10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2003

Commission File Number 0-753

PENN VIRGINIA CORPORATION

Incorporated in VIRGINIA I.R.S. Employer Identification Number 23-1184320

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:

Title of Each Class	Name of Exchange on which registered
Common Stock, $6.25 Par Value	New York Stock Exchange

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

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE:

	Part Into Which Incorporated
(1) Proxy Statement for Annual Shareholders Meeting on May 4, 2004	Part III

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

Part I
1.	Business	1
2.	Properties	13
3.	Legal Proceedings	18
4.	Submission of Matters to a Vote of Security Holders	18
Part II
5.	Market for the Registrant’s Common Stock and Related Shareholder Matters	19
6.	Selected Financial Data	19
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
7A.	Quantitative and Qualitative Disclosures about Market Risk	46
8.	Financial Statements and Supplementary Data	49
9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure	90
9A.	Controls and Procedures	90
Part III
10.	Directors and Executive Officers of the Registrant	91
11.	Executive Compensation	91
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	91
13.	Certain Relationships and Related Transactions	91
14.	Principal Accountant Fees and Services	91
Part IV
15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	92

PART I

Item 1—Business

General

Penn Virginia Corporation (“Penn Virginia” or the “Company”) is a Virginia corporation founded in 1882. We are engaged in the exploration, development and production of crude oil and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States. We also collect royalties on various oil and gas properties in which we own a mineral fee interest. At December 31, 2003, we had proved reserves of approximately 6.6 million barrels of oil and condensate and 283 billion cubic feet (“Bcf”) of natural gas, or 323 billion cubic feet equivalent (“Bcfe”).

Until October 30, 2001, we also engaged directly in the leasing and management of coal properties in the central Appalachian region of the United States. In September 2001, we transferred our coal properties and related assets and liabilities to Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a newly formed Delaware limited partnership. On October 30, 2001, the Partnership completed its initial public offering (“IPO”) of approximately 7.5 million common units at $21.00 per unit, which are traded on the New York Stock Exchange under the symbol PVR. At December 31, 2003, the Partnership owned approximately 588 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. The Partnership does not operate any mines, but has leased its reserves under 53 leases to 29 different operators who mine coal at 54 mines in exchange for royalty payments to PVR. In managing its properties, PVR actively works with its lessees to develop efficient methods to exploit reserves and to maximize production from properties. Additionally, the Partnership provides fee-based coal preparation and transportation facilities to some of its lessees to generate coal service revenues. The Partnership also generates revenues from the sale of standing timber on its properties. The Partnership owned approximately 166 million board feet (“MMbf”) of timber at December 31, 2003.

Our wholly owned subsidiary, Penn Virginia Resource GP, LLC, a Delaware limited liability company, serves as general partner of the Partnership. As of December 31, 2003, we owned approximately 45 percent of the Partnership, consisting of a two percent general partner interest and 43 percent limited partner interest. As part of our ownership of PVR’s general partner, we also own the rights, referred to as “incentive distribution rights”, to receive an increasing percentage of the Partnership’s quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. See Item 1—Business—Corporate and Other for more information on incentive distribution rights.

Financial Information

We operate in two primary business segments. We are in the crude oil and natural gas exploration and production business and, through our interests in PVR, we are in the coal royalty and land management business. For financial statement purposes, the assets, liabilities and earnings of PVR are included in our consolidated financial statements, with the public unitholders’ ownership interest reflected as a minority interest. See Note 20. Segment Information of the Notes to the Consolidated Financial Statements for financial information concerning our business segments.

Oil and Gas Operations

General

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

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

Transportation

The majority of our natural gas production is transported to market on five major pipeline or transmission systems. NiSource Inc., Dominion Transmission, Inc., Duke Energy Corporation, Exxon Mobil Corporation and Crosstex Energy Services LTD transported 21 percent, 20 percent, 19 percent, 12 percent and 8 percent, respectively, of our 2003 natural gas production. The remainder was divided among several pipeline companies in Texas, Louisiana and West Virginia. In almost all cases, our natural gas is sold at interconnects with transmission pipelines. For additional information, see Item 1—Risks Associated with Business Activities—Oil and Gas—Transportation.

Marketing and Hedging

We generally sell our natural gas using spot market and short-term fixed price physical contracts. For the year ended December 31, 2003, three customers of the oil and gas segment, Dominion Transmission, Inc., El Paso Corporation and Duke Energy Corporation accounted for approximately 19 percent, 13 percent and 12 percent, respectively, of our total revenues. From time to time, we enter into commodity derivative contracts or fixed price physical contracts to mitigate the risk associated with the volatility of natural gas prices. Recently, we have utilized swaps and costless collars in connection with our hedging activities. Gains and losses from hedging activities are included in revenues when the hedged production is sold. We recognized a loss of $6.1 million on settled hedging activities in 2003, a loss of $1.1 million in 2002 and a gain of $1.9 million in 2001. In 2003, we hedged approximately 45 percent of our natural gas production at an average NYMEX Henry Hub floor price of $3.64 per MMbtu and a ceiling price of $5.61 per MMbtu for costless collars, and an average $4.70 per MMbtu for swaps. For crude oil, we hedged approximately 26 percent of our 2003 crude oil production at an average floor price of $23.00 per barrel and a ceiling price of $28.75 per barrel for costless collars, and an average $26.82 per barrel for swaps. See Item 7A.— Quantitative and Qualitative Disclosures about Market Risk for information about our price risk management positions for 2004 and 2005.

Coal Royalty and Land Management Operations

General

At December 31, 2003, the Partnership properties contained approximately 588 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. The Partnership earns coal royalty revenues, based on long-term lease agreements, from 29 coal mining operators actively mining under 53 separate leases at 54 mines. Approximately 72 percent of PVR’s 2003 coal royalty revenues and 99 percent of its 2002 coal royalty revenues were based on the higher of a percentage of gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. The balance of PVR’s 2003 and 2002 coal royalty revenues was based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. The Partnership does not operate coal mines. The Partnership provides fee-based coal preparation and transportation facilities to some of its lessees to enhance their production levels and generate additional coal service revenues.

The Partnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. The Partnership owned approximately 166 million board feet of standing saw timber at December 31, 2003. The Partnership’s timber inventory only includes timber that can be harvested and is greater than 12 inches in diameter.

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

Coal Royalties

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

Timber Sales

The Partnership harvests timber in advance of lessee mining to prevent loss of the resource. Timber is sold as individual parcels in competitive bid sales or on a contract basis, where PVR pays independent contractors to harvest timber while PVR directly markets the product. The Partnership sold approximately 5.3 MMbf in 2003, compared with 8.3 MMbf in 2002.

Coal Services

The Partnership generates coal service revenues from fees charged to lessees for use of the Partnership’s coal preparation and transportation facilities. The majority of these fees have been generated by the Partnership’s unit train loadout facility located on its Wise property, which was completed in April 1999 at a cost of $5.2 million. This facility accommodates up to 108-car unit trains, which can be loaded in approximately four hours. Lessees utilize the unit train loadout facility to reduce delivery costs incurred by their customers. The Partnership recognized $2.1 million in coal service revenues in 2003, compared to $1.7 million in 2002. Such amounts are reported as other revenues in the Consolidated Statements of Income included herein.

Corporate and Other

Partnership Distributions

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

We are entitled, through our wholly owned subsidiaries, to receive certain cash distributions payable with respect to the subordinated and common units of PVR held by such subsidiaries as well as certain cash distributions payable with respect to incentive distribution rights held by our general partner subsidiary. The Company received distributions from PVR of $16.8 million and $14.9 million in 2003 and 2002, respectively.

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

If for any quarter:

• PVR has distributed available cash from operating surplus to its common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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• PVR has distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

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:

• First, 98 percent to all unitholders, and 2 percent to the general partner, until each unitholder has received a total of $0.55 per unit for that quarter;

• Second, 85 percent to all unitholders, and 15 percent to the general partner, until each unitholder has received a total of $0.65 per unit for that quarter;

• Third, 75 percent to all unitholders, and 25 percent to the general partner, until each unitholder has received a total of $0.75 per unit for that quarter; and

• Thereafter, 50 percent to all unitholders and 50 percent to the general partner.

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

Investments

During 2001, we sold 3,307,200 shares of Norfolk Southern Corporation (NYSE: NSC) common stock. The shares were sold in open market transactions on the New York Stock Exchange at an average price of $17.39 per share. Our 3,307,200 common shares of Norfolk Southern Corporation generated dividends of $0.2 million in 2001. We received a quarterly dividend of $0.06 per share in 2001. We had no available-for-sale securities at December 31, 2003 and 2002. See Note 5. Investments and Dividend Income of the Notes to the Consolidated Financial Statements for additional information.

Risks Associated with Business Activities

Oil and Gas

Competition

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

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Price Volatility

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

Drilling and Operating Risks

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

Transportation

We transport our natural gas to market on various gathering and transmission pipeline systems owned by third parties. Gathering fees are primarily paid by the purchaser of the natural gas. The majority of natural gas sales contracts are one year or less in duration and contain relevant monthly index pricing provisions. Interruptible gathering rates have increased over the years as pipelines have implemented the mandatory unbundling of gathering services (Federal Energy Regulatory Commission Order 636) from other transportation services. In 2003, NiSource Inc. gathered and transported approximately 21 percent of our natural gas, Dominion Transmission, Inc. approximately 20 percent, Duke Energy Corporation approximately 19 percent, Exxon Mobil Corporation approximately 12 percent, and Crosstex Energy Services LTD approximately 8 percent, with the remainder divided among several pipeline companies in Texas, Louisiana and West Virginia. Production could be adversely affected by disruptions or curtailments of the operations of pipelines for maintenance or replacement as transportation options are limited.

Regulation

State Regulatory Matters. Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas. These provisions include the permitting for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells, and to limit the number of wells or the locations at which we can drill.

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

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

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

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

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Coal Royalty and Land Management

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

Competition

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

Operating Risks

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

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

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

Certain Regulatory and Legal Matters.

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

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

The Clean Air Act also imposes standards on sources of hazardous air pollutants. These standards have not yet been extended to coal mining operations, but in January 2004, EPA proposed regulations to control emissions of mercury, a hazardous air pollutant from power plants that combust coal, as well as nitrogen oxides and sulfur dioxide, which are also power plant pollutants, Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.

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

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

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

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

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

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

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

9

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

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

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

Employees

We had 116 employees at December 31, 2003, including 32 employees who directly provide services for PVR through its general partner. We consider our relations with our employees to be good.

Available Information

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

Executive Officers of the Company

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

Name	Age	Position with the Company
A. James Dearlove	56	President and Chief Executive Officer
Frank A. Pici	48	Executive Vice President and Chief Financial Officer
H. Baird Whitehead	53	Executive Vice President
Keith D. Horton	50	Executive Vice President
Nancy M. Snyder	50	Senior Vice President, General Counsel and Secretary
Dana G Wright	51	Vice President and Controller
Ronald K. Page	53	Vice President, Corporate Development

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

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

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

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

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

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

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

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

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

Bbl— means a standard barrel of 42 U.S. gallons liquid volume

Bcf— means one billion cubic feet

Bcfe— means one billion cubic feet equivalent with one barrel of oil or condensate converted to six thousand cubic feet of natural gas based on the estimated relative energy content

Gross— acre or well means an acre or well in which a working interest is owned

Mbbl— means one thousand barrels

Mbf— means one thousand board feet

Mcf— means one thousand cubic feet

MMbf— means one million board feet

MMbtu— means one million British thermal units

MMcf— means one million cubic feet

Net— acres or wells is determined by multiplying the gross acres or wells by the owned working interest in those gross acres or wells

NYMEX— New York Mercantile Exchange

Present value of proved reserves— means the present value (discounted at 10%) of estimated future cash flows from proved oil and natural gas reserves, as estimated by our independent engineers, reduced by additional estimated future operating expenses, development expenditures and abandonment costs (net of salvage value) associated therewith (before income taxes).

Probable Coal Reserves— means those reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Proved Reserves— means those 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 oil and gas reservoirs under existing economic and operating conditions.

Proven Coal Reserves— means those reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes;

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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.

Standardized Measure— means present value of proved reserves further reduced by the present value (discounted at 10%) of estimated future income taxes on cash flows.

Working Interest— means a cost-bearing interest under an oil and gas lease that gives the holder the right to develop and produce the minerals under the lease.

Item 2—Properties

Facilities

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

Title to Properties

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

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

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

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Information Regarding Oil and Gas Properties

Production and Pricing

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

	2003			2002			2001
Production
Oil and condensate (Mbbls)*		625			349			164
Natural gas (MMcf)*		20,094			18,697			13,130
Total production (MMcfe)*		23,844			20,791			14,114
Average sales price
Oil and condensate ($/Bbl)	$	26.91		$	23.63		$	22.94
Natural gas ($/Mcf)	$	5.31		$	3.35		$	4.06
Production cost ($/Mcfe)
Lease operating expense	$	0.51		$	0.45		$	0.40
Taxes other than income		0.40			0.27			0.31
General and administrative expense		0.33			0.40			0.38
Total production cost	$	1.24		$	1.12		$	1.09
Hedging Summary
Natural gas prices ($/Mcf):
Actual price received for production	$	5.59		$	3.39		$	3.92
Effect of derivative hedging activities		(0.28	)		(0.04	)		0.14
Average realized price	$	5.31		$	3.35		$	4.06
Crude oil prices ($/Bbl):
Actual price received for production	$	27.77		$	24.39		$	22.45
Effect of derivative hedging activities		(0.86	)		(0.76	)		0.49
Average realized price	$	26.91		$	23.63		$	22.94

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

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Proved Reserves

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

	Oil and Condensate	Natural Gas	Natural Gas Equivalents	Pre-tax SEC PV10 Value		Year-end Prices Used
	(MMbbls)	(Bcf)	(Bcfe)	($ millions)		$ / Bbl		$ /MMbtu
2003
Developed	3.3	231	251	$	570
Undeveloped	3.3	52	72		126
Total	6.6	283	323	$	696	$	32.52	$	5.97
2002
Developed	2.9	199	216	$	404
Undeveloped	2.5	42	57		77
Total	5.4	241	273	$	481	$	31.13	$	4.74
2001
Developed	2.2	183	196	$	202
Undeveloped	1.7	46	56		40
Total	3.9	229	252	$	242	$	20.40	$	2.65

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

In accordance with the Securities and Exchange Commission’s guidelines, the engineers’ estimates of future net revenues from our properties and the pre-tax SEC PV10 value thereof are made using oil and natural gas sales prices in effect as of December 31, 2003. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Prices for oil and gas are subject to substantial seasonal fluctuations as well as fluctuations resulting from numerous other factors. See Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

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that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, neither the pre-tax nor after-tax SEC PV10 value amounts shown above should be

construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in production prices.

Acreage

The following table sets forth our developed and undeveloped acreage at December 31, 2003. The acreage is located in the eastern and Gulf Coast areas of the United States.

	Gross Acreage	Net Acreage
	(in thousands)
Developed	669	531
Undeveloped	408	231
Total	1,077	762

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.

	2003		2002		2001
	Gross	Net	Gross	Net	Gross	Net
Development
Productive	161	117.0	87	58.4	125	96.1
Non-productive	1	1.0	3	2.5	5	5.0
	162	118.0	90	60.9	130	101.1
Exploratory
Productive	5	1.2	3	3.0	19	14.5
Non-productive	3	2.9	3	1.6	5	3.5
Under evaluation	10	10.0	—	—	—	—
	18	14.1	6	4.6	24	18.0
Total	180	132.1	96	65.5	154	119.1

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

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Productive Wells

The number of productive oil and gas wells in which we had a working interest at December 31, 2003 is set forth below. Productive wells are producing wells or wells capable of commercial production.

Operated Wells		Non-Operated Wells		Total
Gross	Net	Gross	Net	Gross	Net
794	769.7	493	77.7	1,287	847.4

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

Information Regarding Coal Royalty and Land Management Properties

The Partnership’s coal reserves at December 31, 2003 covered 241,000 acres, including fee and leased acreage, in Virginia, West Virginia, New Mexico and eastern Kentucky. The coal reserves are in various surface and underground seams. As of December 31, 2003, the Partnership had approximately 588 million tons of proven and probable coal reserves, which are found in the following six separate properties:

• the Wise property, located in Wise and Lee Counties, Virginia and Letcher and Harlan Counties, Kentucky;

• the Coal River property, located in Boone, Fayette, Kanawha, Lincoln and Raleigh Counties, West Virginia;

• the New Mexico property, located in McKinley County, New Mexico;

• the Northern Appalachia property, located in Barbour, Harrison, Lewis, Monongalia and Upshur Counties, West Virginia;

• the Spruce Laurel property, located in Boone and Logan Counties, West Virginia; and

• the Buchanan property, located in Buchanan County, Virginia.

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

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

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

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

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

	Production Year Ended December 31,			Proven and Probable Reserves at December 31, 2003
Property	2003	2002	2001	Under- ground	Surface	Total
	(tons in millions)
Wise	9.3	8.9	9.0	186.5	25.2	211.7
Coal River	3.9	2.5	4.0	128.0	73.2	201.2
New Mexico	6.3	0.2	—	—	73.3	73.3
Northern Appalachia	5.1	0.5	—	46.5	2.5	49.0
Spruce Laurel	1.5	1.8	1.7	35.4	15.9	51.3
Buchanan	0.4	0.4	0.6	1.6	0.1	1.7
Total	26.5	14.3	15.3	398.0	190.2	588.2

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

	Owned
Property	Surface and Mineral Interests	Mineral Interests Only	Leased	Total
	(tons in millions)
Wise	203.4	8.3	0.0	211.7
Coal River	145.7	20.3	35.2	201.2
New Mexico	0.0	69.4	3.9	73.3
Northern Appalachia	0.0	49.0	0.0	49.0
Spruce Laurel	47.8	0.0	3.5	51.3
Buchanan	0.0	0.6	1.1	1.7
Total	396.9	147.6	43.7	588.2

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

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

Item 3—Legal Proceedings

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

Item 4—Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders during the fourth quarter of 2003.

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PART II

Item 5—Market for the Company’s Common Stock and Related Stockholder Matters

Common Stock Market Prices And Dividends

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

	2003						2002
	Sales Price				Cash Dividends Paid		Sales Price				Cash Dividends Paid
	High		Low				High		Low
Quarter Ended:
March 31	$	39.90	$	34.09	$	0.225	$	40.30	$	26.03	$	0.225
June 30	$	45.05	$	37.40	$	0.225	$	42.00	$	32.15	$	0.225
September 30	$	45.65	$	39.65	$	0.225	$	39.25	$	29.50	$	0.225
December 31	$	57.75	$	44.05	$	0.225	$	37.25	$	30.15	$	0.225

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

Item 6—Selected Financial Data

Five Year Selected Financial Data

	2003		2002		2001		2000		1999
	(in thousands except share data)
Year Ended December 31,
Revenues	$	181,284	$	110,957	$	96,571	$	105,998	$	47,697
Operating income(a,b)	$	62,101	$	30,791	$	1,563	$	65,684	$	20,715
Net income(c)	$	28,522	$	12,104	$	34,337	$	39,265	$	14,504
Per common share:
Net income, basic	$	3.17	$	1.35	$	3.92	$	4.76	$	1.73
Net income, diluted	$	3.15	$	1.34	$	3.86	$	4.69	$	1.71
Dividends paid	$	0.90	$	0.90	$	0.90	$	0.90	$	0.90
Weighted average shares outstanding, basic		8,988		8,930		8,770		8,241		8,406
Weighted average shares outstanding, diluted		9,056		8,974		8,896		8,371		8,480
Total assets(d)	$	683,733	$	586,292	$	457,102	$	268,766	$	274,011
Long-term debt(e)	$	154,286	$	106,887	$	46,887	$	47,500	$	78,475
Minority interest in PVR	$	190,508	$	192,770	$	144,039	$	—	$	—
Shareholders’ equity	$	211,648	$	187,956	$	185,454	$	171,162	$	154,343

(a) Certain reclassifications have been made to conform to the current year presentation.

(b) Operating income in 2003, 2002 and 2001 included a $0.4 million, $0.8 million and $33.6 million impairment of oil and gas properties, respectively. Operating income in 2000 included a $23.9 million gain on the sale of certain oil and gas properties.

(c) Net income in 2001 included a $54.7 million ($35.6 million after tax) gain on the sale of Norfolk Southern Corporation common stock.

(d) Total assets reflected the acquisition of coal reserves from Peabody in December 2002 for $130.5 million. Total assets in 2001 included Gulf Coast oil and gas properties purchased in July 2001 for $157.1 million.

(e) Long-term debt in 2003 included outstanding borrowing of $64 million against our revolving credit facility. Also included was PVR borrowing of $90.3 million consisting of $2.5 million borrowed against its $100 million revolving credit facility and $87.8 million of senior unsecured notes. Long-term debt in 2002 included borrowing of $16 million against our revolving credit facility. Also included was PVR’s borrowing of $90.9 million consisting of $47.5 million borrowed against its $50 million revolving credit facility and $43.3 million of a fully-drawn term loan. Long-term debt in 2001 included $43.4 of long-term debt of PVR that was secured by $43.4 million of U.S. Treasuries also held by PVR.

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Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Overview

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

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

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

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

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

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

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

2003 Performance—Oil and Gas Segment

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Critical Accounting Policies and Estimates

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

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

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

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

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

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

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

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

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

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

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

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

Acquisitions

Oil and gas

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

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

Coal Royalty and Land Management

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

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

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

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Results of Operations

Selected Financial Data—Consolidated

	2003		2002		2001
	(in millions, except share data)
Revenues	$	181.3	$	111.0	$	96.6
Operating costs and expenses	$	119.2	$	80.2	$	95.0
Operating income	$	62.1	$	30.8	$	1.6
Net income	$	28.5	$	12.1	$	34.3
Earnings per share, basic	$	3.17	$	1.35	$	3.92
Earnings per share, diluted	$	3.15	$	1.34	$	3.86
Cash flows provided by operating activities	$	109.7	$	65.8	$	44.2

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

The 2001 results included a pre-tax gain on the sale of securities of approximately $54.7 million ($35.5 million after tax). This amount is included in “Corporate and Other”. Also included in the 2001 results was the impairment of certain oil and gas properties, for which we recorded a $33.6 million ($21.8 million after tax) impairment charge. This amount was included in the oil and gas segment’s contribution to net income.

Consolidated Net Income

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

Oil and Gas Segment

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

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Selected Financial and Operating Data—Oil and Gas

	2003			2002			2001
	(in thousands, except as noted)
Revenues
Oil and condensate	$	16,816		$	8,246		$	3,762
Natural gas		106,615			62,552			53,263
Other		1,391			714			753
Total Revenues	$	124,822		$	71,512		$	57,778
Expenses
Lease operating		12,115			9,253			5,631
Exploration		15,503			7,549			11,514
Taxes other than income		9,515			5,618			4,439
General and administrative		7,804			8,381			5,330
Operating expenses before non-cash charges		44,937			30,801			26,914
Depreciation, depletion and amortization		33,164			26,336			16,418
Impairment of properties		406			796			33,583
Total Operating Expenses		78,507			57,933			76,915
Operating Income (Loss)	$	46,315		$	13,579		$	(19,137	)
Production
Oil and condensate (Mbbls) *		625			349			164
Natural gas (MMcf) *		20,094			18,697			13,130
Total production (MMcfe) *		23,844			20,791			14,114
Prices
Oil and condensate ($/Bbl)	$	26.91		$	23.63		$	22.94
Natural gas ($/Mcf)	$	5.31		$	3.35		$	4.06
Production cost ($/Mcfe)
Lease operating expense	$	0.51		$	0.45		$	0.40
Taxes other than income		0.40			0.27			0.31
General and administrative expense		0.33			0.40			0.38
Total production cost	$	1.24		$	1.12		$	1.09
Hedging Summary
Natural gas prices ($/Mcf):
Actual price received for production	$	5.59		$	3.39		$	3.92
Effect of hedging activities		(0.28	)		(0.04	)		0.14
Average realized price	$	5.31		$	3.35		$	4.06
Crude oil prices ($/Bbl):
Actual price received for production	$	27.77		$	24.39		$	22.45
Effect of hedging activities		(0.86	)		(0.76	)		0.49
Average realized price	$	26.91		$	23.63		$	22.94

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

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

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

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

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

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

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

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

	2003		2002
Seismic	$	8,713	$	4,892
Dry hole costs		5,186		1,357
Leasehold amortization		802		899
Other		802		401
Total	$	15,503	$	7,549

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

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

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

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

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

Crude oil and natural gas production increased to 20.8 Bcfe in 2002, a 47 percent increase over 14.1 Bcfe in 2001. The increase was primarily due to the inclusion of a full year of production from the Gulf Coast oil and gas properties acquired in July 2001 and development drilling success in connection with our Gulf Coast, Mississippi and Appalachian assets. Approximately 90 percent of our 2002 production was natural gas.

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

Due to the volatility of crude oil and natural gas prices, we sometimes hedge the price received for sales volumes through the use of swaps and costless collars. Gains and losses from hedging activities are included in revenues when the hedged production occurs. We recognized a loss on settled hedging activities of $1.1 million in 2002 and a gain of $1.9 million in 2001.

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

Exploration expenses for the years ended December 31, 2002 and 2001 consisted of the following (in thousands):

	2002		2001
Seismic	$	4,892	$	2,381
Dry hole costs		1,357		5,973
Leasehold amortization		899		2,980
Other		401		180
Total	$	7,549	$	11,514

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

Taxes other than income taxes increased from $4.4 million in 2001 to $5.6 million in 2002. The increased taxes were a result of the higher production and revenue levels in 2002.

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

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

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Coal Royalty and Land Management Segment (PVR)

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

The Partnership enters into leases with various third-party operators for the right to mine coal reserves on the Partnership’s properties in exchange for royalty payments. Approximately 72 percent of the Partnership’s 2003 coal royalty revenues and 99 percent of its 2002 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. The balance of the Partnership’s 2003 and 2002 coal royalty revenues were based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. In addition to coal royalty revenues, the Partnership generates coal service revenues from fees charged to lessees for the use of coal preparation and transportation facilities. The Partnership also generates revenues from the sale of timber on its properties.

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

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Selected Financial and Operating Data—Coal Royalty and Land Management

	2003			2002			2001
	(in thousands, except as noted)
Revenues
Coal royalties	$	50,312		$	31,358		$	32,365
Timber		1,020			1,640			1,732
Coal services		2,111			1,704			1,660
Other		2,199			3,906			1,756
Total Revenues		55,642			38,608			37,513
Expenses
Operating		5,491			3,807			3,812
General and administrative		7,013			6,419			5,459
Operating Expenses Before Non-cash Charges		12,504			10,226			9,271
Depreciation, depletion and amortization		16,578			3,955			3,084
Total Operating Expenses		29,082			14,181			12,355
Operating Income		26,560			24,427			25,158
Interest expense		(4,986	)		(1,758	)		(269	)
Interest income and other		1,223			2,017			1,388
Income from operations before minority interest, income taxes and cumulative effect of change in accounting principle		22,797			24,686			26,277
Minority interest		(12,510	)		(11,896	)		(1,763	)
Contribution to income from operations before income taxes and cumulative effect of change in accounting principle		10,287			12,790			24,514
Production
Royalty coal tons produced by lessees (thousands)		26,463			14,281			15,306
Timber sales (Mbf)		5,250			8,345			8,741
Prices
Royalty per ton	$	1.90		$	2.20		$	2.11
Timber sales price per Mbf	$	179		$	187		$	168

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

Revenues. Coal royalty and land management segment revenues for the year ended December 31, 2003 were $55.6 million compared to $38.6 million for the year ended December 31, 2002, an increase of $17 million, or 44 percent.

Coal royalty revenues for the year ended December 31, 2003 were $50.3 million compared to $31.4 million for the year ended December 31, 2001, an increase of $18.9 million, or 60 percent. Average gross royalties per ton decreased from $2.20 in 2002 to $1.90 in 2003 as a result of the lower royalty rates attributable to the Peabody Acquisition in December 2002. Over these same periods, production increased by 12.2 million tons, or 85 percent, from 14.3 million tons to 26.5 millions tons. These variances were primarily due to the following factors:

• Production increased on the New Mexico property by 6.1 million tons, which resulted in an increase in revenues of $9.1 million. The increase was a direct result of the Peabody Acquisition in December 2002.

• Production increased on the Northern Appalachia property by 4.7 million tons, which resulted in an increase in revenues of $5.5 million. The increase was a direct result of the Peabody Acquisition in December 2002 and the Upshur Acquisition in August 2002.

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• Production on the Coal River property increased by 1.4 million tons, which resulted in an increase in revenues of $4.2 million. Of these increases, 0.6 million tons, or $1.7 million, resulted from the addition of a mine operator and a new mine by one lessee, 0.6 million tons, or $1.4 million, resulted from an adjacent property lessee mining over on to PVR’s property and the balance of the increase was primarily due to one lessee beginning operations in late 2002 and reaching full production in 2003 and start-up operations on the West Coal River property. Additional production from two lessees with high royalty rates coupled with increased demand in the region resulted in a 15 percent increase in the average gross royalty per ton on the Coal River property from $2.11 per ton in 2002 to $2.42 per ton in 2003.

• Production on the Wise property increased by 0.4 million tons, which resulted in an increase in revenues of $1.0 million. These increases were primarily due to additional mining equipment being added by two lessees and another lessee beginning operations in late 2002 and reaching full production in 2003.

• Production on the Spruce Laurel property decreased by 0.3 million tons, which resulted in a decrease in revenues of $0.7 million. These decreases were the result of the depletion of two mines in 2003.

• Production on the Buchanan property decreased by 0.1 million tons, which resulted in a $0.2 million decrease in revenues as this property continues to approach the end of its reserve life.

Timber revenues decreased to $1.0 million for the year ended December 31, 2003 from $1.6 million for the year ended December 31, 2002, a decrease of $0.6 million, or 38 percent. Volume sold declined 3.1 MMbf, or 37 percent, to 5.3 MMbf in 2003, compared to 8.3 MMbf for 2002. The decrease in volume sold was due to the timing of parcel sales.

Coal services revenues for the year ended December 31, 2003 were $2.1 million compared to $1.7 million for the year ended December 31, 2002, an increase of $0.4 million, or 24 percent. The increase was a direct result of our West Coal River preparation and transportation facility beginning operations in July 2003 and the addition of one of PVR’s three modular preparation plants.

Other revenues were $2.2 million for the year ended December 31, 2003 compared to $3.9 million for the year ended December 31, 2002, a decrease of $1.7 million, or 44 percent. The decrease was primarily due to reduction of minimum rental revenues. The decrease in minimum rental revenues was due to a lessee rejecting PVR’s lease in bankruptcy in 2002; consequently, $0.8 million of deferred revenues from this respective lessee was recognized as income in 2002. Additionally, a railroad rebate received for the use of a specific portion of railroad by one of PVR’s lessees was paid in full in the fourth quarter of 2002.

Operating expenses. Operating expenses, which include both lease operating expenses and taxes other than income, increased to $5.5 million for the year ended December 31, 2003 compared to $3.8 million for the year ended December 31, 2002, representing a 44 percent increase. Lease operating expenses were $4.2 million for the year ended December 31, 2003 compared to $2.9 million for the year ended December 31, 2002, an increase of $1.3 million, or 45 percent. The increase was primarily due to maintenance costs for idled mines on the West Coal River property. PVR leased its West Coal River property in May 2003, and the on-going maintenance costs were assumed by the new lessee as of that date. The remainder of the variance is primarily attributable to increased production by lessees on subleased properties. Aggregate production from subleased properties increased to 2.0 million tons for the year ended December 31, 2003 from 1.8 million tons for the year ended December 31, 2002, an increase of 0.2 million tons, or 11 percent. Taxes other than income for the year ended December 31, 2003 were $1.3 million compared to $0.9 million for the year ended December 31, 2002, an increase of $0.4 million, or 40 percent. The variance was attributable to increased property taxes as a result of assuming the property tax obligation on the West Coal River property upon re-acquiring the lease from the bankrupt lessee. The West Coal River property was leased in May 2003, and the on-going property taxes were assumed by the new lessee as of that date.

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G&A expenses increased to $7.0 million for the year ended December 31, 2003 compared to $6.4 million for the year ended December 31, 2002, representing a 9 percent increase. The increase was primarily attributable to increased payroll, an increase in insurance premiums and additional recurring expenses associated with the Peabody Acquisition and costs related to the secondary offering of units for Peabody.

DD&A expense for the year ended December 31, 2003 was $16.6 million compared to $4.0 million for the year ended December 31, 2002, an increase of $12.6 million, or 319 percent. The increase was a result of higher depletion rates caused by higher cost bases relative to reserves added as well as increased production, both of which related primarily to the Peabody and Upshur Acquisitions completed in the last half of 2002.

Interest expense. Interest expense was $5.0 million for the year ended December 31, 2003 compared with $1.8 million for the same period in 2002, an increase of $3.2 million, or 184 percent. The higher interest expense was primarily due to the increase in PVR’s long-term borrowings in connection with the Peabody Acquisition in December 2002.

Interest income. Interest income was $1.2 million for the year ended December 31, 2003 compared with $2.0 million for the year ended December 31, 2002, a decrease of $0.8 million, or 39 percent. The decrease was primarily due to the liquidation of $43.4 million of U.S. Treasury notes in the last half of 2002.

Minority interest. Minority interest was $12.5 million for the year ended December 31, 2003 compared with $11.9 million for the year ended December 31, 2002, an increase of $0.6 million, or 5 percent. The increase was primarily due to an increase in the public’s ownership percentage in the Partnership, offset by a decrease in the Partnership’s net income for the comparable years.

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

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

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

Timber revenues decreased to $1.6 million for the year ended December 31, 2002 from $1.7 million for the year ended December 31, 2001, a decrease of $0.1 million, or five percent. Volume sold declined 0.4 MMbf, or five percent, to 8.3 MMbf in 2002, compared to 8.7 MMbf for 2001.

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

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

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

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

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

Interest Expense. Interest expense was $1.8 million for the year ended December 31, 2002 compared with $0.3 million for the same period in 2001, an increase of $1.5 million. The increase was primarily due to Partnership’s long-term borrowings in connection with its creation in October 2001. See additional discussion of the Partnership’s credit facilities below in Capital Resources and Liquidity.

Interest Income. Interest income was $2.0 million for the year ended December 31, 2002 compared with $1.4 million for the year ended December 31, 2001, an increase of $0.6 million. The increase in interest income was due to the U.S. Treasury Notes purchased by the Partnership in conjunction with the closing of its initial public offering in October 2001, and securing its own credit facility.

Minority interest. Minority interest was $11.9 million for the year ended December 31, 2002 compared with $1.8 million for the year ended December 31, 2001, an increase of $10.1 million. The minority interest share of the Partnership’s net income was only attributable to earnings subsequent to its creation in October 2001.

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Corporate and Other

The Corporate and Other segment primarily consists of oversight and administrative functions.

Selected Financial and Operating Data—Corporate and Other

	2003			2002			2001
	(in thousands, except as noted)
Revenues
Other	$	820		$	837		$	1,280
Total Revenues	$	820		$	837		$	1,280
Expenses
Lease operating		600			607			601
Exploration		—			166			174
Taxes other than income		551			291			378
General and administrative		10,076			6,640			4,508
Operating expenses before non-cash charges		11,227			7,704			5,661
Depreciation, depletion and amortization		367			348			77
Total Operating Expenses		11,594			8,052			5,738
Operating Loss	$	(10,774	)	$	(7,215	)	$	(4,458	)
Interest expense		(318	)		(358	)		(2,184	)
Interest income and other		8			15			188
Gain on sale of securities		—			—			54,688
Contribution to income from operations before income taxes and cumulative effect of change in accounting principle	$	(11,084	)	$	(7,558	)	$	48,234

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

G&A expenses increased to $10.1 million in 2003 from $6.6 million in 2002. The $3.5 million increase was primarily attributable to consulting and advisory services related to the consideration of various shareholder proposals, higher insurance premiums and a general increase in staffing levels.

In conjunction with the acquisition of oil and gas properties during 2001, considerable unproved leasehold costs were recorded. Interest costs associated with non-producing leases were capitalized during 2003 and 2002 as activities were in progress to bring projects to their intended use. We capitalized $2.0 million and $1.0 million of interest costs in 2003 and 2002, respectively. Interest expense not capitalized in the Corporate and Other segment related to amortization of debt issuance costs.

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

Other revenue decreased to $0.8 million in 2002 from $1.3 million in 2001. The $0.5 million decrease was due to the absence of dividend and other income in 2002, which existed in 2001. Dividends on the Norfolk Southern Corporation stock were a source of income to the Company for part of the 2001 year. The balance of other revenue during these years consisted primarily of railcar rental revenues.

G&A expenses increased to $6.6 million in 2002 from $4.5 million in 2001. The $2.1 million increase was primarily attributable to consulting and advisory services and legal fees related to the consideration of various shareholder proposals.

In conjunction with the acquisition of oil and gas properties during 2001, considerable unproved leasehold costs were recorded. Interest costs associated with non-producing leases were capitalized during 2002 and 2001 as activities were in progress to bring projects to their intended use. We capitalized $1.0 million and $1.1 million of interest costs in 2002 and 2001, respectively. Interest expense reflected in the Corporate and Other segment during 2002 and 2001 related to amortization of debt issuance costs.

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In April 2001, we sold all of our 3.3 million common share position in Norfolk Southern Corporation and other stocks classified as available-for-sale. The Norfolk Southern Corporation shares were sold at an average price of $17.39 per share. Proceeds from the sales, net of commissions, total approximately $57.4 million. We recorded a pre-tax gain on sale of securities of $54.7 million.

Reserves

Oil and Gas Reserves

Our total proved reserves at December 31, 2003 were 323 Bcfe, compared with 273 Bcfe at December 31, 2002. At December 31, 2003, proved developed reserves comprised 78 percent of our total proved reserves, compared with 79 percent at December 31, 2002. We had 152 net proved undeveloped drilling locations at December 31, 2003, compared with 128 net proved undeveloped drilling locations at December 31, 2002.

	2003			2002			2001
Proved reserves
Oil and condensate (MMbbls)		6.6			5.4			3.9
Natural gas (Bcf)		283.1			241.3			229.3
Total proved reserves (Bcfe)		322.9			273.4			252.8
Proved developed reserves
Oil and condensate (MMbbls)		3.3			2.9			2.2
Natural gas (Bcf)		231.0			198.7			183.1
Total proved developed reserves (Bcfe)		251.0			216.4			196.4
Finding and development cost (a), ($/Mcfe)
Current year	$	1.96		$	1.34		$	3.26
Three year weighted average	$	2.10		$	1.81		$	2.66
Reserve replacement cost (b), ($/Mcfe)
Current year	$	1.81		$	1.32		$	2.22
Three year weighted average	$	1.89		$	1.60		$	1.70
Reserve replacement percentage (c), ($/Mcfe)
Current year		308	%		206	%		660	%
Three year weighted average		357	%		432	%		544	%

Finding and development cost, reserve replacement cost and reserve replacement percentage are not measures presented in accordance with GAAP and are not intended to be used in lieu of GAAP presentation. These measures are commonly used within the industry as a measurement to determine the performance of a company’s oil and gas activities.

(a) Finding and development cost is calculated by dividing 1) costs incurred in certain oil and gas activities (exclusive of asset retirement obligation) less proved property acquisitions, by 2) reserve extensions, discoveries and other additions and revisions. The 2001 finding and development costs used in this calculation included $62.2 million for unproved property acquisition costs (including the impact of deferred income taxes) related to the purchase of certain Gulf Coast oil and gas properties in the third quarter of 2001. No proved reserves were recorded relative to these unproved property acquisition costs, for which future exploration and development activities will be conducted. Had the unproved property acquisition costs been excluded from the 2001 finding and development cost calculations, 2001 and three year weighted average cost per Mcfe as of December 31, 2001 would have been $1.41 and $1.24, respectively.

(b) Reserve replacement cost is calculated by dividing 1) costs incurred in certain oil and gas activities, including acquisitions, by 2) reserve purchases, extensions, discoveries and other additions and revisions. The 2001 reserve replacement costs used in this calculation included $62.2 million for unproved property acquisition costs described in footnote (a) above. Had the unproved property acquisition costs been excluded from the 2001 reserve replacement cost calculations, 2001 and three year weighted average cost per Mcfe as of December 31, 2001would have been $1.26 and $1.09, respectively.

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(c) Reserve replacement percentage is calculated by dividing 1) reserve purchases, revisions, extensions, discoveries and other additions, by 2) oil and gas production.

Proven and Probable Coal Reserves

The Partnership’s proven and probable coal reserves were 588 million tons at December 31, 2003 compared with 615 million tons at December 31, 2002. Royalties were collected for 26.5 million tons mined on the Partnership’s properties in 2003.

Capital Resources and Liquidity

Prior to 2001, we satisfied our working capital requirements and funded our capital expenditure and dividend payments with cash generated from operations and credit facility borrowings. In 2001, our acquisition of Gulf Coast properties was funded with credit facility borrowings that were subsequently repaid with proceeds from PVR’s initial public offering. Although results are consolidated for financial reporting, the change in ownership structure of PVR has resulted in the Company and PVR operating with independent capital structures. The Company and PVR have separate credit facilities, and neither entity guarantees the debt of the other. Since PVR’s public offering, with the exception of cash distributions received by the Company from PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and, in the case of PVR’s Peabody Acquisition, issuance of new partnership units. We expect that our cash needs and the cash needs of PVR will continue to be met independently of each other with a combination of these funding sources. Below are summarized cash flow statements for 2003 and 2002 consolidating the oil and gas (and corporate) and the coal royalty and land management (PVR) segments.

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For the year ended December 31, 2003 (in thousands)	Oil and Gas & Corporate			Coal Royalty & Land Mgmt (PVR)			Consolidated
Cash flows from operating activities:
Net income contribution	$	22,455		$	6,067		$	28,522
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		55,552			29,673			85,225
Net change in operating assets and liabilities		(9,380	)		5,337			(4,043	)
Net cash provided by operating activities		68,627			41,077			109,704
Cash flows from investing activities:
Additions to property and equipment		(122,891	)		(5,291	)		(128,182	)
Other		800			580			1,380
Net cash used in investing activities		(122,091	)		(4,711	)		(126,802	)
Cash flows from financing activities:
PVA dividends paid		(8,092	)		—			(8,092	)
PVR distributions received/(paid)		16,828			(36,708	)		(19,880	)
PVA debt proceeds, net of repayments		47,948			—			47,948
PVR debt proceeds, net of repayments		—			1,613			1,613
Other		2,001			(1,825	)		176
Net cash provided by (used in) financing activities		58,685			(36,920	)		21,765
Net increase, (decrease) in cash and cash equivalents		5,221			(554	)		4,667
Cash and cash equivalents—beginning of year		3,721			9,620			13,341
Cash and cash equivalents—end of year	$	8,942		$	9,066		$	18,008
For the year ended December 31, 2002 (in thousands)	Oil and Gas & Corporate			Coal Royalty & Land Mgmt (PVR)			Consolidated
Cash flows from operating activities:
Net income (loss) contribution	$	4,028		$	8,076		$	12,104
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		39,533			16,161			55,694
Net change in operating assets and liabilities		(8,115	)		6,105			(2,010	)
Net cash provided by operating activities		35,446			30,342			65,788
Cash flows from investing activities:
Additions to property and equipment		(51,924	)		(92,817	)		(144,741	)
Other		1,420			43,841			45,261
Net cash used in investing activities		(50,504	)		(48,976	)		(99,480	)
Cash flows from financing activities:
PVA dividends paid		(8,040	)		—			(8,040	)
PVR distributions received/(paid)		14,936			(28,723	)		(13,787	)
PVA debt proceeds, net of repayments		11,317			—			11,317
PVR debt proceeds, net of repayments		—			47,500			47,500
Other		(720	)		1,142			422
Net cash provided by financing activities		17,493			19,919			37,412
Net increase in cash and cash equivalents		2,435			1,285			3,720
Cash and cash equivalents—beginning of year		1,286			8,335			9,621
Cash and cash equivalents—end of year	$	3,721		$	9,620		$	13,341

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

Cash flows from Operating Activities

Consolidated net cash provided from operating activities was $109.7 million in 2003, compared with $65.8 million in 2002. The oil and gas and corporate segment’s net cash provided by operations was $68.6 million in 2003 and $35.4 million in 2002. The increase was primarily due to increased prices received for, and higher production of natural gas and crude oil. Cash in excess of working capital needs for both years was used to help fund the respective year’s capital expenditures. Cash provided by operations of the coal royalty and land management segment was $41.1 million in 2003, compared with $30.3 million in 2002. The increase was primarily due to increased production attributable to the Peabody Acquisition in December 2002.

Cash flows from Investing Activities

Consolidated net cash used in investing activities was $126.8 million in 2003, compared with $99.5 million in 2002. During 2003 and 2002, we used cash primarily for capital expenditures for oil and gas development and exploration activities and acquisitions of oil and gas properties. During 2002, PVR acquired approximately 136 million tons of coal reserves in two transactions.

Capital expenditures totaled $138.8 million in 2003, compared with $203.8 million in 2002 and $241.7 million in 2001. The following table sets forth capital expenditures by segment, made during the periods indicated.

	Year ended December 31,
	2003		2002		2001
	(in thousands)
Oil and gas
Development drilling	$	59,551	$	39,014	$	30,123
Exploration drilling		11,931		2,485		11,253
Seismic and other		9,470		5,358		2,561
Lease acquisitions(a)		44,152		6,336		161,631
Field projects		7,770		2,736		1,422
Total		132,874		55,929		206,990
Coal royalty and land management (PVR)
Lease acquisitions(b)		1,361		138,450		32,992
Support equipment and facilities		3,930		9,085		677
Total		5,291		147,535		33,669
Other		621		343		1,074
Total capital expenditures	$	138,786	$	203,807	$	241,733

(a) 2001 amounts include $43.1 million of deferred tax liabilities related to our acquisition of Gulf Coast oil and gas properties.

(b) 2002 amounts include $50.9 million of noncash items related to equity issued in the form of PVR common units in connection with PVR’s Peabody Acquisition.

We are committed to expanding our oil and natural gas operations over the next several years through a combination of exploration, development and acquisition of new properties. We have a portfolio of assets which balances relatively low risk, moderate return development projects in Appalachia and Mississippi with relatively moderate risk, with potentially higher return development projects and exploration prospects in south Texas and south Louisiana.

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Oil and gas segment capital expenditures for 2004 are estimated to be approximately $100 million. Approximately $49 million of the planned oil and gas capital expenditures are expected to be for development drilling projects, including horizontal coalbed methane drilling in Appalachia, exploitation of our Mississippi Selma Chalk assets, drilling within our core assets in southern West Virginia and drilling Cotton Valley wells in east Texas and northern Louisiana. Exploration drilling is expected to be approximately $25 million of the planned expenditures, concentrated primarily in south Louisiana and south Texas. Expenditures to build our library of 3-D seismic data for drilling prospect generation is expected to be approximately $10 million, and lease acquisition and field project expenditures are expected to be approximately $15 million. We continually review drilling and other capital expenditure plans and may change these amounts based on industry conditions and the availability of capital. We believe our cash flow from operations and sources of debt financing are sufficient to fund our 2004 planned capital expenditures program.

Cash flows from Financing Activities

Consolidated net cash provided by financing activities was $21.8 million in 2003 compared with $37.4 million in 2002. Credit facility borrowings provided approximately $47.9 million of cash in 2003 and $11.3 million of cash in 2002. We also received $16.8 million of cash distributions in 2003 and $14.9 million of cash distributions in 2002 for our ownership of PVR units. Funds from both of these sources were primarily used for capital expenditure needs.

The Company has a $300 million revolving credit facility (the “Revolver”) with a syndicate of major banks led by Bank One NA (as the Administrative Agent), with a final maturity of December 2007. The Revolver is secured by a portion of our proved oil and gas reserves. It has an initial commitment of $150 million which can be expanded at our option to our current approved borrowing base of $200 million. The Company had borrowings of $64.0 million against the Revolver as of December 31, 2003, giving us approximately $86 million of borrowing capacity available under the Revolver as of that date. The Revolver is governed by a borrowing base calculation and will be redetermined semi-annually. We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.25 to 2.00 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 0.30 to 0.50 percent. The Revolver allows for issuance of up to $20 million of letters of credit. At December 31, 2003, letters of credit issued were $0.3 million. The financial covenants require us to maintain levels of debt-to-earnings and dividend limitation restrictions. We are currently in compliance with all of our covenants.

We have a $5 million line of credit, which had no borrowings against it as of December 31, 2003. The line of credit is effective through June 2004 and is renewable annually. We have an option to elect either a fixed rate LIBOR loan, floating rate LIBOR loan or base rate (as determined by the financial institution) loan.

As of December 31, 2003, the Partnership had outstanding borrowings of $91.8 million, consisting of $2.5 million borrowed against a $100 million revolving credit facility and $89.3 million attributable to the Partnership’s senior unsecured notes ($90.0 million offset by $0.7 million fair value of interest rate swap).

On October 31, 2003, the Partnership entered into an amendment to our revolving credit facility (the “PVR Revolver”) to increase the facility from $50 million to $100 million and to extend the maturity date to October 2006. The Revolver is with a syndicate of financial institutions led by PNC Bank, National Association, as its agent. Based primarily on the total debt to consolidated EBITDA covenant and subsequent to the issuance of PVR senior unsecured notes, as described below, available borrowing capacity under the PVR Revolver as of December 31, 2003 was approximately $17 million. The Revolver is available for general partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $5.0 million sublimit available for working capital needs and distributions and a $5.0 million sublimit for the issuance of letters of credit.

At the Partnership’s option, indebtedness under the PVR Revolver bears interest at either (i) the higher of the federal funds rate plus 0.50 percent or the prime rate as announced by PNC Bank, National Association or (ii) the Eurodollar rate plus an applicable margin which ranges from 1.25 percent to 2.25 percent based on the

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Partnership’s ratio of consolidated indebtedness to consolidated EBITDA (as defined in the PVR Revolver) for the four most recently completed fiscal quarters. The Partnership will incur a commitment fee on the unused portion of the PVR Revolver at a rate per annum ranging from 0.40 percent to 0.50 percent based upon the ratio of the Partnership’s consolidated indebtedness to consolidated EBITDA for the four most recently completed fiscal quarters. When the PVR Revolver matures in October 2006, it will terminate and all outstanding amounts thereunder will be due and payable. The Partnership may prepay the PVR Revolver at any time without penalty. The Partnership is required to reduce all working capital borrowings under the working capital sublimit under the PVR Revolver to zero for a period of at least 15 consecutive days once each calendar year.

The PVR Revolver prohibits the Partnership from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the PVR Revolver, occurs or would result from the distribution. In addition, the PVR Revolver contains various covenants that limit, among other things, the Partnership’s ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of the Partnership’s business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. At December 31, 2003, the Partnership was in compliance with the covenants in the PVR Revolver.

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

In conjunction with the PVR Notes, the Partnership entered into an interest rate swap agreement with a notional amount of $30 million, to hedge a portion of the fair value of the PVR Notes. This swap is designated as a fair value hedge and has been reflected as a decrease in long-term debt of $0.7 million as of December 31, 2003. Under the terms of the interest rate swap agreement, the counterparty pays the Partnership a fixed annual rate of 5.77 percent on a total notional amount of $30 million, and the Partnership pays the counterparty a variable rate equal to the floating interest rate which will be determined semi-annually and will be based on the six month London Interbank Offering Rate plus 2.36 percent.

Future Capital Needs and Commitments. In 2004, we anticipate making total capital expenditures, excluding acquisitions, of approximately $100 million. Nearly all of these expenditures are expected to be made in our oil and gas segment, and are expected to be funded primarily by operating cash flow. Additional funding will be provided as needed from our Revolver, under which we had $86 million of borrowing capacity as of December 31, 2003.

In our coal royalty and land management segment, PVR anticipates making total capital expenditures, excluding acquisitions, of approximately $0.2 million for coal services related projects. Part of PVR’s strategy is to make acquisitions which increase cash available for distribution to its unitholders. PVR’s ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new units. Since completing the Peabody Acquisition in late 2002, PVR’s ability to incur additional debt has been restricted due to limitations in its debt instruments. As of December 31, 2003, PVR had approximately $17 million of borrowing capacity available under the PVR Revolver. This limitation may have the effect of necessitating the issuance of new units by PVR, as opposed to using debt, to fund acquisitions in the future.

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Our contractual cash obligations as of December 31, 2003 were as follows:

	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		4-5 Years		Thereafter
	(in thousands)
Penn Virginia Corporation Revolver	$	64,000	$	—	$	—	$	64,000	$	—
PVR Revolver		2,500		—		2,500		—		—
PVR Notes		90,000		1,500		13,100		23,700		51,700
Rental commitments(1)		5,888		1,861		2,347		1,280		400
Total contractual cash obligations	$	162,388	$	3,361	$	17,947	$	88,980	$	52,100

(1) Rental commitments primarily relate to equipment and building leases. Also included are PVR’s rental commitments, which primarily relate to reserve-based properties which are, or are intended to be, subleased by the Partnership to third parties. The obligation expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. We believe the obligation after five years cannot be reasonably estimated; however, based on current knowledge, we believe PVR will incur approximately $0.4 million in rental commitments in perpetuity until the reserves have been exhausted.

Environmental Matters

Our businesses are subject to various environmental hazards. Several federal, state and local laws, regulations and rules govern the environmental aspects of our businesses. Noncompliance with these laws, regulations and rules can result in substantial penalties or other liabilities. We do not believe our environmental risks are materially different from those of comparable companies nor that cost of compliance will have a material adverse effect on our profitability, capital expenditures, cash flows or competitive position.

However, there is no assurance that future changes in or additions to laws, regulations or rules regarding the protection of the environment will not have such an impact. We believe we are materially in compliance with environmental laws, regulations and rules.

In conjunction with the Partnership’s leasing of property to coal operators, environmental and reclamation liabilities are generally the responsibilities of the Partnership’s lessees. 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.

Recent Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. We adopted SFAS No. 143 on January 1, 2003 and recognized, and recorded an asset of $1.3 million, a related liability of $2.7 million and a cumulative effect on change in accounting principle on prior years of $1.4 million (net of taxes of $0.7 million). During 2003, the company recognized a net $0.7 million of additions to the liability and a net $0.6 million of additions to the asset cost basis as a result of adopting SFAS No. 143.

In November 2002, the FASB issued Interpretation No. 45 ( FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others”, which clarifies the requirements of SFAS No. 5, “Accounting for Contingencies”, relating to a guarantor’s accounting for and disclosure of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party

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guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 31, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively. The Company has no outstanding guarantees that meet the recognition requirements of FIN 45 as of December 31, 2003.

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003) (“FIN 46R), “Consolidation of Variable Interest Entities” replacing FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities, an interpretation of ARB No. 51” issued in January 2003. FIN 46R was issued to replace FIN 46 and to provide clarification of key terms, additional exemptions for application and an extended initial application period. FIN 46R requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 was effective for all variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 was required to be applied for the first interim or annual period beginning after June 15, 2003. We are required to adopt FIN 46R no later than the end of the first reporting period ending after March 15, 2003, which is March 31, 2003. We do not expect the initial adoption of FIN 46R to have a material effect on our financial position, results of operations or cash flow.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Other Intangible Assets” to companies in the extractive industries, including oil and gas and coal industry companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights as intangible assets in the balance sheet, apart from other capitalized oil and gas property and coal property costs, and provide specific footnote disclosures. The Emerging Issues Task Force has added the treatment of oil and gas and coal mineral rights to an upcoming agenda, which may result in a change in how we are currently classifying these assets.

Oil and Gas Mineral Rights. Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties under SFAS No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies”. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $157 million and $136 million as of December 31, 2003 and December 31, 2002, respectively, out of oil and gas properties and into a separate line item for intangible assets. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.

Coal Mineral Rights. Historically, we have included both owned and leased mineral interests of PVR as a component of property and equipment on the balance sheet. However, based on the application of certain provisions of SFAS No. 141 and SFAS No. 142 to the coal industry, we have begun to classify costs associated with PVR’s leasing of coal reserves after June 30, 2001 as an intangible asset on the balance sheet, apart from other capitalized property costs. As of December 31, 2003, coal mineral rights of $4.9 million are included in other assets on the accompanying balance sheet. The transition provisions of SFAS No. 141 and SFAS No. 142 only require the reclassification of rights which were acquired after June 30, 2001 unless previously maintained records make it possible to reclassify rights acquired prior to that date. Prior to June 30, 2001, the Partnership did not separately allocate acquisition costs between owned coal mineral interests (tangible property) and leased coal mineral rights (intangible property), as such interests were part of the same coal seams. Accordingly, we have only classified coal mineral rights acquired after June 30, 2001 as an intangible asset and report them in Other assets in the accompanying consolidated balance sheet.

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In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards on how companies classify and measure certain financial instruments with characteristics of both liabilities and equity. The statement requires that we classify as liabilities the fair value of all mandatorily redeemable financial instruments that had previously been recorded as equity or elsewhere in the consolidated financial statements. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for all existing financial instruments beginning in the third quarter of 2003. The initial adoption of this Statement did not have a material effect on the financial position, results of operations or liquidity of the Company. The Company has no outstanding guarantees as of December 31, 2003.

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” to enhance the disclosures about pension plans and other postretirement benefit plans. The Statement retains the disclosures required by the original SFAS No. 132. Additional disclosures have been added to those disclosures including information describing the types of plan assets, investment strategy, measurement date(s), plan obligations, cash flows, and components of net periodic benefit costs recognized during interim periods. The provisions of this Statement are effective for financial statements with fiscal years ending after December 15, 2003. The interim-period disclosures required by this Statement are effective for interim periods beginning after December 15, 2003. We have included the required additional disclosures of the revised Statement in the financial statements. See Note 15. Pension Plans and Other Post-retirement Benefits.

On December 8, 2003, a new law was enacted which expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate that the benefits we pay after 2006 could be lower as a result of the new Medicare provisions; however, at this time the retiree medical obligations and costs reported do not reflect any changes as a result of this legislation. Deferring the recognition of the new Medicare provisions’ impact is permitted by FASB Staff Position 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, due to open questions about some of the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information. We do not believe that this regulation will have a material adverse effect on our financial position, results of operations or cash flows.

Forward-Looking Statements

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

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

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

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Important factors that could cause the actual results of our operations or financial condition to differ materially from those expressed or implied in the forward-looking statements include, but are not necessarily limited to:

• the cost of finding and successfully developing oil and gas reserves and the cost to PVR of finding new coal reserves;

• our ability to acquire new oil and gas reserves and PVR’s ability to acquire new coal reserves on satisfactory terms;

• the price for which such reserves can be sold;

• the volatility of commodity prices for oil and gas and coal;

• our ability to obtain adequate pipeline transportation capacity for our oil and gas production;

• PVR’s ability to lease new and existing coal reserves;

• the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves;

• the ability of lessees to obtain favorable contracts for coal produced from PVR’s reserves;

• competition among producers in the oil and gas and coal industries generally;

• the extent to which the amount and quality of actual production differs from estimated recoverable proved oil and gas reserves and coal reserves;

• unanticipated geological problems;

• availability of required drilling rigs, materials and equipment;

• the occurrence of unusual weather or operating conditions including force majeure events;

• the failure of equipment or processes to operate in accordance with specifications or expectations;

• delays in anticipated start-up dates of our oil and natural gas production and PVR’s lessees’ mining operations and related coal infrastructure projects;

• environmental risks affecting the drilling and producing of oil and gas wells or the mining of coal reserves;

• the timing of receipt of necessary governmental permits by us and by PVR’s lessees;

• the risks associated with having or not having price risk management programs;

• labor relations and costs;

• accidents;

• changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators;

• uncertainties relating to the outcome of litigation regarding permitting of the disposal of coal overburden;

• risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions;

• the experience and financial condition of lessees of PVR’s coal reserves including their ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others; and

• the Partnership’s ability to make cash distributions.

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Many of such factors are beyond our ability to control or accurately predict. Readers are cautioned not to put undue reliance on forward-looking statements.

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

Item 7A—Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk. At December 31, 2003, we had $64.0 million of long-term debt borrowed against our Revolver. The Revolver matures in December 2007 and is governed by a borrowing base calculation that is re-determined semi-annually. We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.25 to 2.00 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 0.30 to 0.50 percent. As a result, our 2004 interest costs will fluctuate based on short-term interest rates relating to the PVA Revolver.

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

Price Risk Management. Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to mitigate the price risks associated with fluctuations in natural gas and crude oil prices as they relate to our anticipated production. These contracts and/or financial instruments are designated as cash flow hedges and accounted for in accordance with SFAS No. 133, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 139. See Note 9. Hedging Activities of the Notes to the Consolidated Financial Statements for more information. The derivative financial instruments are placed with major financial institutions that we believe are of minimum credit risk. The fair value of our price risk management assets are significantly affected by energy price fluctuations. As of February 16, 2004, our open commodity price risk management positions on average daily volumes were as follows:

Natural gas hedging positions

	Costless Collars					Swaps
	Average MMbtu Per Day	Average Price / MMbtu(a)				Average MMbtu Per Day	Average Price /MMbtu
		Floor		Ceiling
First Quarter 2004	22,500	$	3.67	$	5.70	1,800	$	4.70
Second Quarter 2004	21,495	$	3.78	$	6.11	1,533	$	4.70
Third Quarter 2004	20,500	$	4.05	$	6.12	1,367	$	4.70
Fourth Quarter 2004	19,837	$	4.13	$	6.54	1,234	$	4.70
First Quarter 2005	13,656	$	4.00	$	6.52	379	$	4.70
Second Quarter 2005 (April only)	14,000	$	4.00	$	6.40	—	$	—

(a) The costless collar natural gas prices per MMbtu per quarter include the effects of basis differentials, if any, that may be hedged.

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Crude oil hedging positions

	Swaps
	Average Barrels Per Day	Average Price /Barrel
First Quarter 2004	404	$	28.62
Second Quarter 2004	493	$	29.07
Third Quarter 2004	413	$	30.03
Fourth Quarter 2004	407	$	30.08
First Quarter 2005 (January only)	400	$	30.13

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PENN VIRGINIA CORPORATION
March 9, 2004	By:	/s/    FRANK A. PICI
		(Frank A. Pici, Executive Vice President and Chief Financial Officer)
March 9, 2004	By:	/s/    DANA G WRIGHT
		(Dana G Wright, Vice President and Principal Accounting Officer)

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

/s/    ROBERT GARRETT         (Robert Garrett)	Chairman of the Board and Director	March 9, 2004
/s/    EDWARD B CLOUES, II         (Edward B. Cloues, II)	Director	March 9, 2004
/s/    A. JAMES DEARLOVE         (A. James Dearlove)	Director and Chief Executive Officer	March 9, 2004
/s/    H. JARRELL GIBBS         (H. Jarrell Gibbs)	Director	March 9, 2004
/s/    KEITH D. HORTON         (Keith D. Horton)	Director and Executive Vice President	March 9, 2004
/s/    MARSHA R. PERELMAN         (Marsha R. Perelman)	Director	March 9, 2004
/s/    JOE T. RYE         (Joe T. Rye)	Director	March 9, 2004
/s/    GARY K. WRIGHT         (Gary K. Wright)	Director	March 9, 2004

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Item 8—Financial Statements and Supplementary D ata

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

INDEX TO FINANCIAL SECTION

Management’s Report on Financial Information	50
Independent Auditors’ Report	51
Financial Statements and Supplementary Data	53

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MANAGEMENT’S REPORT ON FINANCIAL INFORMATION

Management of Penn Virginia Corporation (the “Company”) is responsible for the preparation and integrity of the financial information included in this annual report. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, which involve the use of estimates and judgments where appropriate.

The Company has a system of internal accounting controls designed to provide reasonable assurance that assets are safeguarded against loss or unauthorized use and to produce the records necessary for the preparation of financial information. The system of internal control is supported by the selection and training of qualified personnel, the delegation of management authority and responsibility, and dissemination of policies and procedures. There are limits inherent in all systems of internal control based on the recognition that the costs of such systems should be commensurate with the benefits to be derived. We believe the Company’s systems provide this appropriate balance.

The Company’s independent public accountants, KPMG LLP, have developed an understanding of our accounting and financial controls and have conducted such tests as they consider necessary to support their opinion on the 2003 financial statements. Their report contains an independent, informed judgment as to the corporation’s reported results of operations and financial position for 2003.

The Board of Directors pursues its oversight role for the financial statements through the Audit Committee, which consists solely of outside directors. The Audit Committee meets regularly with management, the internal auditor and KPMG LLP, jointly and separately, to review management’s process of implementation and maintenance of internal controls, and auditing and financial reporting matters. The independent and internal auditors have unrestricted access to the Audit Committee.

A. James Dearlove	Frank A. Pici
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer

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INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Penn Virginia Corporation:

We have audited the accompanying consolidated balance sheets of Penn Virginia Corporation (a Virginia corporation) and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, shareholders’ equity and comprehensive income and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. The 2001 consolidated financial statements of Penn Virginia Corporation and subsidiaries were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated February 18, 2002.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 11 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

KPMG LLP

Houston, Texas

February 16, 2004

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THIS REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP. THE REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP, NOR HAS ARTHUR ANDERSEN LLP PROVIDED A CONSENT TO THE INCLUSION OF ITS REPORT IN THIS FORM 10-K.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Penn Virginia Corporation:

We have audited the accompanying consolidated balance sheets of Penn Virginia Corporation (a Virginia corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Penn Virginia Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas

February 18, 2002

52

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except share data)

	Year Ended December 31,
	2003			2002			2001
Revenues
Oil and condensate	$	16,816		$	8,246		$	3,762
Natural gas		106,615			62,552			53,263
Coal royalties		50,312			31,358			32,365
Timber		1,020			1,640			1,732
Other		6,521			7,161			5,449
		181,284			110,957			96,571
Expenses
Lease operating		16,864			12,754			9,284
Exploration		15,589			7,733			11,832
Taxes other than income		11,322			6,804			5,433
General and administrative		24,893			21,440			15,297
Depreciation, depletion and amortization		50,109			30,639			19,579
Impairment of oil and gas properties		406			796			33,583
		119,183			80,166			95,008
Operating Income		62,101			30,791			1,563
Other income (expense)
Interest expense		(5,304	)		(2,116	)		(2,453	)
Interest income		1,237			2,038			1,602
Gain on the sale of securities		—			—			54,688
Other		1			1			14
Income from continuing operations before minority interest, income taxes, discontinued operations and cumulative effect of change in accounting principle		58,035			30,714			55,414
Minority interest		12,510			11,896			1,763
Income tax expense		18,366			6,935			19,314
Income from continuing operations before discontinued operations and cumulative effect of change in accounting principle		27,159			11,883			34,337
Income from discontinued operations (including gain on sale and net of taxes)		—			221			—
Cumulative effect of change in accounting principle, net of taxes of $734 thousand		1,363			—			—
Net Income	$	28,522		$	12,104		$	34,337
Income from continuing operations before discontinued operations and cumulative effect of change in accounting principle, basic	$	3.02		$	1.33		$	3.92
Income from discontinued operations, basic		—			0.02			—
Cumulative effect of change in accounting principle, basic		0.15			—			—
Net income per share, basic	$	3.17		$	1.35		$	3.92
Income from continuing operations before discontinued operations and cumulative effect of change in accounting principle, diluted	$	3.00		$	1.32		$	3.86
Income from discontinued operations per share, diluted		—			0.02			—
Cumulative effect of change in accounting principle, diluted		0.15			—			—
Net income per share, diluted	$	3.15		$	1.34		$	3.86
Weighted average shares outstanding, basic		8,988			8,930			8,770
Weighted average shares outstanding, diluted		9,056			8,974			8,896

The accompanying notes are an integral part of these consolidated financial statements.

53

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2003			2002
Assets
Current assets
Cash and cash equivalents	$	18,008		$	13,341
Accounts receivable		31,789			20,366
Other		2,108			2,030
Total current assets		51,905			35,737
Property and Equipment
Oil and gas properties (successful efforts method)		503,290			383,360
Other property and equipment		267,378			265,180
		770,668			648,540
Less: Accumulated depreciation, depletion and amortization		149,734			102,588
Net property and equipment		620,934			545,952
Other assets		10,894			4,603
Total assets	$	683,733		$	586,292
Liabilities and Shareholders’ Equity
Current liabilities
Current maturities of long-term debt	$	1,500		$	52
Accounts payable		9,911			5,670
Accrued liabilities		19,153			16,508
Hedging liabilities		2,678			1,621
Total current liabilities		33,242			23,851
Other liabilities		15,188			12,230
Hedging liabilities		998			444
Deferred income taxes		77,863			62,154
Long-term debt of the Company		64,000			16,000
Long-term debt of PVR.		90,286			90,887
Minority interest in PVR		190,508			192,770
Commitments and contingencies (Note 21)
Shareholders’ equity
Preferred stock of $100 par value—authorized 100,000 shares; none issued		—			—
Common stock of $6.25 par value—16,000,000 shares authorized; 9,052,416 and 8,946,651 shares issued and outstanding at December 31, 2003 and 2002, respectively		56,576			55,915
Paid-in capital		14,497			11,436
Retained earnings		143,619			123,189
Accumulated other comprehensive income		(2,250	)		(1,661	)
		212,442			188,879
Less: Unearned compensation and ESOP		794			923
Total shareholders’ equity		211,648			187,956
Total liabilities and shareholders’ equity	$	683,733		$	586,292

The accompanying notes are an integral part of these consolidated financial statements.

54

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(in thousands, except share data)

	Shares Outstanding		Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income			Treasury Stock			Unearned Compensation And ESOP			Total Stockholders’ Comprehensive Equity			Comprehensive Income (Loss)
Balance at December 31, 2000	8,397,758		$	55,762	$	8,100	$	92,718		$	26,606		$	(10,974	)	$	(1,050	)	$	171,162
Dividends paid ($0.90 per share)	—			—		—		(7,930	)		—			—			—			(7,930	)
Purchase of treasury stock	(33,991	)		—		—		—			—			(638	)		—			(638	)
Stock issued as compensation	8,281			—		142		—			—			188			—			330
Exercise of stock options	526,053			—		1,417		—			—			11,216			—			12,633
Allocation of ESOP shares	—			—		210		—			—			(391	)		591			410
Net income	—			—		—		34,337			—			—			—			34,337		$	34,337
Other comprehensive loss, net of tax	—			—		—		—			(24,850	)		—			—			(24,850	)		(24,850	)
Balance at December 31, 2001	8,898,101			55,762		9,869		119,125			1,756			(599	)		(459	)		185,454		$	9,487
Dividends paid ($0.90 per share)	—			—		—		(8,040	)		—			—			—			(8,040	)
Purchase of treasury stock	(15,202	)		—		—		—			—			(557	)		—			(557	)
Stock issued as compensation	6,752			8		84		—			—			157			—			249
PVR units issued as compensation, net	—			—		806		—			—			—			(664	)		142
Exercise of stock options	57,000			145		470		—			—			999			—			1,614
Allocation of ESOP shares	—			—		207		—			—			—			200			407
Net income	—			—		—		12,104			—			—			—			12,104		$	12,104
Other comprehensive loss, net of tax	—			—		—		—			(3,417	)		—			—			(3,417	)		(3,417	)
Balance at December 31, 2002	8,946,651			55,915		11,436		123,189			(1,661	)		—			(923	)		187,956		$	8,687
Dividends paid ($0.90 per share)	—			—		—		(8,092	)		—			—			—			(8,092	)
Stock issued as compensation	6,710			42		229		—			—			—			—			271
PVR units issued as compensation, net	—			—		172		—			—			—			(71	)		101
Exercise of stock options	99,055			619		2,364		—			—			—			—			2,983
Allocation of ESOP shares	—			—		296		—			—			—			200			496
Net income	—			—		—		28,522			—			—			—			28,522		$	28,522
Other comprehensive loss, net of tax	—			—		—		—			(589	)		—			—			(589	)		(589	)
Balance at December 31, 2003	9,052,416		$	56,576	$	14,497	$	143,619		$	(2,250	)	$	—		$	(794	)	$	211,648		$	27,933

The accompanying notes are an integral part of these consolidated financial statements

55

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2003			2002			2001
Cash flows from operating activities:
Net income	$	28,522		$	12,104		$	34,337
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		50,109			30,639			19,579
Deferred income taxes		15,292			8,133			(1,888	)
Minority interest		12,510			11,896			1,763
Dry hole and unproved leasehold expense		5,989			2,255			8,953
Impairment of oil and gas properties		406			796			33,583
Gain on sale of securities		—			—			(54,688	)
Cumulative effect of change in accounting principle		(1,363	)		—			—
Other		2,282			1,975			2,920
Changes in operating assets and liabilities:
Accounts receivable		(11,423	)		(5,695	)		592
Other current assets		239			(646	)		(2,041	)
Accounts payable and accrued liabilities		4,785			6,849			4,986
Taxes on income		—			—			(7,296	)
Other assets and liabilities		2,356			(2,518	)		3,391
Net cash flows provided by operating activities		109,704			65,788			44,191
Cash flows from investing activities:
Proceeds from the sale of securities		—			—			57,525
Proceeds from the sale of property and equipment		850			1,319			1,416
Payments received on long-term notes receivable		530			555			1,052
Sale of restricted U. S. Treasury Notes		—			43,387			—
Purchase of restricted U.S. Treasury Notes		—			—			(43,387	)
Additions to property and equipment		(128,182	)		(144,741	)		(196,038	)
Net cash flows used in investing activities		(126,802	)		(99,480	)		(179,432	)
Cash flows from financing activities:
Dividends paid		(8,092	)		(8,040	)		(7,930	)
Distributions paid to minority interest holders of PVR		(19,880	)		(13,787	)		—
Proceeds from borrowings of the Company		108,398			22,046			147,895
Repayment of borrowings of the Company		(60,450	)		(10,729	)		(191,400	)
Proceeds from PVR borrowings		90,000			47,500			43,387
Repayments of PVR borrowings		(88,387	)		—			—
Payments for debt issuance costs		(2,824	)		—			—
Proceeds from initial public offering, net		—			—			142,373
Purchases of treasury stock		—			(557	)		(638	)
Purchase of PVR units		—			(1,067	)		—
Issuance of stock		3,000			2,046			10,440
Net cash flows provided by financing activities		21,765			37,412			144,127
Net increase in cash and cash equivalents		4,667			3,720			8,886
Cash and cash equivalents—beginning of year		13,341			9,621			735
Cash and cash equivalents—end of year	$	18,008		$	13,341		$	9,621
Supplemental disclosures:
Cash paid during the year for:
Interest (net of amount capitalized)	$	3,810		$	1,213		$	3,131
Income taxes	$	6,529		$	125		$	28,772
Noncash investing and financing activities:
Issuance of PVR units for acquisitions	$	4,969		$	50,920		$	—
Working capital and assumed liabilities for acquisitions, net	$	—		$	3,805		$	—
Deferred tax liabilities related to acquisition, net	$	—		$	—		$	43,137

The accompanying notes are an integral part of these consolidated financial statements.

56

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

Penn Virginia Corporation (“Penn Virginia” or the “Company”) is an independent energy company that is engaged in two primary lines of business. We explore for, develop and produce crude oil, condensate and natural gas in the eastern and Gulf Coast onshore areas of the United States. In addition, we conduct our coal operations through our ownership in Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a Delaware limited partnership. See Note 2. Penn Virginia Resource Partners, L.P.

The Partnership enters into leases with various third-party operators for the right to mine coal reserves on the Partnership’s property in exchange for royalty payments. Approximately 72 percent of the Partnership’s 2003 coal royalty revenues and 99 percent of its 2002 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. The balance of the Partnership’s 2003 and 2002 coal royalty revenues were based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. The Partnership also sells timber growing on its land and provides fee-based infrastructure facilities to certain lessees to enhance coal production and to generate additional coal services revenues.

2. Penn Virginia Resource Partners, L.P.

Penn Virginia Resource Partners, L.P. was formed in July 2001 to own and operate the coal land management business of Penn Virginia.

The Partnership completed its initial public offering of 7,475,000 common units at a price of $21.00 per unit on October 30, 2001. Total proceeds for the 7,475,000 units were $157.0 million before offering costs and underwriters’ commissions. Effective with the closing of the initial public offering, Penn Virginia, through its wholly owned subsidiaries, received 174,880 common units, 7,649,880 subordinated units and a 2 percent general partnership interest in the ownership of the Partnership. In addition, concurrent with the closing of the initial public offering, the Partnership borrowed $43.4 million under its term loan credit facility with PNC Bank, National Association and other lenders.

In conjunction with the formation of the Partnership, Penn Virginia contributed to the Partnership net assets totaling $39.1 million. Concurrent with the initial public offering, the Partnership paid $141.5 million to Penn Virginia for repayment of debt and the purchase of 975,000 common units held by Penn Virginia. The Partnership’s note receivable from Penn Virginia was forgiven as well as the remaining portion of the Partnership’s note payable to Penn Virginia.

The common units have preferences over the subordinated units with respect to cash distributions, accordingly, we accounted for the sale of the Partnership units as a sale of a minority interest. At the time our subordinated units convert to common units, we will recognize any gain or loss computed at that time, as paid-in capital. Our subordinated units automatically convert to common units on September 30, 2006, but a portion of the subordinated units may convert after September 30, 2004 if the Partnership meets certain financial tests.

The general partner of the Partnership is Penn Virginia Resource GP, LLC, a wholly owned subsidiary of Penn Virginia.

57

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

3. Summary of Significant Accounting Policies

Principles of Consolidation

The consolidated financial statements include the accounts of Penn Virginia, all wholly-owned subsidiaries and the Partnership in which we have an approximate 45 percent ownership interest as of December 31, 2003. Penn Virginia Resource GP, LLC, a wholly-owned subsidiary of Penn Virginia, serves as the Partnership’s sole general partner and controls the Partnership. We own and operate our undivided oil and gas reserves through our wholly-owned subsidiaries. We account for our undivided interest in oil and gas properties using the proportionate consolidation method, whereby our share of assets, liabilities, revenues and expenses is included in the appropriate classification in the financial statements. Intercompany balances and transactions have been eliminated in consolidation. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the consolidated financial statements. Certain amounts have been reclassified to conform to the current year’s presentation.

Use of Estimates

Preparation of the accompanying consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Note Receivable

The note receivable is recorded at cost and adjusted for amortization of discounts. Discounts are amortized over the life of the note receivable using the effective interest rate method.

Oil and Gas Properties

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

The costs of unproved leaseholds, including capitalized interest, are capitalized pending the results of exploration efforts. During 2003, 2002 and 2001, interest costs associated with non-producing leases were capitalized for the period activities were in progress to bring projects to their intended use. We capitalized $2.0 million, $1.0 million and $1.1 million of interest costs in 2003, 2002 and 2001, respectively. Unproved leasehold costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, the cost of the property has been impaired. As unproved leaseholds are determined to be productive, the related costs

58

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

are transferred to proved leaseholds and amortized on a unit-of-production basis. As of December 31 2003 and 2002, unproved leasehold costs amounted to $60.0 million and $57.6 million, respectively.

Other Property and Equipment

Other property and equipment primarily represent PVR’s ownership in coal fee mineral interests. Other property and equipment is carried at cost and includes expenditures for additions and improvements, such as roads and land improvements, which substantially increase the productive lives of existing assets. Maintenance and repair costs are expensed as incurred. Depreciation of property and equipment is generally computed using the straight-line or declining balance methods over the estimated useful lives of such property and equipment, varying from 3 years to 20 years. Coal properties are depleted on an area-by-area basis at a rate based upon the cost of the mineral properties and estimated proven and probable tonnage therein. When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts. The difference between net book value and proceeds from disposition is recorded as a gain or loss.

Impairment of Long-Lived Assets

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

Concentration of Credit Risk

Substantially all of our accounts receivable at December 31, 2003 result from oil and gas sales and joint interest billings to third party companies in the oil and gas industry. This concentration of customers and joint interest owners may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, we analyze the entity’s net worth, cash flows, earnings and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables have not been significant.

Substantially all of the Partnership’s accounts receivable at December 31, 2003, result from accrued revenues from lessee production. This concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a lessee, the Partnership analyzes the entity’s net worth, cash flows, earnings and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred by the Partnership on receivables have not been significant.

Risk Factors

Our revenues, profitability, cash flow and future growth rates are substantially dependent upon the price of and demand for natural gas and crude oil and to a lesser extent coal. Prices for natural gas and crude oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control. We are also dependent upon the continued success of our exploratory drilling program. Other factors that could affect

59

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

revenues, profitability, cash flow and future growth rates include the inherent uncertainties in crude oil, natural gas and coal reserves, hedging of our crude oil and natural gas production with derivative instruments, the ability to replace crude oil, natural gas and coal reserves and the ability to finance future capital spending requirements.

Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, notes receivables, accounts payable, derivative instruments and long-term debt. The carrying values of cash and cash equivalents, accounts receivables, accounts payables, derivative instruments and long-term debt approximate fair value. The fair value of PVR senior unsecured debt at December 31, 2003 and 2002 was $88.9 million and $90.9 million, respectively. The fair value of notes receivable at December 31, 2003 and 2002 was $2.3 million and $3.4 million, respectively.

Revenues

Oil and Gas. Revenues associated with sales of crude oil, condensate, natural gas, and natural gas liquids are recorded when title passes to the customer. Natural gas sales revenues from properties in which the Company has an interest with other producers are recognized on the basis of our net working interest (“entitlement” method of accounting). Natural gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of the Company’s share is treated as deferred revenues. If the Company takes less than it is entitled to take, the under-delivery is recorded as a receivable.

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. Approximately 70 percent of PVR’s 2003 coal royalty revenues and all of the 2002 coal royalty revenues received from PVR’s coal lessees were based on a minimum dollar royalty per ton and/or a percentage of the gross sales price, with minimum monthly or annual rental payments. The remainder of PVR’s 2003 coal royalty revenues were derived from fixed royalty rate leases, which escalate annually, with pre-established minimum monthly payments. Coal royalty revenues are accrued on a monthly basis, based on PVR’s best estimates of coal mined on its properties.

Coal Services. Coal services revenues are recognized when lessees use the Partnership’s facilities for the processing, loading and/or transportation of coal. Coal services revenues consist of fees collected from the Partnership’s lessees for the use of the Partnership’s loadout facility, coal preparation plant and dock loading facility. Revenues associated with coal services for the years ended December 31, 2003, 2002 and 2001 were approximately $2.1 million, $1.7 million and $1.7 million, respectively, and are included in other revenues.

Timber. Timber revenues are recognized when timber is sold in a competitive bid process involving sales of standing timber on individual parcels and, from time to time, on a contract basis where independent contractors harvest and sell the timber. Timber revenues are recognized when the timber parcel has been sold or when the timber is harvested by the independent contractors. Title and risk of loss pass to the independent contractors upon the execution of the contract. In addition, if the contractors do not harvest the timber within the specified time period, the title of the timber reverts back to the Partnership with no refund of previous amounts received by us.

Minimum Rentals. Most of the Partnership’s lessees are required to make minimum monthly or annual payments that are generally recoupable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalty revenues. If a lessee fails to meet its minimum production

60

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

for the recoupment period, the deferred income attributable to the minimum payment is recognized as minimum rental revenues and is included in other revenues.

Hedging Activities

From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility. The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps.

All derivative instruments are recorded on the balance sheet at fair value. See Note 9. Hedging Activities. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we are utilizing only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. All hedge transactions are subject to our risk management policy, which has been reviewed and approved by our Board of Directors.

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

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

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

The fair values of our hedging instruments are determined based on third party forward price quotes for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices.

Income Tax

We account for income taxes in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes. This Statement requires a company to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in a company’s financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates.

Stock-based Compensation

We have stock compensation plans that allow, among other grants, incentive and nonqualified stock options to be granted to key employees and officers and nonqualified stock options to be granted to directors. See

61

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 18. Stock Compensation and Stock Ownership Plans. We account for those plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations. No stock-based employee compensation cost related to stock options is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provision of SFAS No. 123, Accounting for Stock-Based Compensation, to stock-based employee options.

	Year ended December 31,
	2003			2002			2001
Net income, as reported	$	28,522		$	12,104		$	34,337
Add:     Stock-based employee compensation expense included in reported net income related to restricted units and director compensation, net of related tax effects		332			424			215
Less:    Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(1,119	)		(1,268	)		(900	)
Pro forma net income	$	27,735		$	11,260		$	33,652
Earnings per share
Basic—as reported	$	3.17		$	1.35		$	3.92
Basic—pro forma	$	3.09		$	1.26		$	3.84
Diluted—as reported	$	3.15		$	1.34		$	3.86
Diluted—pro forma	$	3.06		$	1.25		$	3.78

New Accounting Standards

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying cost of the asset. We adopted SFAS No. 143 on January 1, 2003 and recognized, and recorded an asset of $1.3 million, a related liability of $2.7 million and a cumulative effect on change in accounting principle on prior years of $1.4 million (net of taxes of $0.7 million). During 2003, the company recognized a net $0.7 million of additions to the liability and a net $0.6 million of additions to the asset cost basis as a result of adopting SFAS No. 143.

In November 2002, the FASB issued Interpretation No. 45 ( FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others”, which clarifies the requirements of SFAS No. 5, “Accounting for Contingencies,” relating to a guarantor’s accounting for and disclosure of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 31, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively. The Company has no outstanding guarantees that meet the recognition requirements of FIN 45 as of December 31, 2003.

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003) (“FIN 46R), “Consolidation of Variable Interest Entities” replacing FASB Interpretation No. 46 (“FIN 46”), “Consolidation of

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Variable Interest Entities, an interpretation of ARB No. 51” issued in January 2003. FIN 46R was issued to replace FIN 46 and to provide clarification of key terms, additional exemptions for application and an extended initial application period. FIN 46R requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 was effective for all variable interest entities created or acquired after January 31, 2003. For variable interest entities created or acquired prior to February 1, 2003, the provisions of FIN 46 was required to be applied for the first interim or annual period beginning after June 15, 2003. We are required to adopt FIN 46R no later than the end of the first reporting period ending after March 15, 2003, which is March 31, 2003. We do not expect the initial adoption of FIN 46R to have a material effect on our financial position, results of operations or cash flow.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Other Intangible Assets” to companies in the extractive industries, including oil and gas and coal industry companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights as intangible assets in the balance sheet, apart from other capitalized oil and gas property and coal property costs, and provide specific footnote disclosures. The Emerging Issues Task Force has added the treatment of oil and gas and coal mineral rights to an upcoming agenda, which may result in a change in how we are currently classifying these assets.

Oil and Gas Mineral Rights. Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties under SFAS No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies”. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $157 million and $136 million as of December 31, 2003 and December 31, 2002, respectively, out of oil and gas properties and into a separate line item for intangible assets. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.

Coal Mineral Rights. Historically, we have included both owned and leased mineral interests of PVR as a component of property and equipment on the balance sheet. However, based on the application of certain provisions of SFAS No. 141 and SFAS No. 142 to the coal industry, we have begun to classify costs associated with PVR’s leasing of coal reserves after June 30, 2001 as an intangible asset on the balance sheet, apart from other capitalized property costs. As of December 31, 2003, coal mineral rights of $4.9 million are included in other assets on the accompanying balance sheet. The transition provisions of SFAS No. 141 and SFAS No. 142 only require the reclassification of rights which were acquired after the June 30, 2001 unless previously maintained records make it possible to reclassify rights acquired prior to that date. Prior to June 30, 2001, the Partnership did not separately allocate acquisition costs between owned coal mineral interests (tangible property) and leased coal mineral rights (intangible property), as such interests were part of the same coal seams. Accordingly, we have only classified coal mineral rights acquired after June 30, 2001 as an intangible asset and report them in Other assets in the accompanying consolidated balance sheet.

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards on how companies classify and measure certain financial instruments with characteristics of both liabilities and equity. The statement

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requires that we classify as liabilities the fair value of all mandatorily redeemable financial instruments that had previously been recorded as equity or elsewhere in the consolidated financial statements. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for all existing financial instruments beginning in the third quarter of 2003. The initial adoption of this Statement did not have a material effect on the financial position, results of operations or liquidity of the Company. The Company has no outstanding guarantees as of December 31, 2003.

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” to enhance the disclosures about pension plans and other postretirement benefit plans. The Statement retains the disclosures required by the original SFAS No. 132. Additional disclosures have been added to those disclosures including information describing the types of plan assets, investment strategy, measurement date(s), plan obligations, cash flows, and components of net periodic benefit costs recognized during interim periods. The provisions of this Statement are effective for financial statements with fiscal years ending after December 15, 2003. The interim-period disclosures required by this Statement are effective for interim periods beginning after December 15, 2003. We have included the required additional disclosures of the revised Statement in the financial statements. See Note 15. Pension Plans and Other Post-retirement Benefits.

On December 8, 2003, a new law was enacted which expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We anticipate that the benefits we pay after 2006 could be lower as a result of the new Medicare provisions; however, at this time the retiree medical obligations and costs reported do not reflect any changes as a result of this legislation. Deferring the recognition of the new Medicare provisions’ impact is permitted by FASB Staff Position 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, due to open questions about some of the new Medicare provisions and a lack of authoritative accounting guidance about certain matters. The final accounting guidance could require changes to previously reported information. We do not believe that this regulation will have a material adverse effect on our financial position, results of operations or cash flows.

4. 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. Additional wells are expected to be drilled over the next two to three years to fully develop the field.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On July 23, 2001, we acquired all of the outstanding stock of Synergy Oil & Gas, Inc., a Texas corporation. Synergy was a privately owned independent exploration and production company with operations primarily in the Texas onshore Gulf Coast and West Texas areas. Cash consideration for the stock was approximately $112 million, which was funded by advances under our revolving credit facility and available cash on hand. The total purchase price was allocated to the assets purchased and the liabilities assumed in the Synergy transaction based upon the fair values on the date of acquisition, as follows (in thousands):

Value of oil and gas properties acquired	$	157,120
Net assets acquired, excluding oil and gas properties		351
Deferred income tax liability		(45,271	)
Cash paid, net of cash acquired	$	112,200

The following unaudited Pro Forma results of operations have been prepared as though the acquisition had been completed on January 1, 2001. The unaudited Pro Forma results of operations for the years ended December 31, 2001 are as follows (in thousands, except share data):

	2001
Revenues	$	114,629
Net income	$	40,026
Net income per share, diluted	$	4.50

Coal Royalty and Land Management

In December 2002, the Partnership acquired two properties containing approximately 120 million tons of coal reserves (unaudited) from Peabody for 1,522,325 million common units, 1,240,833 million Class B common units (a combined common unit value of $57.0 million) and $72.5 million in cash plus closing costs. The $130.5 million acquisition included approximately $6.1 million, or 293,700 Class B units, held in escrow pending certain title transfers at December 31, 2002. As a result of the units held in escrow, approximately five million tons of coal reserves (unaudited) and 293,700 common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2002. In July 2003, 241,000 Class B common units were released from escrow in exchange for certain title transfers in New Mexico. In July 2003, all of the class B common units were converted, in accordance with their terms, upon the approval of our common unitholders. As of December 31, 2003, 52,700 common units remained in escrow pending Peabody acquiring and transferring to us certain of the West Virginia reserves we purchased. As a result of the units held in escrow, approximately one million tons of coal reserves and 52,700 common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2003. Approximately two-thirds of the reserves are located on the Lee Ranch property in New Mexico, which Peabody continues to operate as a surface mining operation. Approximately one third of the acquired reserves are in northern West Virginia, which Peabody also continues to operate. Each set of reserves are being leased back to Peabody for royalty rates which escalate annually over the life of the property’s production. As part of the transaction, Peabody will receive the right to share in the general partner’s Incentive Distribution Rights, if any, in exchange for additional properties Peabody may source to the Partnership in the future. The cash portion of the transaction was funded with long-term debt and $26.4 million in proceeds from the sale of U.S. Treasury notes. The acquired coal reserves had existing productive operations that have been included in the Partnership’s statements of income since the closing date.

In November 2002, the Partnership completed the acquisition of certain infrastructure-related equipment and other assets integral to mining on one of our West Virginia properties. The purchased assets included a 900-

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

ton per hour coal preparation plant, a unit-train loading facility and a railroad-granted rebate on coal loaded through the facility. The Partnership acquired the assets from Pen Holdings, Inc. and its lessors for $5.1 million in cash, which was funded with the proceeds from the sale of U.S. Treasury notes, plus the assumption of approximately $2.4 million in reclamation liabilities and approximately $0.6 million of stream mitigation obligations. These assets did not have existing productive operations at the time of acquisition. In 2003, the Partnership leased the property and related infrastructure to a third party who is actively operating on the property. Consequently, all of the reclamation and stream mitigation liabilities were assigned to the new lessee.

In August 2002, the Partnership acquired the coal mineral interests to approximately 16 million tons of coal reserves located in West Virginia for $12.3 million. The acquisition, which was purchased from an independent private entity, was funded with the proceeds from the sale of U.S. Treasury notes. The acquired coal mineral interests had existing productive operations that have been included in the Partnership’s statements of income as of the closing date.

The factors used by the Partnership to determine the fair market value of acquisitions include, but are not limited to, discounted future net cash flows on a risked-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of the lessees.

5. Investments and Dividend Income

In April 2001, we sold 3.3 million shares of the common stock of Norfolk Southern Corporation and other stocks which had been classified as available-for-sale. The Norfolk Southern Corporation shares were sold at an average price of $17.39 per share. Proceeds from the sales, net of commissions, totaled approximately $57.4 million. We recorded a pre-tax gain on the stock sale transactions of approximately $54.7 million.

Dividend income from our investment in Norfolk Southern Corporation was approximately $0.2 million for the year ended December 31, 2001.

6. Notes Receivable

At December 31, 2003 and 2002, the Partnership had one note receivable outstanding, which relates to the sale of coal properties located in Virginia in 1986. The note has a stated interest rate of 6.0 percent per annum and had an original principal amount of $15.0 million pursuant to which we receive quarterly payments through July 1, 2005. In addition, the Partnership owns a 50 percent residual interest in any royalty income generated from the coal properties sold which are mined after July 1, 2005.

The note receivable is collateralized by property and equipment. Maturities of notes receivable are as follows (in thousands):

	December 31,
	2003		2002
Current	$	767	$	527
Due after one year through July 1, 2005		504		1,274
Total	$	1,271	$	1,801

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

7. Property and Equipment

Property and equipment includes (in thousands):

	December 31,
	2003		2002
Oil and gas properties
Proved	$	443,248	$	325,785
Unproved		60,042		57,575
Total oil and gas properties		503,290		383,360
Other property and equipment:
Coal mineral interest		244,881		244,702
Other equipment		20,518		18,499
Land and timber		1,979		1,979
Total property and equipment		770,668		648,540
Less: Accumulated depreciation, depletion and amortization		149,734		102,588
Net property and equipment	$	620,934	$	545,952

8. Impairment of Oil and Gas Properties

In accordance with SFAS No. 144, Accounting for the Impairment of Disposal or Long-Lived Assets, we review oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When we find that the carrying amounts of the properties exceed their estimated undiscounted future cash flows, we adjust the carrying amount of the properties to their fair value as determined by discounting their estimated future cash flows. The factors used to determine fair value included, but were not limited to, estimates of proved reserves, future commodity prices, and timing of future production, future capital expenditures and a discount rate commensurate with the risk-free interest rate reflective of the lives remaining for the respective oil and gas properties.

For the year ended December 31, 2003, we recognized a pretax charge of $0.4 million ($0.2 million after tax) related to the impairment of certain south Texas properties. These impairments were a result of downward reserve revisions on these properties caused by the poor performance of these wells near the end of their productive lives.

Due to reserve revisions in 2002, we recognized a pretax charge of $0.8 million ($0.5 million after tax) related to the impairment of oil and gas properties for the year ended December 31, 2002.

Due to a low commodity price environment at the end of 2001, we recognized a pre-tax charge of $33.6 million ($21.8 million after tax) related to the impairment of oil and gas properties in the fourth quarter of 2001.

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9. Hedging Activities

Commodity Cash Flow Hedges

From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility. The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps. All derivative financial instruments are recognized in the financial statements at fair value in accordance with SFAS No. 133, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149 and related interpretations.

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

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

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

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

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

Time Period	Notional Quantities	Effective Floor /Ceiling Price	Swap Price		Fair Value
					(in thousands)
	(MMbtu per Day)	($ per MMbtu)	($ per MMbtu)
Natural Gas
Costless collars
January 1 – April 30, 2004	8,000	$3.50 / $5.00			$	(701	)
January 1 – June 30, 2004	7,500	$3.50 / $5.28				(660	)
January 1 – July 31, 2004	4,000	$3.72 / $6.97				(69	)
January 1 – December 31, 2004	3,000 / 6,000	$4.50 / $6.95				77
May 1 – November 30, 2004	6,500	$4.00 / $6.87				(1	)
July 1 – October 31, 2004	7,000	$4.00 / $5.24				(345	)
August 1 – October 31, 2004	4,000	$4.00 / $5.25				(151	)
November 1, 2004 – January 31, 2005	5,000 / 11,500 / 11,000	$4.00 / $6.82				(156	)
November 1, 2004 – April 30, 2005	2,000 / 14,000	$4.00 / $6.40				(317	)
Swaps
January 1 2004 – January 31, 2005	1,900 / 1,100		$	4.70		(367	)
	(Bbls per Day)		($ per barrel)
Crude Oil
Swaps
January 1, 2004 – January 31, 2005	90 to 50		$	26.93		(91	)
January 1, 2004 – June 30, 2004	120		$	26.58		(104	)
Total					$	(2,885	)

Based upon our assessment of our derivative contracts designated as cash flow hedges at December 31, 2003, we reported (i) a hedging liability of approximately $3.0 million, a hedging asset of approximately $0.1 million and (ii) a loss in accumulated other comprehensive income of $1.9 million, net of a related income tax benefit of $1.0 million. In connection with monthly settlements, we recognized net hedging losses in natural gas and oil revenues of $6.1 million for the year ended December 31, 2003. Based upon future oil and natural gas prices as of December 31, 2003, $2.6 million of hedging losses are expected to be realized within the next 12 months. The amounts ultimately realized will vary due to changes in the fair value of the open derivative contracts prior to settlement. We recognized net hedging losses of $1.1 million and net hedging gains of $1.9 million for the years ended December 31, 2002 and 2001, respectively.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of February 16, 2004 our open commodity hedge positions on average daily volumes were as follows:

Natural gas hedging positions

	Costless Collars					Swaps
	Average MMbtu Per Day	Average Price / MMbtu (a)				Average MMbtu Per Day	Average Price /MMbtu
		Floor		Ceiling
First Quarter 2004	22,500	$	3.67	$	5.70	1,800	$	4.70
Second Quarter 2004	21,495	$	3.78	$	6.11	1,533	$	4.70
Third Quarter 2004	20,500	$	4.05	$	6.12	1,367	$	4.70
Fourth Quarter 2004	19,837	$	4.13	$	6.54	1,234	$	4.70
First Quarter 2005	13,656	$	4.00	$	6.52	379	$	4.70
Second Quarter 2005 (April only)	14,000	$	4.00	$	6.40	—	$	—

(a) The costless collar natural gas prices per MMbtu per quarter include the effects of basis differentials, if any, that may be hedged.

Crude oil hedging positions

	Swaps
	Average Barrels Per Day	Average Price / Barrel
First Quarter 2004	404	$	28.62
Second Quarter 2004	493	$	29.07
Third Quarter 2004	413	$	30.03
Fourth Quarter 2004	407	$	30.08
First Quarter 2005 (January only)	400	$	30.13

Interest Rate Swap

In March 2003, PVR entered into an interest rate swap agreement with a notional amount of $30 million to hedge a portion of the fair value of its 5.77 percent senior unsecured notes which mature over a ten year period. This swap is designated as a fair value hedge and has been reflected as a decrease of long-term debt of approximately $0.7 million as of December 31, 2003, with a corresponding increase in long-term hedging liabilities. Under the terms of the interest rate swap agreement, the counterparty pays PVR a fixed annual rate of 5.77 percent on a total notional amount of $30 million, and PVR pays the counterparty a variable rate equal to the floating interest rate which will be determined semi-annually and will be based on the six month London Interbank Offering Rate (“LIBOR”) plus 2.36 percent. See Note 13. Long-Term Debt for a description of the underlying debt instrument to which the interest rate swap applies.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

10. Accrued Liabilities

Accrued expenses are summarized as follows (in thousands):

	December 31,
	2003		2002
Drilling costs	$	4,877	$	1,481
Royalties		3,277		2,654
Production, payroll and franchise taxes		2,850		2,834
Compensation		2,659		2,286
Deferred income		1,610		2,829
Interest		1,382		164
Professional services		598		2,594
Post-retirement healthcare		160		160
Pension		140		140
Other		1,600		1,366
Total	$	19,153	$	16,508

11. Asset Retirement Obligation

Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of assets.

The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is also added to the carrying amount of the associated asset and is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to accretion expense, which are recorded as additional depreciation, depletion and amortization. If the obligation is settled for other than the carrying amount of the liability, we will recognize a gain or loss on settlement.

We identified all required asset retirement obligations and determined the fair value of these obligations on the date of adoption. The determination of fair value was based upon regional market and specific well or mine type information. In conjunction with the initial application of SFAS No. 143, we recorded a cumulative effect of change in accounting principle, net of taxes, of approximately $1.4 million as an increase to income. In addition, we recorded an asset retirement obligation of approximately $2.7 million. Below is a reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations as of December 31, 2003 (in thousands).

Balance, January 1, 2003		$     —
Liability recorded upon initial adoption		2,685
Liabilities incurred in the current period		666
Liabilities settled in the current period		(120	)
Accretion expense		158
Balance, December 31, 2003	$	3,389

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes the pro forma net income and earnings per share for the years ended December 31, 2003 and 2002 had the change in accounting been implemented on January 1:

	December 31,
	2002		2001
Net income
As reported	$	12,104	$	34,337
Pro forma	$	12,185	$	34,495
Net income per share—reported
Basic	$	1.35	$	3.92
Diluted	$	1.34	$	3.86
Net income per share—pro forma
Basic	$	1.36	$	3.93
Diluted	$	1.35	$	3.88

12. Other Liabilities

Other liabilities are summarized in the following table (in thousands):

	December 31,
	2003		2002
Deferred income	$	6,028	$	2,488
Asset retirement obligation		3,389		871
Pension		2,242		2,237
Post-retirement health care		2,102		2,129
Reclamation environmental liabilities		1,413		4,478
Other		14		27
Total	$	15,188	$	12,230

13. Long-Term Debt

Long-term debt as of December 31, 2003 and 2002 consisted of the following (in thousands):

	December 31,
	2003			2002
Penn Virginia revolving credit facility, variable rate of 2.4% at December 31, 2003, due in 2007	$	64,000		$	16,000
PVR revolving credit facility, variable rate of 2.9% at December 31, 2003, due in 2006		2,500			47,500
PVR senior unsecured notes*		89,286			—
PVR Term loan		—			43,387
Line of credit		—			52
		155,786			106,939
Less: current maturities		(1,500	)		(52	)
Total long-term debt	$	154,286		$	106,887

* Includes negative fair value adjustment of $714 thousand related to interest rate swap designated as a fair value hedge. See Note 9. Hedging Activities.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

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Penn Virginia Revolving Credit Facility

In December 2003, we entered into a $300 million secured revolving credit facility (the “Revolver”) with a group of major banks led by Bank One NA, which has a borrowing base of $200 million and a $150 million initial commitment, and expires in December 2007.

The Revolver is governed by a borrowing base calculation and will be redetermined semi-annually. We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.25 to 2.00 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 0.30 to 0.50 percent. The weighted average interest rate on borrowings incurred during the year ended December 31, 2003 was approximately 2.91 percent. The Revolver allows for issuance of letters of credit that are limited to no more than $20 million. At December 31, 2003, letters of credit issued were $0.3 million. The financial covenants require us to maintain levels of debt-to-earnings and dividend limitation restrictions. We are currently in compliance with all of our covenants.

Line of Credit

We have a $5 million line of credit with a financial institution effective through June 2004, renewable annually. We have an option to elect either a fixed rate LIBOR loan, floating rate LIBOR loan or base rate (as determined by the financial institution) loan. At December 31, 2003 we had no outstanding borrowings against the line of credit.

PVR Revolving Credit Facility

In October 2003, the Partnership entered into an amendment to its revolving credit facility (the “PVR Revolver”) to increase the facility from $50 million to $100 million and to extend the maturity date to October 2006. The PVR Revolver is with a syndicate of financial institutions led by PNC Bank, National Association as its agent. The PVR Revolver is available for general partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $5.0 million sublimit that is available for working capital needs and distributions and a $5.0 million sublimit for the issuance of letters of credit.

At the Partnership’s option, indebtedness under the PVR Revolver will bear interest at either (i) the Eurodollar rate plus an applicable margin which ranges from 1.25 percent to 2.25 percent based on our ratio of consolidated indebtedness to consolidated EBITDA (as defined in the Revolver) for the four most recently completed fiscal quarters, or (ii) the higher of the federal funds rate plus 0.50 percent or the prime rate as announced by PNC Bank, National Association. The Partnership had utilized letters of credit of $1.6 million as of December 31, 2003 and 2002. The financial covenants of the PVR Revolver require PVR to maintain levels of debt to consolidated EBITDA (as defined by the credit agreement) and consolidated EBITDA to interest. The financial covenants restricted PVR’s borrowing capacity under the PVR Revolver to approximately $17 million as of December 31, 2003. As of December 31, 2003, the Partnership was in compliance with all of its covenants.

PVR senior unsecured notes

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The PVR Notes contain various covenants similar to those contained in the PVR Revolver. However, the Notes do not limit the Partnership’s ability to incur additional indebtedness. As of December 31, 2003, the Partnership was in compliance with all of the covenants.

Debt Maturities

Aggregate maturities of the principle amounts of long-term debt for the next five years and thereafter are as follows (in thousands):

2004	$	1,500
2005		4,800
2006		10,800
2007		75,000
2008		12,700
Thereafter		51,700
	$	156,500
Less: interest rate swap		(714	)
Total debt, including current maturities	$	155,786

14. Income Taxes

The provision for income taxes from continuing operations is comprised of the following (in thousands):

	Year ended December 31,
	2003		2002			2001
Current income taxes
Federal	$	2,067	$	(320	)	$	21,160
State		1,007		(878	)		42
Total current		3,074		(1,198	)		21,202
Deferred income taxes
Federal		12,090		5,236			(3,167	)
State		3,202		2,897			1,279
Total deferred		15,292		8,133			(1,888	)
Total income tax expense	$	18,366	$	6,935		$	19,314

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The difference between the taxes computed by applying the statutory tax rate to income from operations before income taxes and our reported income tax expense is as follows (in thousands):

	Year ended December 31,
	2003					2002					2001
Computed at federal statutory tax rate	$	15,933		35.0	%	$	6,586		35.0	%	$	18,777		35.0	%
State income taxes, net of federal income tax benefit		2,611		5.7	%		1,312		7.0	%		859		1.6	%
Dividends received deduction		—		—			—		—			(49	)	(0.1	)%
Non-conventional fuel source credit		—		—			(926	)	(4.9	)%		(721	)	(1.3	)%
Other, net		(178	)	(0.4	)%		(37	)	(0.2	)%		448		0.8	%
Total income tax expense	$	18,366		40.3	%	$	6,935		36.9	%	$	19,314		36.0	%

The principal components of our net deferred income tax liability are as follows (in thousands):

	December 31,
	2003		2002
Deferred tax liabilities:
Notes receivable	$	428	$	668
Oil and gas properties		81,927		66,092
Other property and equipment		859		635
Total deferred tax liabilities		83,214		67,395
Deferred tax assets:
Pension and post-retirement benefits		1,626		1,826
Deferred income—coal properties		564		965
Net operating loss carryforwards		2,057		1,392
Other		1,104		1,058
Total deferred tax assets		5,351		5,241
Net deferred tax liability	$	77,863	$	62,154

As of December 31, 2003, we have various net operating loss carryforwards for state tax purposes of approximately $39.1 million which, if unused, will expire from 2004 to 2022.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

15. Pension Plans and Other Post-retirement Benefits

We provide early retirement programs for eligible employees. Benefits are recorded based on the employee’s average annual compensation and yearly services. We provided a noncontributory, defined benefit pension plan, which was frozen in 1996 and terminated in 2001.

We also sponsor a defined benefit post-retirement plan that covers employees hired prior to January 1, 1991 who retire from active service. The plan provides medical benefits for the retirees and dependents and life insurance for the retirees. The medical coverage is noncontributory for retirees who retired prior to January 1, 1991 and may be contributory for retirees who retired after December 31, 1990.

We use a December 31 measurement date for these plans.

A reconciliation of the changes in the benefit obligations and fair value of assets for the years ended December 31, 2003 and 2002 and a statement of the funded status at December 31, 2003 and 2002 is as follows (in thousands):

	Pension						Post-retirement Healthcare
	2003			2002			2003			2002
Reconciliation of benefit obligation:
Obligation—beginning of year	$	2,377		$	2,375		$	4,960		$	3,468
Service cost		—			—			24			10
Interest cost		153			164			285			311
Benefits paid		(253	)		(260	)		(490	)		(618	)
Change in benefit assumption		—			—			—			1,039
Actuarial (gain) loss		105			98			(289	)		750
Obligation—end of year		2,382			2,377			4,490			4,960
Reconciliation of fair value of plan assets:
Fair value—beginning of year		—			—			—			518
Actual return on plan assets		—			—			—			5
Employer contributions		253			260			—			96
Participant contributions								—			11
Benefit payments		(253	)		(260	)		—			(609	)
Administrative expenses		—			—			—			(21	)
Fair value—end of year		—			—			—			—
Funded status:
Funded status—end of year		(2,382	)		(2,377	)		(4,490	)		(4,960	)
Unrecognized transition obligation		13			16			—			—
Unrecognized prior service cost		30			36			1,024			1,112
Unrecognized (gain) loss		577			491			1,208			1,559
Net amount recognized	$	(1,762	)	$	(1,834	)	$	(2,258	)	$	(2,289	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table provides the amounts recognized in the statements of financial position at December 31, 2003 and 2002 (in thousands):

	Pension						Post-retirement Healthcare
	2003			2002			2003			2002
Accrued benefit liability	$	(2,382	)	$	(2,377	)	$	(2,258	)	$	(2,289	)
Other long-term assets		43			52			—			—
Accumulated other comprehensive income		577			491			—			—
Obligation—end of year	$	(1,762	)	$	(1,834	)	$	(2,258	)	$	(2,289	)

The following table provides the components of net periodic benefit cost for the plans for the years ended December 31, 2003 and 2002 (in thousands):

	Pension				Post-retirement Healthcare
	2003		2002		2003		2002
Service cost	$	—	$	—	$	24	$	10
Interest cost		153		164		285		311
Expected return on plan assets		—		—		—		(8	)
Amortization of prior service cost		6		6		88		6
Amortization of transitional obligation		3		3		—		—
Recognized actuarial (gain) loss		19		12		45		113
Net periodic benefit cost	$	181	$	185	$	442	$	432

The assumptions used in the measurement of our benefit obligation were as follows:

	Pension				Post-retirement Healthcare
	2003		2002		2003		2002
Discount rate	6.25	%	6.75	%	6.25	%	6.75	%

For measurement purposes, a 9.0 percent annual rate increase in the per capita cost of covered health care benefits was assumed for 2003. The rate is assumed to decrease gradually to 5.0 percent for 2011 and remain at that level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts reported for post-retirement benefits. A one percent change in assumed health care cost trend rates would have the following effects for 2002 (in thousands):

	One percent Increase		One percent Decrease
Effect on total of service and interest cost components	$	13	$	(13	)
Effect on post-retirement benefit obligation		204		(196	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

16. Discontinued Operations

During the second quarter of 2002, we sold certain oil and gas properties, which included various interests in south Texas properties acquired in the third quarter of 2001. The operations of these properties were insignificant in 2001. The net carrying amount of properties sold was approximately $0.5 million. Accordingly, under the provisions of SFAS No. 144 the components of discontinued operations were as follows for the year ended December 31, 2002 (in thousands).

Production
Oil and condensate (Mbbls)		16
Natural gas (MMcf)		18
Total production (MMcfe)		114
Revenues
Natural gas	$	48
Oil and condensate		332
Total revenues		380
Expenses
Operating expenses		352
Depreciation, depletion and amortization		25
Total expenses		377
Income from discontinued operations		3
Gain on sale of properties		337
		340
Income taxes		(119	)
Net income from discontinued operations	$	221

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

17. Earnings Per Share

The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share (“EPS”) for net income for the three years ended December 31, 2003 (in thousands, except per share data.)

	2003		2002		2001
Income from continuing operations	$	27,159	$	11,883	$	34,337
Income from discontinued operations		—		221		—
Cumulative effect of change in accounting principle		1,363		—		—
Net income	$	28,522	$	12,104	$	34,337
Weighted average shares, basic		8,988		8,930		8,770
Effect of dilutive securities:
Stock options		68		44		126
Weighted average shares, diluted		9,056		8,974		8,896
Income from continuing operations per share, basic	$	3.02	$	1.33	$	3.92
Income from discontinued operations per share, basic		—		0.02		—
Cumulative effect of change in accounting principle, basic		0.15		—		—
Net income per share, basic	$	3.17	$	1.35	$	3.92
Income from continuing operations per share, diluted	$	3.00	$	1.32	$	3.86
Income from discontinued operations per share, diluted		—		0.02		—
Cumulative effect of change in accounting principle, diluted		0.15		—		—
Net income per share, diluted	$	3.15	$	1.34	$	3.86

Not included in calculation of the denominator for diluted earnings per share for the years ended December 31, 2003, 2002 and 2001 were options with an exercise price that exceeded the average price of the underlying securities, and as such these options are not considered to be dilutive.

18. Stock Compensation and Stock Ownership Plans

Stock Compensation Plans

We have several stock compensation plans (collectively known as the “Stock Compensation Plans”) that allow, among other grants, incentive and nonqualified stock options to be granted to key employees and officers and nonqualified stock options to be granted to directors. Options granted under the Stock Compensation Plans may be exercised at any time after one year and prior to ten years following the grant, subject to special rules that apply in the event of death, retirement and/or termination of the employment of an optionee. The exercise price of all options granted under the Stock Compensation Plans is at the fair market value of the Company’s stock on the date of the grant. At December 31, 2003 there were approximately 116,000 and 361,000 shares available for issuance to directors and employees, respectively, pursuant to the Stock Compensation Plans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes information with respect to the common stock options awarded under the Stock Option Plans and grants described above.

	2003			2002			2001
	Shares Under Options	Weighted Avg. Exercise Price		Shares Under Options	Weighted Avg Exercise Price		Shares Under Options	Weighted Avg Exercise Price
Outstanding at beginning of year	403,850	$	29.39	359,450	$	25.97	725,403	$	19.38
Granted	103,000	$	37.41	113,400	$	36.91	160,100	$	32.02
Exercised	104,900	$	23.70	57,000	$	24.45	526,053	$	23.35
Cancelled / forfeited	1,000	$	36.59	12,000	$	21.38	—		—
Outstanding at end of year	400,950	$	32.92	403,850	$	29.39	359,450	$	25.97
Weighted average of fair value of options granted during the year		$	10.51		$	10.17		$	10.55

The fair value of the options granted during 2003 is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: a) dividend yield of 1.98 percent to 2.59 percent, b) expected volatility of 27.9 percent, c) risk-free interest rate 3.7 percent and d) expected life of eight years.

The fair value of the options granted during 2002 is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: a) dividend yield of 2.37 percent to 2.66 percent, b) expected volatility of 28.6 percent, c) risk-free interest rate 3.8 percent and d) expected life of eight years.

The fair value of the options granted during 2001 is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: a) dividend yield of 2.71 percent to 2.92 percent, b) expected volatility of 32.3 percent, c) risk-free interest rate of 5.1 percent and d) expected life of eight years.

The following table summarizes certain information regarding stock options outstanding at December 31, 2003:

	Options Outstanding			Options Exercisable
Range of Exercise Price	Number Outstanding at 12/31/03	Weighted Avg. Remaining Contractual Life	Weighted Avg. Exercise Price/share	Number Exercisable at 12/31/03	Weighted Avg. Exercise Price/share
$15 to $19	800	5.5	$17.69	800	$17.69
$20 to $24	58,700	4.0	$21.65	58,700	$21.65
$25 to $29	18,150	5.0	$27.05	18,150	$27.05
$30 to $34	139,100	8.0	$32.53	129,100	$32.36
$35 to $39	173,200	8.9	$37.07	92,200	$37.20
$40 to $44	11,000	9.7	$43.39	—	$   —

Employees’ Stock Ownership Plan

In 1996, the Board of Directors extended the Employees’ Stock Ownership Plan (“ESOP”). All employees with one year of service are participants. The ESOP is designed to enable employees to accumulate stock ownership. While there are no employee contributions, participants receive an allocation of stock which has been contributed by the Company. Compensation costs are reported when such shares are released to employees. The ESOP borrowed $2.0 million from the Company in 1996 and used the proceeds to purchase treasury stock. Under the terms of the ESOP, we will make annual contributions over a 10-year period. At December 31, 2003, the unearned portion of the ESOP of approximately ($0.1 million) is reported as a component of Shareholders’

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Equity entitled “Unearned Compensation-ESOP.” The ESOP will be merged with and into the Penn Virginia Corporation and Affiliated Companies’ Employees’ 401(k) Plan effective July 1, 2004.

Shareholder Rights Plan

In February 1998, the Board of Directors adopted a Shareholder Rights Plan (the “Plan”) designed to prevent an acquirer from gaining control of the Company without offering a fair price to all shareholders. The Plan was amended in March 2002. Each right entitles the holder to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock, $100 par value, at a price of $100 subject to adjustment. The rights are not exercisable or transferable apart from the common stock until after a person or affiliated group has acquired or obtained the right to acquire fifteen percent or more (or ten percent or more if such person or group has been deemed to an “adverse person” as defined in the Plan), of our common stock. Each right will entitle the holder, under certain circumstances, to acquire at half the value, either common stock of the Company, a combination of cash, other property, or common stock or other securities of the Company, or common stock of an acquiring person. Any such event would also result in any rights owned beneficially by the acquiring person or its affiliates becoming null and void. The rights expire in February 2008 and are redeemable under certain circumstances.

Restricted Units of PVR

The general partner granted 12,950 restricted units to directors and officers of the general partner in 2003. A restricted unit entitles the grantee to receive a common unit upon the vesting of the restricted unit. Restricted units vest upon terms established by the Partnership Compensation Committee, but in no case earlier than the conversion to common units of the Partnership’s outstanding subordinated units. In addition, the restricted units will vest upon a change of control of the general partner or the Company. If a grantee’s employment with or membership on the Partnership’s Board of Directors of the general partner terminates for any reason, the grantee’s restricted units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered upon the vesting of restricted units may be common units acquired by the general partner in the open market, common units already owned by the general partner, common units acquired by the general partner directly from the Partnership or any other person or any combination of the foregoing. The general partner will be entitled to reimbursement by the Partnership for the cost incurred in acquiring such common units. Distributions payable with respect to restricted units may, at the Partnership’s Compensation Committee’s request, be paid directly to the grantee or held by the Partnership and made subject to a risk of forfeiture during the applicable restriction period.

The following table summarizes information with respect to restricted units awarded by the general partner.

	2003
	Restricted Units	Fair Value/unit
Outstanding at beginning of year	33,500	$	24.50
Granted	12,950	$	23.97
Vested	—		—
Forfeited	—		—
Outstanding at end of year	46,450	$	24.30

Compensation expense related to restricted units totaled $0.2 million, and $0.4 million for the years ended December 31, 2003 and 2002. There was no compensation expense related to restricted units in 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

19. Accumulated Other Comprehensive Income

Comprehensive income represents certain changes in equity during the reporting period, including net income and other comprehensive income, which includes, but is not limited to, unrealized gains and losses from marketable securities, price risk management assets and minimum pension liability adjustments. Reclassification adjustments represent gains or losses realized in net income for each respective year. For the three years ended December 31, 2003, the components of accumulated other comprehensive income are as follows (in thousands):

	Net Unrealized Holding Gain- Investments			Price Risk Management Assets			Minimum Pension Liability			Accumulated Other Comprehensive Income
Balance at December 31, 2000	$	26,806		$	—		$	(200	)	$	26,606
Investment holding gain, net of tax of $1,383		8,741			—			—			8,741
Investment reclassification adjustment, net of tax of $19,140		(35,547	)		—			—			(35,547	)
Hedging unrealized gain, net of tax of $1,940		—			3,603			—			3,603
Hedging reclassification adjustment, net of tax of $853		—			(1,584	)		—			(1,584	)
Pension plan adjustment, net of tax of $34		—			—			(63	)		(63	)
Balance at December 31, 2001		—			2,019			(263	)		1,756
Hedging unrealized loss, net of tax of $2,160		—			(4,012	)		—			(4,012	)
Hedging reclassification adjustment, net of tax of $350		—			651			—			651
Pension plan adjustment, net of tax of $30		—			—			(56	)		(56	)
Balance at December 31, 2002		—			(1,342	)		(319	)		(1,661	)
Hedging unrealized loss, net of tax of $2,428		—			(4,509	)		—			(4,509	)
Hedging reclassification adjustment, net of tax of $2,141		—			3,976			—			3,976
Pension plan adjustment, net of tax of $30		—			—			(56	)		(56	)
Balance at December 31, 2003	$	—		$	(1,875	)	$	(375	)	$	(2,250	)

20. Segment Information

Segment information has been prepared in accordance with SFAS No. 131 Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief decision maker, or decision-making group, in assessing performance. Our chief operating decision-making group consists of the Chief Executive Officer and other senior officials. This group routinely reviews and makes operating and resource allocation decisions among our oil and gas operations and its coal royalty and land management operations. Accordingly, our reportable segments are as follows:

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

Coal Royalty and Land Management—the leasing of mineral interests and subsequent collection of royalties and the development and harvesting of timber.

Corporate and Other—primarily represents corporate functions.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Oil and Gas			Coal Royalty and Land Management		Corporate and Other			Consolidated
	(in thousands)
December 31, 2003
Revenues	$	124,822		$	55,642	$	820		$	181,284
Operating costs and expenses		44,937			12,504		11,227			68,668
Depreciation, depletion and amortization		33,164			16,578		367			50,109
Impairment of oil and gas properties		406			—		—			406
Operating income (loss)	$	46,315		$	26,560	$	(10,774	)		62,101
Interest expense										(5,304	)
Interest income										1,237
Other										1
Income before minority interest and taxes									$	58,035
Total assets	$	405,753		$	259,892	$	18,088		$	683,733
Additions to property and equipment	$	122,270		$	5,291	$	621		$	128,182
December 31, 2002
Revenues	$	71,512		$	38,608	$	837		$	110,957
Operating costs and expenses		30,801			10,226		7,704			48,731
Depreciation, depletion and amortization		26,336			3,955		348			30,639
Impairment of oil and gas properties		796			—		—			796
Operating income (loss)	$	13,579		$	24,427	$	(7,215	)		30,791
Interest expense										(2,116	)
Interest income										2,038
Other										1
Income before minority interest and taxes									$	30,714
Total assets	$	314,284		$	266,576	$	5,432		$	586,292
Additions to property and equipment	$	51,581		$	92,817	$	343		$	144,741
December 31, 2001
Revenues	$	57,778		$	37,513	$	1,280		$	96,571
Operating costs and expenses		26,914			9,271		5,661			41,846
Depreciation, depletion and amortization		16,418			3,084		77			19,579
Impairment of oil and gas properties		33,583			—		—			33,583
Operating income (loss)	$	(19,137	)	$	25,158	$	(4,458	)		1,563
Gain on sale of securities										54,688
Interest expense										(2,453	)
Interest income										1,602
Other										14
Income before minority interest and taxes									$	55,414
Total assets	$	289,379		$	162,638	$	5,085		$	457,102
Additions to property and equipment	$	161,295		$	33,669	$	1,074		$	196,038

Operating loss for the Oil Gas segment in 2001 includes a $33.6 million impairment on properties see Note 8. Impairment of Oil and Gas Properties.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Operating income is total revenues less operating expenses. Operating income does not include certain other income items, gain (loss) on sale of securities, interest expense, minority interest and income taxes.

For the year ended December 31, 2003, three customers of the oil and gas segment accounted for approximately $34.8 million, $24.2 million and $21.9 million or 19 percent, 13 percent and 12 percent, respectively, of our consolidated net revenues.

For the year ended December 31, 2002, two customers of the oil and gas segment accounted for approximately $29.4 million and $17.7 million, or 26 percent 19 percent, respectively, of our consolidated net revenues.

For the year ended December 31, 2001, two customers of the oil and gas segment accounted for approximately $20.8 million and $11.4 million, or 22 percent and 12 percent, respectively, of our consolidated net revenues.

21. Commitments and Contingencies

Rental Commitments

Minimum rental commitments under all non-cancelable operating leases in effect at December 31, 2003 were as follows (in thousands):

Year ending December 31,
2004	$	1,861
2005		1,413
2006		934
2007		847
2008		433
Total minimum payments	$	5,488

Rental commitments primarily relate to equipment, car and building leases. Also included are the Partnership’s rental commitments, which primarily relate to reserve-based properties which are, or are intended to be, subleased by the Partnership to third parties. The obligation expires when the property has been mined to exhaustion or the lease has been canceled. The timing of mining by third party operators is difficult to estimate due to numerous factors. We believe the obligation after five years cannot be reasonably estimated; however, based on current knowledge, we believe the Partnership will incur approximately $0.4 million in rental commitments in perpetuity until the reserves have been exhausted.

Legal

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Environmental Compliance

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

The operations of the Partnership’s lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of the Partnership’s coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified the Partnership against any and all future environmental liabilities. The Partnership regularly visits the coal property leases to monitor lessee’s compliance with environmental laws and regulations, as well as reviewing mine activities. Management believes that the Partnership’s lessees will be able to comply with existing regulations and does not expect any material impact on its financial condition or results of operations.

As of December 31, 2003, the Partnership has reclamation bonding requirements with respect to certain of its unleased and inactive properties. In conjunction with the November 2002 purchase of equipment (see Note 4. Acquisitions), the Partnership assumed reclamation and mitigation liabilities of approximately $3.0 million. In 2003, the Partnership leased the property and related infrastructure to a third party who is actively operating on the property. Consequently, all of the reclamation and stream mitigation liabilities were assigned to the new lessee. As of December 31, 2003 and 2002, the Partnership’s environmental liabilities totaled $1.6 million and $4.6 million, respectively. The environmental liabilities are not covered by the indemnification agreement with Penn Virginia.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

22. Quarterly Financial Information (Unaudited)

Summarized Quarterly Financial Data:

	2003 Quarters Ended										2002 Quarters Ended
	(in thousands, except share data)
	Mar. 31		June 30		Sept. 30		Dec. 31		Mar. 31		June 30		Sept.30		Dec.31
Revenues	$	48,016	$	43,703	$	42,021	$	47,544	$	24,383	$	25,648	$	28,754	$	32,172
Operating Income (loss)	$	18,813	$	14,807	$	12,756	$	15,725	$	8,778	$	7,076	$	7,949	$	6,988
Net income	$	10,486	$	6,362	$	5,443	$	6,231	$	3,370	$	3,163	$	3,208	$	2,363
Net income from continuing operations per share(a)
Basic	$	1.02	$	0.71	$	0.61	$	0.69	$	0.38	$	0.33	$	0.36	$	0.26
Diluted	$	1.01	$	0.70	$	0.60	$	0.68	$	0.37	$	0.33	$	0.36	$	0.26
Net income from per share(a)
Basic	$	1.17	$	0.71	$	0.61	$	0.69	$	0.38	$	0.35	$	0.36	$	0.26
Diluted	$	1.16	$	0.70	$	0.60	$	0.68	$	0.37	$	0.35	$	0.36	$	0.26
Weighted average shares outstanding:
Basic		8,952		8,976		8,996		9,027		8,909		8,927		8,944		8,945
Diluted		8,996		9,047		9,069		9,110		9,007		8,984		8,982		8,984

(a) The sum of the quarters may not equal the total of the respective year’s net income per share due to changes in the weighted average shares outstanding throughout the year.

23. Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following supplemental information regarding the oil and gas producing activities is presented in accordance with the requirements of the Securities and Exchange Commission (SEC) and SFAS No. 69 “Disclosures about Oil and Gas Producing Activities”. The amounts shown include our net working and royalty interest in all of our oil and gas operations.

Capitalized Costs Relating to Oil and Gas Producing Activities

	Year Ended December 31,
	2003			2002			2001
	(in thousands)
Proved properties	$	123,302		$	93,744		$	87,198
Unproved properties		60,042			57,575			57,813
Wells, equipment and facilities		316,257			228,608			187,624
Support equipment		3,689			3,433			2,859
		503,290			383,360			335,494
Accumulated depreciation and depletion		(116,998	)		(86,586	)		(60,073	)
Net capitalized costs	$	386,292		$	296,774		$	275,421

In accordance with SFAS No. 143, as of January 1, 2003 the cost basis of oil and gas wells were grossed up by approximately $1.0 million. During 2003, an additional $0.4 million was added to the cost basis of oil and gas wells for wells drilled.

86

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Costs Incurred in Certain Oil and Gas Activities

	Year Ended December 31,
	2003		2002		2001
	(in thousands)
Proved property acquisition costs	$	35,131	$	517	$	97,143
Unproved property acquisition costs		9,021		5,819		64,488
Exploration costs		21,401		7,843		13,814
Development costs and other		67,783		41,750		31,545
Total costs incurred	$	133,336	$	55,929	$	206,990

Costs for the year ended December 31, 2001, include deferred income taxes of $45.3 million provided for the book versus tax basis difference related to the acquired Synergy Oil and Gas properties, $27.2 million of which is included in proved property acquisition costs and $18.1 million is included in unproved property acquisition costs.

Results of Operations for Oil and Gas Producing Activities

The following schedule includes results solely from the production and sale of oil and gas and a non-cash charge for property impairments. It excludes corporate related general and administrative expenses and gains or losses on property dispositions. The income tax expense is calculated by applying the statutory tax rates to the revenues after deducting costs, which include depletion allowances and giving effect to oil and gas related permanent differences and tax credits.

	Year Ended December 31,
	2003			2002		2001
	(in thousands)
Revenues	$	123,431		$	71,178	$	57,024
Production expenses		21,928			15,390		10,069
Exploration expenses		15,503			7,614		11,514
Depreciation and depletion expense		33,164			26,361		16,418
Impairment of oil and gas properties		406			796		33,583
		52,430			21,017		(14,560	)
Income tax expense (benefit)		(21,338	)		6,566		(5,817	)
Results of operations	$	31,092		$	14,451	$	(8,743	)

In accordance with SFAS No. 143, the combined depletion and accretion expense recognized during 2003 in depreciation and depletion expense was approximately $0.2 million. Had SFAS No. 143 been implemented on January 1, 2001 the net combined effect on depreciation and depletion expense for the years ended December, 31. 2002 and 2001 would have been favorable adjustments of approximately $0.1 million and $0.2 million, respectively.

Oil and Gas Reserves

The following schedule presents the estimated oil and gas reserves owned by us. This information includes our royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the three years ended December 31, 2003, were estimated by Wright and Company, Inc. All reserves are located in the United States.

87

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved oil and gas 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 oil and gas reserves are those reserves expected to be recovered through existing equipment and operating methods.

Net quantities of proved reserves and proved developed reserves during the periods indicated are set forth in the tables below:

Proved Developed and Undeveloped Reserves	Oil and Condensate		Natural Gas		Total Equivalents
	(Mbbls)		(MMcf)		(MMcfe)
December 31, 2000	71		174,247		174,673
Revisions of previous estimates	(438	)	(5,697	)	(8,325	)
Extensions, discoveries and other additions	90		41,395		41,935
Production	(164	)	(13,130	)	(14,114	)
Purchase of reserves	4,361		33,402		59,568
Sale of reserves in place	—		(964	)	(964	)
December 31, 2001	3,920		229,253		252,773
Revisions of previous estimates	—		(3,339	)	(3,339	)
Extensions, discoveries and other additions	1,944		33,197		44,861
Production	(364	)	(18,715	)	(20,899	)
Purchase of reserves	29		1,071		1,245
Sale of reserves in place	(168	)	(212	)	(1,220	)
December 31, 2002	5,361		241,255		273,421
Revisions of previous estimates	101		(5,302	)	(4,696	)
Extensions, discoveries and other additions	232		53,088		54,480
Production	(625	)	(20,094	)	(23,844	)
Purchase of reserves	1,567		14,354		23,756
Sale of reserves in place	(2	)	(232	)	(244	)
December 31, 2003	6,634		283,069		322,873
Proved Developed Reserves:
December 31, 2001	2,212		183,134		196,406
December 31, 2002	2,943		198,733		216,391
December 31, 2003	3,346		230,958		251,034

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and gas reserves. Future cash inflows were computed by applying year-end prices of oil and gas to the estimated future production of proved oil and gas reserves. Natural gas prices were escalated only where existing contracts contained fixed and determinable escalation clauses. Contractually provided natural gas prices in excess of estimated market clearing prices were used in computing the future cash inflows only if we expect to continue to receive higher prices under legally enforceable contract terms. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

88

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved oil and gas reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10 percent annual rate.

	Year Ended December 31,
	2003			2002			2001
	(in thousands)
Future cash inflows	$	1,965,224		$	1,372,935		$	722,203
Future production costs		(392,193	)		(263,705	)		(178,533	)
Future development costs		(70,105	)		(51,151	)		(39,145	)
Future net cash flows before income tax		1,502,926			1,058,079			504,525
Future income tax expense		(407,411	)		(285,633	)		(127,277	)
Future net cash flows		1,095,515			772,446			377,248
10% annual discount for estimated timing of cash flows		(583,823	)		(417,523	)		(188,305	)
Standardized measure of discounted future net cash flows	$	511,692		$	354,923		$	188,943

Changes in Standardized Measure of Discounted Future Net Cash Flows

	Year Ended December 31,
	2003			2002			2001
	(in thousands)
Sales of oil and gas, net of production costs	$	(101,503	)	$	(55,788	)	$	(47,191	)
Net changes in prices and production costs		92,640			203,588			(483,009	)
Extensions, discoveries and other additions		142,921			82,808			37,907
Development costs incurred during the period		15,503			16,393			13,771
Revisions of previous quantity estimates		(10,380	)		(6,513	)		(7,710	)
Purchase of minerals-in-place		68,071			2,901			70,294
Sale of minerals-in-place		(36	)		(328	)		(906	)
Accretion of discount		48,114			24,254			64,363
Net change in income taxes		(57,942	)		(72,614	)		122,636
Other changes		(40,619	)		(28,721	)		(48,605	)
Net increase (decrease)		156,769			165,980			(278,450	)
Beginning of year		354,923			188,943			467,393
End of year	$	511,692		$	354,923		$	188,943

As required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” changes in standardized measure relating to sales of reserves are calculated using prices in effect as of the beginning of the period and changes in standardized measure relating to purchases of reserves are calculated using prices in effect at the end of the period. Accordingly, the changes in standardized measure for purchases and sales of reserves reflected above do not necessarily represent the economic reality of such transactions. See the disclosure of “Costs incurred in Certain Oil and Gas Activities” and the statements of cash flows in the financial statements.

89

Item 9—Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Effective May 3, 2002, the Audit Committee of the Board of Directors of our Company dismissed Arthur Andersen LLP (“Andersen”) as the Company’s independent public accountants and engaged KPMG to serve as the Company’s independent public accountants for 2002.

None of Andersen’s reports on the Company’s consolidated financial statements for either of the past two fiscal years contained an adverse opinion or disclaimer of opinion or were qualified or modified as to uncertainty, audit scope or accounting principles.

During the Company’s two most recent fiscal years, there were no disagreements with Andersen on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Andersen, would have caused Andersen to make reference to the subject matter of the disagreements in connection with Andersen’s report; and during such period there were no “reportable events” of the kind listed in Item 304(a)(1)(v) of Regulation S-K.

The Company disclosed the foregoing information on a Current Report on Form 8-K dated May 3, 2002 (the “Form 8-K”). The Company provided Andersen with a copy of the foregoing disclosure and requested Andersen to furnish the Company with a letter addressed to the Securities and Exchange Commission stating whether Andersen agreed with the statements by the Company in the foregoing disclosure and, if not, stating the respects in which it did not agree. Andersen’s letter stated that it had read the pertinent paragraphs of the Form 8-K and was in agreement with the statements contained therein.

During the Company’s two most recent fiscal years and through the date of this Annual Report on Form 10-K, the Company did not consult KPMG with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s consolidated financial statements, or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

Item 9A—Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

The Company, under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, performed an evaluation of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, the Company’s principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to ensure that material information relating to the Company, including its consolidated subsidiaries, is accumulated and communicated to the Company’s management and made known to the principal executive officer and principal financial officer, particularly during the period for which this periodic report was being prepared.

(b) Changes in Internal Controls

No changes were made in the Company’s internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

90

PART III

Items 10, 11, 12 and 13—Directors and Executive Officers of the Company, Executive Compensation, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Certain Relationships and Related Transactions

Except for information concerning executive officers of the Company included as an unnumbered item in Part I hereof, in accordance with General Instruction G(3), reference is hereby made to the Company’s definitive proxy statement to be filed within 120 days after the end of the fiscal year covered by this report.

Item 14—Principal Accountant Fees and Services

The following table presents fees for professionals audit services rendered by KPMG LLP for the audit of the Company’s annual financial statements for 2003 and 2002, and fees billed for other services rendered by KPMG, LLP.

	2003		2002
Audit fees(1)	$	557,350	$	299,400
Audit related fees(2)		10,000		—
Tax fees(3)		66,529		22,390
Total Fees	$	633,879	$	321,790

(1) Includes $277,950 and $122,200 of fees related to the Partnership for the years ended December 31, 2003 and 2002, respectively. The Partnership reimbursed the Company for these amounts.

(2) Audit-related fees pertain to debt compliance letters issued by KPMG under the Company’s credit facility and the Partnership’s senior notes. The Partnership’s fees were $5,000 and they reimbursed the Company for this amount.

(3) Comprised of fees for tax consulting and tax compliance services.

Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditors

The Audit Committee’s policy is to pre-approve all audit and audit-related services provided by the independent auditors. These services may include audit services, audit-related services, tax services and other services. The Audit Committee may also pre-approve particular services on a case-by-case basis. The independent auditors are required to periodically report to the Audit Committee regarding the extent of services provided by the independent auditors in accordance with such pre-approval. The Audit Committee may also delegate pre-approval authority to one or more of its members. Such member(s) must report any decisions to the Audit Committee at the next scheduled meeting.

91

PART IV

Item 15—Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a) Financial Statements

1.	Financial Statements—The financial statements filed herewith are listed in the Index to Financial Statements on page 36 of this report.
2.	All schedules are omitted because they are not required, inapplicable or the information is included in the consolidated financial statements or the notes thereto
3.	Exhibits
(3.1)	Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
(3.2)	Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.2 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
(3.3)	Amended bylaws of Registrant (incorporated by reference to Exhibit 3.1 to Registrant’s Report on Form 8-K filed on March 28, 2002).
(4.1)	Rights Agreement dated as of February 11, 1998 between Penn Virginia Corporation and American Stock Transfer & Trust Company, as Agent (incorporated by reference to Exhibit 1.1 to Registrant’s Registration Statement on Form 8-A filed on February 20, 1998).
(4.2)	Amendment No. 1 to Rights Agreement dated March 27, 2002 by and between Penn Virginia Corporation and American Stock Transfer & Trust Company (incorporated by reference to Exhibit 4.1 of Registrant’s Report on Form 8-K filed on March 28, 2002).
(10.1)	Amended and Restated Credit Agreement dated as of December 4, 2003 among Penn Virginia Corporation, the lenders party thereto, Bank One, NA, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent, Royal Bank of Canada, BNP Paribas and Fleet National Bank, as Documentation Agents, and Banc One Capital Markets, Inc. and Wachovia Capital Markets, LLC, as Co-Lead Arrangers and Joint Book Runners.
(10.2)	Penn Virginia Corporation and Affiliated Companies Employees’ Stock Ownership Plan, as amended (incorporated by reference to Exhibit 10.2 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001).
(10.3)	Penn Virginia Corporation and Affiliated Companies’ Employees’ 401(k) Plan, as amended (incorporated by reference to Exhibit 10.3 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001).
(10.6)	Penn Virginia Corporation 1995 Third Amended and Restated Directors’ Stock Compensation Plan (incorporated by reference to Exhibit 10.6 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
(10.7)	Penn Virginia Corporation Amended 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.7 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
(10.8)	Omnibus Agreement (“Omnibus Agreement”) dated October 30, 2001 among Penn Virginia Corporation, Penn Virginia Resource GP, LLC, Penn Virginia Operating Co., LLC and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.2 to Registrant’s Report on Form 8-K filed on November 14, 2001).

92

(10.9)	Amendment to Omnibus Agreement (incorporated by reference to Exhibit 10.9 of Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
(10.10)	Penn Virginia Corporation 1994 Stock Option Plan, as amended (incorporated by reference to Exhibit 10.5 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
(10.11)	Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and A. James Dearlove (incorporated by reference to Exhibit 10.1 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002).
(10.12)	Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and Frank A. Pici (incorporated by reference to Exhibit 10.2 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002).
(10.13)	Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and Nancy M. Snyder (incorporated by reference to Exhibit 10.3 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002).
(10.14)	Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and H. Baird Whitehead (incorporated by reference to Exhibit 10.4 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002).
(10.15)	Change of Control Severance Agreement dated May 7, 2002 between Penn Virginia Corporation and Keith D. Horton (incorporated by reference to Exhibit 10.5 of Registrant’s Report on Form 10-Q for the period ended March 31, 2002).
(12)	Ratio of Earnings to Fixed Charges.
(14)	Penn Virginia Corporation Executive and Financial Officer Code of Ethics.
(16)	Letter dated May 8, 2002 from Arthur Andersen LLP to the Securities and Exchange Commission (incorporated by reference to Exhibit 16.1 of Registrant’s Current Report on Form 8K filed May 9, 2002).
(21)	Subsidiaries of Registrant.
(23.1)	Consent of KPMG LLP.
(23.2)	Consent of Wright & Company, Inc.
(31.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

On October 30, 2002, Registrant filed a report on Form 8-K. The report involved the resignation of a director of Registrant’s Board of Directors.

On December 6, 2002, Registrant filed a report on Form 8-K. The report involved the election of a director to Registrant’s Board of Directors.

93

EX-10.1

Exhibit 10.1

AMENDED AND RESTATED CREDIT AGREEMENT

DATED AS OF DECEMBER 4, 2003

AMONG

PENN VIRGINIA CORPORATION,

THE LENDERS,

BANK ONE, NA

AS ADMINISTRATIVE AGENT,

WACHOVIA BANK, NATIONAL ASSOCIATION

AS SYNDICATION AGENT,

ROYAL BANK OF CANADA, BNP PARIBAS AND FLEET NATIONAL BANK,

AS DOCUMENTATION AGENTS,

AND

BANC ONE CAPITAL MARKETS, INC. AND

WACHOVIA CAPITAL MARKETS, LLC

AS CO-LEAD ARRANGERS AND JOINT BOOK RUNNER

TABLE OF CONTENTS

		Page
ARTICLE I	DEFINITIONS	2
1.1.	Defined Terms: As used in this Agreement, the following terms have the meanings specified below:	2
1.2.	Terms Generally	20
ARTICLE II	THE CREDITS	21
2.1.	Commitment	21
2.2.	Required Payments; Termination	21
2.3.	Ratable Loans	21
2.4.	Types of Advances	21
2.5.	Commitment Fee; Increases and Reductions in Aggregate Commitment	21
2.6.	Minimum Amount of Each Advance	22
2.7.	Prepayments	22
	2.7.1.   Optional Payments	22
	2.7.2.   Mandatory Payments	23
2.8.	Method of Selecting Types and Interest Periods for New Advances	23
2.9.	Conversion and Continuation of Outstanding Advances	23
2.10.	Changes in Interest Rate, etc	24
2.11.	Rates Applicable After Default	24
2.12.	Method of Payment	24
2.13.	Noteless Agreement; Evidence of Indebtedness	25
2.14.	Telephonic Notices	25
2.15.	Interest Payment Dates; Interest and Fee Basis	26
2.16.	Notification of Advances, Interest Rates, Prepayments and Commitment Reductions	26
2.17.	Lending Installations	26
2.18.	Non-Receipt of Funds by the Administrative Agent	26
2.19.	Facility LCs	27
	2.19.1.   Issuance	27
	2.19.2.   Participations	27
	2.19.3.   Notice	27
	2.19.4.   LC Fees	28

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TABLE OF CONTENTS

(continued)

		Page
	2.19.5.   Administration; Reimbursement by Lenders	28
	2.19.6.   Reimbursement by Borrower	28
	2.19.7.   Obligations Absolute	29
	2.19.8.   Actions of LC Issuer	29
	2.19.9.   Indemnification	30
	2.19.10. Lenders’ Indemnification	30
	2.19.11. Facility LC Collateral Account	30
	2.19.12. Rights as a Lender	31
2.20.	Limitation of Interest; Applicability of Texas Finance Code Chapter 346	31
2.21.	Borrowing Base	32
ARTICLE III	YIELD PROTECTION; TAXES	34
3.1.	Yield Protection	34
3.2.	Changes in Capital Adequacy Regulations	35
3.3.	Availability of Types of Advances	35
3.4.	Funding Indemnification	35
3.5.	Taxes	35
3.6.	Lender Statements; Survival of Indemnity	37
3.7.	Time Limit; Etc	37
ARTICLE IV	CONDITIONS PRECEDENT	38
4.1.	Initial Credit Extension	38
4.2.	Each Credit Extension	41
ARTICLE V	REPRESENTATIONS AND WARRANTIES	42
5.1.	Existence	42
5.2.	Financial Position; No Material Adverse Effect	42
5.3.	Litigation	43
5.4.	No Breach	43
5.5.	Authority; Enforceability	43
5.6.	Approvals	43
5.7.	Use of Loans and Letters of Credit	44
5.8.	ERISA	44

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TABLE OF CONTENTS

(continued)

		Page
5.9.	Taxes	45
5.10.	Titles, Etc	45
5.11.	No Material Misstatements	46
5.12.	Investment Company Act	46
5.13.	Public Utility Holding Company Act	46
5.14.	Subsidiaries	46
5.15.	Jurisdiction of Incorporation or Organization	46
5.16.	Defaults	46
5.17.	Environmental Matters	47
5.18.	Compliance with the Law; Maintenance of Properties	48
5.19.	Insurance	48
5.20.	Rate Management Transactions	48
5.21.	Restriction on Liens	48
5.22.	Intellectual Property	49
5.23.	Material Personal Property	49
5.24.	Business	49
5.25.	Solvency	49
5.26.	Licenses, Permits, Etc	49
5.27.	Fiscal Year	49
ARTICLE VI	COVENANTS	50
6.1.	Affirmative Covenants	50
	6.1.1.   Reporting Requirements	50
	6.1.2.   Litigation	52
	6.1.3.   Maintenance, Compliance with Laws, Inspections, Insurance, Etc	53
	6.1.4.   Environmental Matters	54
	6.1.5.   Further Assurances	55
	6.1.6.   Performance of Obligations	55
	6.1.7.   Reserve Reports	55
	6.1.8.   Title Information	56
	6.1.9.   Additional Collateral; Additional Guarantors	57

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TABLE OF CONTENTS

(continued)

		Page
	6.1.10. ERISA Information and Compliance	57
	6.1.11. Business of the Borrower	58
	6.1.12. Payment of Taxes and Claims	58
	6.1.13. Permits, Licenses	58
	6.1.14. Legal Opinion	58
6.2.	Negative Covenants	59
	6.2.1.   Financial Covenants	59
	6.2.2.   Indebtedness	59
	6.2.3.   Liens	60
	6.2.4.   Dividends, Distributions and Redemptions	60
	6.2.5.   Investments, Loans and Advances	61
	6.2.6.   Designation and Conversion of Restricted and Unrestricted Subsidiaries; Indebtedness of Unrestricted Subsidiaries	61
	6.2.7.   Nature of Business	62
	6.2.8.   Proceeds of Loans	62
	6.2.9.   ERISA Compliance	62
	6.2.10. Mergers, Etc	63
	6.2.11. Sale of Oil and Gas Properties	63
	6.2.12. Environmental Matters	64
	6.2.13. Transactions with Affiliates	64
	6.2.14. Subsidiaries	64
	6.2.15. Negative Pledge Agreements	64
	6.2.16. Gas Imbalances, Take-or-Pay or Other Prepayments	65
	6.2.17. Fiscal Year; Fiscal Quarter	65
	6.2.18. Rate Management Transactions	65
	6.2.19. Restricted Subsidiaries	65
ARTICLE VII	DEFAULTS	66
7.1.	Events of Default	66
ARTICLE VIII	ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES	68
8.1.	Acceleration; Facility LC Collateral Amount	68

-iv-

TABLE OF CONTENTS

(continued)

		Page
8.2.	Amendments	69
8.3.	Preservation of Rights	69
8.4.	Application of Payments	70
ARTICLE IX	GENERAL PROVISIONS	70
9.1.	Survival of Representations	70
9.2.	Governmental Regulation	71
9.3.	Headings	71
9.4.	Entire Agreement	71
9.5.	Several Obligations; Benefits of this Agreement	71
9.6.	Expenses; Indemnification	71
9.7.	Numbers of Documents	72
9.8.	Accounting	72
9.9.	Severability of Provisions	72
9.10.	Nonliability of Lenders	72
9.11.	Confidentiality	73
9.12.	Nonreliance	73
9.13.	Disclosure	73
9.14.	Renewal and Continuation of Existing Indebtedness	73
9.15.	Collateral Matters; Lender Party Rate Management Agreements	74
ARTICLE X	THE ADMINISTRATIVE AGENT	74
10.1.	Appointment; Nature of Relationship	74
10.2.	Powers	74
10.3.	General Immunity	75
10.4.	No Responsibility for Loans, Recitals, Etc	75
10.5.	Action on Instructions of Lenders	75
10.6.	Employment of Agents and Counsel	75
10.7.	Reliance on Documents; Counsel	76
10.8.	Administrative Agent’s Reimbursement and Indemnification	76
10.9.	Notice of Default	76
10.10.	Rights as a Lender	76

-v-

TABLE OF CONTENTS

(continued)

		Page
10.11.	Lender Credit Decision	77
10.12.	Successor Administrative Agent	77
10.13.	Fees	78
10.14.	Delegation to Affiliates	78
10.15.	Execution of Collateral Documents	78
10.16.	Collateral Releases	78
10.17.	Co-Agents, Documentation Agent, Syndication Agent, etc	78
ARTICLE XI	SETOFF; RATABLE PAYMENTS	78
11.1.	Setoff	78
11.2.	Ratable Payments	79
ARTICLE XII	BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS	79
12.1.	Successors and Assigns	79
12.2.	Participations	80
	12.2.1.   Permitted Participants; Effect	80
	12.2.2.   Voting Rights	80
	12.2.3.   Benefit of Certain Provisions	80
12.3.	Assignments	81
	12.3.1.   Permitted Assignments	81
	12.3.2.   Consents	81
	12.3.3.   Effect; Effective Date	81
	12.3.4.   Register	82
12.4.	Dissemination of Information	82
12.5.	Tax Treatment	82
ARTICLE XIII	NOTICES	82
13.1.	Notices	82
13.2.	Change of Address	83
ARTICLE XIV	COUNTERPARTS	83
ARTICLE XV	CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL	83

-vi-

AMENDED AND RESTATED CREDIT AGREEMENT

THIS AMENDED AND RESTATED CREDIT AGREEMENT, dated as of December 4, 2003, is among PENN VIRGINIA CORPORATION, a corporation formed under the laws of the Commonwealth of Virginia, the Lenders, BANK ONE, NA, a national banking association having its principal office in Chicago, Illinois, as LC Issuer and as Administrative Agent, WACHOVIA BANK, NATIONAL ASSOCIATION, a national banking association having its principal office in Charlotte, North Carolina, as Syndication Agent, ROYAL BANK OF CANADA, BNP PARIBAS and FLEET NATIONAL BANK, as Documentation Agents, BANC ONE CAPITAL MARKETS, INC., as Co-Lead Arranger and Joint Bookrunner, and WACHOVIA CAPITAL MARKETS, LLC, as Co-Lead Arranger and Joint Bookrunner.

W I T N E S S E T H:

WHEREAS, the Borrower, JPMorgan Chase Bank (successor in interest to The Chase Manhattan Bank), as administrative agent, Wachovia Bank, National Association (formerly known as First Union National Bank), Bank One, NA, and Royal Bank of Canada, as co-syndication agents, and certain lenders party thereto (the “Prior Lenders”) have heretofore entered into a Credit Agreement dated as of October 30, 2001, as amended, modified or supplemented (the “Prior Credit Agreement”);

WHEREAS, the Borrower desires to amend and restate the Prior Credit Agreement in order to restructure, rearrange, renew, extend and continue all indebtedness evidenced by and outstanding under the Prior Credit Agreement (the “Existing Indebtedness”), and to modify the commitments from the Lenders pursuant to which Loans will be made by the Lenders to the Borrower and Facility LCs will be issued by the LC Issuer under the several responsibilities of the Lenders for the account of the Borrower from time to time prior to the Facility Termination Date;

WHEREAS, the Borrower has delivered to JPMorgan Chase Bank (successor in interest to The Chase Manhattan Bank), as administrative agent for the Prior Lenders, certain collateral documents to secure the repayment of the Existing Indebtedness to the Prior Lenders, which collateral documents are being assigned to the Administrative Agent in connection with, and concurrently with, the restructuring, rearrangement, renewal, extension and continuation of the Existing Indebtedness pursuant to this Agreement;

WHEREAS, the Agents, the Lenders and the LC Issuer are willing, on the terms and subject to the conditions hereinafter set forth (including Article IV), to amend and restate the Prior Credit Agreement in order to restructure, rearrange, renew, extend and continue all Existing Indebtedness and to modify the commitments and make such Loans to the Borrower and issue and participate in such Facility LCs for the account of the Borrower; and

NOW, THEREFORE, the parties hereto agree that the Prior Credit Agreement is amended and restated in its entirety as follows:

ARTICLE I

DEFINITIONS

1.1. Defined Terms: As used in this Agreement, the following terms have the meanings specified below:

“Additional Lender Certificate” shall have the meaning assigned to such term in Section 2.5(ii).

“Administrative Agent” means Bank One in its capacity as contractual representative of the Lenders pursuant to Article X, and not in its individual capacity as a Lender, and any successor Administrative Agent appointed pursuant to Article X.

“Advance” means a borrowing hereunder, (i) made by the Lenders on the same Borrowing Date, or (ii) converted or continued by the Lenders on the same date of conversion or continuation, consisting, in either case, of the aggregate amount of the several Loans of the same Type and, in the case of Eurodollar Loans, for the same Interest Period.

“Affiliate” of any Person means any other Person directly or indirectly controlling, controlled by or under common control with such Person. A Person shall be deemed to control another Person if the controlling Person owns 10% or more of any class of voting securities (or other ownership interests) of the controlled Person or possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of the controlled Person, whether through ownership of stock, by contract or otherwise.

“Agents” means collectively the Administrative Agent, the Syndication Agent and the Documentation Agents; and “Agent” means either the Administrative Agent, the Syndication Agent or a Documentation Agent, as the context requires.

“Aggregate Commitment” means the aggregate of the Commitments of all the Lenders, as reduced from time to time pursuant to the terms hereof; provided that the Aggregate Commitments shall not at any time exceed $300,000,000.

“Aggregate Outstanding Credit Exposure” means, at any time, the aggregate of the Outstanding Credit Exposure of all the Lenders.

“Agreement” means this amended and restated credit agreement, as it may be amended or modified and in effect from time to time.

“Alternate Base Rate” means, for any day, a rate of interest per annum equal to the higher of (i) the Prime Rate for such day and (ii) the sum of the Federal Funds Effective Rate for such day plus 1/2% per annum.

“Applicable Fee Rate” means, at any time, the percentage rate per annum at which Commitment Fees are accruing on the unused portion of the Aggregate Commitment at such time as set forth in the Pricing Schedule.

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“Applicable Margin” means, with respect to Advances of any Type at any time, the percentage rate per annum which is applicable at such time with respect to Advances of such Type as set forth in the Pricing Schedule.

“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Approved Petroleum Engineers” means any of Wright & Company, Inc., Rider Scott Company, Netherland Sewell & Associates, Inc., and Miller and Lentz, Ltd., or such other reputable firm(s) of independent petroleum engineers as shall be approved by the Required Lenders.

“Article” means an article of this Agreement unless another document is specifically referenced.

“Assignment of Secured Indebtedness” means that certain Assignment of Secured Indebtedness and Authorization to Assign Liens dated as of even date herewith among the Prior Administrative Agent, the Prior Lenders, the Administrative Agent, the Lenders and the Loan Parties, pursuant to which the Prior Administrative Agent and the Prior Lenders assign all their right, title and interest in and to the Existing Indebtedness, the Prior Credit Agreement and the other Loan Documents (defined in the Prior Credit Agreement) to the Administrative Agent and the Lenders.

“Authorized Officer” means, as to any Person, the Chief Executive Officer, the President, the Chief Financial Officer, or any Vice President of such Person. Unless otherwise specified, all references to an Authorized Officer herein shall mean an Authorized Officer of the Borrower.

“Available Aggregate Commitment” means, at any time, the Aggregate Commitment then in effect minus the Aggregate Outstanding Credit Exposure at such time.

“Bank One” means Bank One, NA, a national banking association having its principal office in Chicago, Illinois, in its individual capacity, and its successors.

“Borrower” means Penn Virginia Corporation, a corporation formed under the laws of the Commonwealth of Virginia, and its successors and permitted assigns.

“Borrowing Base” means at any time an amount equal to the amount determined in accordance with Section 2.21.

“Borrowing Base Deficiency” means at any time an amount equal to the amount by which aggregate outstanding Loans plus LC Obligations exceeds the Borrowing Base then in effect.

“Borrowing Date” means a date on which an Advance is made hereunder.

“Borrowing Notice” is defined in Section 2.8.

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“Business Day” means (i) with respect to any borrowing, payment or rate selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago, Houston and New York City for the conduct of substantially all of their commercial lending activities, interbank wire transfers can be made on the Fedwire system and dealings in United States dollars are carried on in the London interbank market and (ii) for all other purposes, a day (other than a Saturday or Sunday) on which banks generally are open in Chicago and New York for the conduct of substantially all of their commercial lending activities and interbank wire transfers can be made on the Fedwire system.

“Capital Lease” of a Person means any lease of Property by such Person as lessee which would be capitalized on a balance sheet of such Person prepared in accordance with GAAP.

“Capital Lease Obligations” of a Person means the amount of the obligations of such Person under Capital Leases which would be shown as a liability on a balance sheet of such Person prepared in accordance with GAAP.

“Casualty Event” means any loss, casualty or other insured damage to, or any taking under power of eminent domain or by condemnation or similar proceeding of, any Property or asset of the Borrower or any of its Restricted Subsidiaries which were included in the most recent Reserve Report having a fair market value in excess of $1,000,000.

“Closing Date” means the date of this Agreement.

“Co-Lead Arranger” means each of Bank One Capital Markets, Inc. and Wachovia Capital Markets, LLC, in its capacity as Co-Lead Arranger.

“Code” means the Internal Revenue Code of 1986, as amended, reformed or otherwise modified from time to time and any successor statute.

“Collateral” means any and all “Mortgaged Property” and “Collateral”, as defined in any Collateral Document.

“Collateral Documents” means the Assignment of Secured Indebtedness, the Guaranty, the Pledge Agreements, the Mortgage Assignment and Amendment, the Mortgages, the Security Agreements (if any) and each other security agreement or other instrument or document described or referred to in Exhibit E, and any and all other agreements, documents or instruments now or hereafter executed and delivered by the Borrower or any other Person (including participation or similar agreements between any Lender and any other lender or creditor with respect to any Obligation pursuant to this Agreement) in connection with, or as security for the payment or performance of the Obligations, as such agreements, documents or instruments may be amended, supplemented or restated from time to time.

“Collateral Shortfall Amount” is defined in Section 8.1.

“Commitment” means, for each Lender, the obligation of such Lender to make Loans to, and participate in Facility LCs issued upon the application of, the Borrower in an aggregate amount not exceeding the amount set forth opposite its signature below, as it may be modified as a result of any assignment that has become effective pursuant to Section 12.3.2 or as otherwise modified from time to time pursuant to the terms hereof.

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“Commitment Fee” means the commitment fee described in Section 2.5.

“Consolidated Net Income” means with respect to the Borrower and its Consolidated Restricted Subsidiaries, for any period, the aggregate of the net income (or loss) of the Borrower and its Consolidated Restricted Subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following: (i) the net income of any Person in which the Borrower or any Consolidated Restricted Subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Borrower and its Consolidated Restricted Subsidiaries in accordance with GAAP), except to the extent of the amount of dividends or distributions actually paid in such period by such other Person to the Borrower or to a Consolidated Restricted Subsidiary, as the case may be; (ii) the net income (but not loss) during such period of any Consolidated Restricted Subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by that Consolidated Restricted Subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such Consolidated Restricted Subsidiary or is otherwise restricted or prohibited, in each case determined in accordance with GAAP; (iii) the net income (or loss) of any Person acquired in a pooling-of-interests transaction for any period prior to the date of such transaction; (iv) any extraordinary gains or losses during such period, including gains or losses attributable to (A) Property sales and (B) stock or other equity purchases or divestitures; and (v) the cumulative effect of a change in accounting principles and any gains or losses attributable to writeups or writedowns of assets; and provided that if the Borrower or any Consolidated Restricted Subsidiary shall acquire or dispose of any Property or stock or other equity interests during such period or a Subsidiary shall be redesignated pursuant to the terms of this Agreement as either an Unrestricted Subsidiary or a Restricted Subsidiary, then, upon delivery to the Administrative Agent of audited or reviewed financial statements or other financial statements acceptable to the Required Lenders which support a recalculation, Consolidated Net Income shall be calculated after giving pro forma effect to such acquisition, disposition or redesignation, as if such acquisition, disposition or redesignation had occurred on the first day of such period.

“Consolidated Restricted Subsidiaries” means any Restricted Subsidiaries that are Consolidated Subsidiaries.

“Consolidated Subsidiaries” means for any Person, each Subsidiary of such Person (whether now existing or hereafter created or acquired) the financial statements of which shall be (or should have been) consolidated with the financial statements of such Person in accordance with GAAP.

“Consolidated Unrestricted Subsidiaries” means any Unrestricted Subsidiaries that are Consolidated Subsidiaries.

“Contingent Obligation” of a Person means any agreement, undertaking or arrangement by which such Person assumes, guarantees, endorses, contingently agrees to purchase or provide

5

funds for the payment of, or otherwise becomes or is contingently liable upon, the obligation or liability of any other Person, or agrees to maintain the net worth or working capital or other financial condition of any other Person, or otherwise assures any creditor of such other Person against loss, including, without limitation, any comfort letter, operating agreement, take-or-pay contract or the obligations of any such Person as general partner of a partnership with respect to the liabilities of the partnership.

“Conversion/Continuation Notice” is defined in Section 2.9.

“Credit Extension” means the making of an Advance or the issuance of a Facility LC hereunder.

“Credit Extension Date” means the Borrowing Date for an Advance or the issuance date for a Facility LC.

“Default” means an event described in Article VII.

“Documentation Agent” means each of Royal Bank of Canada, BNP Paribas and Fleet National Bank in its capacity as contractual representative of the Lenders, and not in its individual capacity as a Lender, and any successor Documentation Agent.

“Domestic Subsidiary” means any Restricted Subsidiary organized under the laws of any jurisdiction within the United States of America (including territories thereof).

“EBITDAX” means, for any period, the sum of Consolidated Net Income for such period plus the following expenses or charges to the extent deducted from Consolidated Net Income in such period: Interest Expense, taxes, depreciation, depletion, amortization, exploration expenses, other similar noncash charges and the amount of cash dividends and distributions paid by the MLP to the Borrower, minus all noncash income added to Consolidated Net Income and any cash dividends, distributions or other payments made by the Borrower to any shareholders of the Borrower.

“Engineering Reports” shall have the meaning assigned such term in Section 2.21(iii).

“Environmental Laws” means any and all Governmental Requirements pertaining to health or the environment in effect in any and all jurisdictions in which the Borrower or any Restricted Subsidiary is conducting or at any time has conducted business, or where any Property of the Borrower or any Restricted Subsidiary is located, including without limitation, the Oil Pollution Act of 1990 (“OPA”), the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“CERCLA”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended, the Superfund Amendments and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, and other environmental conservation or protection laws. The term “oil” shall have the meaning specified in OPA, the terms “hazardous substance” and “release” (or “threatened release”) have the meanings specified in CERCLA, and the terms “solid waste” and “disposal” (or “disposed”) have the meanings specified in RCRA;

6

provided, however, that (i) in the event either OPA, CERCLA or RCRA is amended so as to broaden the meaning of any term defined thereby, such broader meaning shall apply subsequent to the effective date of such amendment and (ii) to the extent the laws of the state in which any Property of the Borrower or any Restricted Subsidiary is located establish a meaning for “oil,” “hazardous substance,” “release,” “solid waste” or “disposal” which is broader than that specified in either OPA, CERCLA or RCRA, such broader meaning shall apply.

“Environmental Liability” means any liability, contingent or otherwise (including any liability for damages, costs of environmental remediation, fines, penalties or indemnities), of the Borrower or any of its Subsidiaries directly or indirectly resulting from or based upon (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or threatened release of any Hazardous Materials into the environment, or (e) any contract, agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to any of the foregoing.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, any rule or regulation issued thereunder, and any successor statute.

“ERISA Affiliate” means each trade or business (whether or not incorporated) which together with the Borrower or any Subsidiary would be deemed to be a “single employer” within the meaning of section 4001(b)(1) of ERISA or subsections (b), (c), (m) or (o) of section 414 of the Code.

“ERISA Event” means (i) a “Reportable Event” described in Section 4043 of ERISA and the regulations issued thereunder for which reporting has not been waived under such regulations, (ii) the withdrawal of the Borrower or any ERISA Affiliate from a Plan during a plan year in which it was a “substantial employer” as defined in Section 4001(a)(2) of ERISA, (iii) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under Section 4041 of ERISA, (iv) the institution of proceedings to terminate a Plan by the PBGC or (v) any other event or condition which might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan.

“Eurodollar Advance” means an Advance which, except as otherwise provided in Section 2.11, bears interest at the applicable Eurodollar Rate.

“Eurodollar Base Rate” means, with respect to a Eurodollar Advance for the relevant Interest Period, the applicable British Bankers’ Association LIBOR rate for deposits in U.S. dollars as reported by any generally recognized financial information service as of 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, and having a maturity equal to such Interest Period, provided that, if no such British Bankers’ Association LIBOR rate is available to the Administrative Agent, the applicable Eurodollar Base Rate for the relevant Interest Period shall instead be the rate determined by the Administrative Agent to be the rate at which Bank One or one of its Affiliate banks offers to place deposits in U.S. dollars with first-class banks in the London interbank market at approximately 11:00 a.m. (London time) two Business Days prior to the first day of such Interest Period, in the approximate amount of Bank One’s relevant Eurodollar Loan and having a maturity equal to such Interest Period.

7

“Eurodollar Loan” means a Loan which, except as otherwise provided in Section 2.11, bears interest at the applicable Eurodollar Rate.

“Eurodollar Rate” means, with respect to a Eurodollar Advance for the relevant Interest Period, the sum of (i) the quotient of (a) the Eurodollar Base Rate applicable to such Interest Period, divided by (b) one minus the Reserve Requirement (expressed as a decimal) applicable to such Interest Period, plus (ii) the Applicable Margin.

“Excepted Liens” means: (i) Liens for taxes, assessments or other governmental charges or levies which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (ii) Liens in connection with workers’ compensation, unemployment insurance or other social security, old age pension or public liability obligations which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (iii) operators’, vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, suppliers’, workers’, materialmen’s, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of Oil and Gas Properties or statutory landlord’s liens, including lessee or operator obligations under statutes, governmental regulations or instruments related to the ownership, exploration and production of oil, gas and minerals on private, state, federal or foreign lands or waters, each of which is in respect of obligations that have not been outstanding more than sixty days or which are being contested in good faith by appropriate proceedings and for which adequate reserves have been maintained in accordance with GAAP; (iv) Liens which (a) arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements which are usual and customary in the oil and gas business and (b) are for claims which either are not delinquent or are being contested in good faith by appropriate proceedings and as to which the Borrower or any Restricted Subsidiary shall have set aside on its books such reserves as may be required pursuant to GAAP, provided that any such Lien referred to in this clause does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by the Borrower or any Restricted Subsidiary or materially impair the value of such Property subject thereto; (v) Liens reserved in oil and gas mineral leases, or created by statute, to secure royalty, net profits interests, bonus payments, rental payments or other payments out of or with respect to the production, transportation or processing of Hydrocarbons, and compliance with the terms of such Hydrocarbon Interests, provided that such Liens secure claims which either are not delinquent or are being contested in good faith by appropriate proceedings and as to which the Borrower or its Restricted Subsidiary shall have set aside on its books such reserves as may be required pursuant to GAAP; (vi) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that (a) no such deposit account is a dedicated cash collateral account or is subject to restrictions

8

against access by the depositor in excess of those set forth by regulations promulgated by the Board of Governors of the Federal Reserve System, and (b) no such deposit account is intended by Borrower or any of its Restricted Subsidiaries to provide collateral to the depository institution; (vii) all other non-consensual defects in title (which might otherwise constitute Liens) arising in the ordinary course of the Borrower’s or such Restricted Subsidiary’s business or incidental to the ownership of their respective Properties; provided that no such Liens shall secure the payment of Indebtedness or shall, in the aggregate, materially detract from the value or marketability of the Property subject thereto or materially impair the use or operation thereof in the operation of the business of the Borrower or such Restricted Subsidiary; (viii) encumbrances (other than to secure the payment of borrowed money or the deferred purchase price of Property or services), easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of the Borrower or any Restricted Subsidiary for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, and defects, irregularities, zoning restrictions and deficiencies in title of any Property which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by the Borrower or any Restricted Subsidiary or materially impair the value of such Property subject thereto; (ix) Liens on cash or securities pledged to secure performance of surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business; and (x) judgment Liens not giving rise to a Default, provided that (a) any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired and (b) no action to enforce such Lien has been commenced.

“Excluded Taxes” means, in the case of each Lender or applicable Lending Installation and the Administrative Agent, taxes imposed on its overall net income, receipts, assets, net worth, and franchise taxes imposed on it, by (i) the jurisdiction under the laws of which such Lender or the Administrative Agent is incorporated or organized or (ii) the jurisdiction in which the Administrative Agent’s or such Lender’s principal executive office or such Lender’s applicable Lending Installation is located.

“Exhibit” refers to an exhibit to this Agreement, unless another document is specifically referenced.

“Existing Indebtedness” is defined in the second recital.

“Facility LC” is defined in Section 2.19.1.

“Facility LC Application” is defined in Section 2.19.3.

“Facility LC Collateral Account” is defined in Section 2.19.11.

“Facility Termination Date” means December 4, 2007.

9

“Fair Market Value” means, with respect to any Property, the cash value which a Person which is not an Affiliate of the Borrower would pay in an arms-length transaction to purchase the specified Property.

“Federal Funds Effective Rate” means, for any day, an interest rate per annum equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published for such day (or, if such day is not a Business Day, for the immediately preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day which is a Business Day, the average of the quotations at approximately 10:00 a.m. (Chicago time) on such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by the Administrative Agent in its sole discretion.

“Financial Statements” means the financial statement or statements of the Borrower and its Consolidated Subsidiaries referred to in Section 4.1(ix).

“Fiscal Quarter” means a three-month period ending on the last day of December, March, June or September of any year.

“Fiscal Year” means a twelve-month period ending on the last day of December 31 of any year.

“Floating Rate” means, for any day, a rate per annum equal to (i) the Alternate Base Rate for such day plus (ii) the Applicable Margin, in each case changing when and as the Alternate Base Rate changes.

“Floating Rate Advance” means an Advance which, except as otherwise provided in Section 2.11, bears interest at the Floating Rate.

“Floating Rate Loan” means a Loan which, except as otherwise provided in Section 2.11, bears interest at the Floating Rate.

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” means generally accepted accounting principles in the United States of America.

“Governmental Authority” means, in respect of any Person, the country, state, county, city and political subdivisions in which such Person or such Person’s Property is located or which exercises valid jurisdiction over such Person or such Person’s Property, and any court, agency, department, commission, board, bureau or instrumentality of any of them including monetary authorities which exercises valid jurisdiction over such Person or such Person’s Property. Unless otherwise specified, all references to Governmental Authority herein shall mean a Governmental Authority having jurisdiction over, where applicable, the Borrower, the Restricted Subsidiaries or any of their Property or the Administrative Agent, any Lender or any applicable Lending Installation.

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“Governmental Requirement” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement, including, without limitation, Environmental Laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

“Guarantor” means each of PVA Holding, PVA Oil & Gas, PVA Texas, and each other Material Domestic Subsidiary that guarantees the Obligations pursuant to Section 6.1.9, and its successors and assigns.

“Guaranty” means the Amended and Restated Subsidiary Guaranty made pursuant to Section 4.1(i) or Section 6.1.9 by the Guarantors in favor of the Administrative Agent, substantially in the form of Exhibit F, as amended, supplemented, restated or otherwise modified from time to time in accordance with the terms of this Agreement and the other Loan Documents.

“Hazardous Material” means all explosive or radioactive substances or wastes and all hazardous or toxic substances, wastes or other pollutants, asbestos or asbestos containing materials, polychlorinated biphenyls, radon gas, infectious or medical wastes and all other substances or wastes of any nature regulated pursuant to any Environmental Law, and any petroleum, petroleum products or petroleum distillates and associated oil or natural gas exploration, production and development wastes that are not exempted or excluded from being defined as “hazardous substances”, “hazardous materials”, “hazardous wastes” and “toxic substances” under such Environmental Laws.

“Highest Lawful Rate” shall mean, on any day, the maximum nonusurious rate of interest permitted for that day by whichever of applicable federal or state law permits the higher interest rate, stated as a rate per annum. On each day, if any, that Chapter 303 of the Texas Finance Code, as amended (formerly Tex. Rev. Civ. Stat. Ann. Art. 5069-1D.003) establishes the Highest Lawful Rate, such rate shall be the “indicated (weekly) rate ceiling” (as defined in Chapter 303 of the Texas Finance Code, as amended) for that day.

“Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“Indebtedness” means, for any Person the sum of the following (without duplication): (i) all obligations of such Person for borrowed money or evidenced by bonds, bankers’ acceptances, debentures, notes or other similar instruments; (ii) all obligations of such Person (whether contingent or otherwise) in respect of letters of credit, surety or other bonds and similar instruments; (iii) all obligations of such Person to pay the deferred purchase price of Property or

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services (other than for borrowed money); (iv) all Capital Lease Obligations; (v) all obligations under Synthetic Leases; (vi) all Indebtedness (as described in the other clauses of this definition) of others secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; (vii) all Indebtedness (as described in the other clauses of this definition) of others guaranteed by such Person or in which such Person otherwise assures a creditor against loss of the debtor to the extent of the lesser of the amount of such Indebtedness and the maximum stated amount of such guarantee or assurance against loss; (viii) all obligations or undertakings of such Person to maintain or cause to be maintained the financial position or covenants of others or to purchase the Indebtedness or Property of others; (ix) obligations to deliver goods or services including Hydrocarbons in consideration of advance payments, including, without limitation, obligations under Advance Payment Contracts; (x) obligations to pay for goods or services whether or not such goods or services are actually received or utilized by such Person; (xi) any Indebtedness of a partnership for which such Person is liable either by agreement or because of a Governmental Requirement but only to the extent of such liability; (xii) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment; and (xiii) Net Mark-to-Market Exposure.

“Initial Reserve Report” is defined in Section 4.1(xi).

“Interest Expense” means, for any period, the sum (determined without duplication) of the aggregate amount of interest expense paid (or payable) in cash during such period on Indebtedness of the Borrower and its Consolidated Restricted Subsidiaries (including the interest portion of payments under Capital Leases and Synthetic Leases).

“Interest Period” means, with respect to a Eurodollar Advance, a period of one, two, three or six months commencing on a Business Day selected by the Borrower pursuant to this Agreement. Such Interest Period shall end on the day which corresponds numerically to such date one, two, three or six months thereafter, provided, however, that if there is no such numerically corresponding day in such next, second, third or sixth succeeding month, such Interest Period shall end on the last Business Day of such next, second, third or sixth succeeding month. If an Interest Period would otherwise end on a day which is not a Business Day, such Interest Period shall end on the next succeeding Business Day, provided, however, that if said next succeeding Business Day falls in a new calendar month, such Interest Period shall end on the immediately preceding Business Day.

“Investment” means, for any Person: (i) the acquisition (whether for cash, Property, services or securities or otherwise) of equity interests of any other Person or any agreement to make any such acquisition (including, without limitation, any “short sale” or any sale of any securities at a time when such securities are not owned by the Person entering into such short sale), (ii) the making of any deposit with, or advance, loan or other extension of credit to, any other Person (including the purchase of Property from another Person subject to an understanding or agreement, contingent or otherwise, to resell such Property to such Person, but excluding any such advance, loan or extension of credit having a term not exceeding ninety (90) days representing the purchase price of inventory or supplies sold by such Person in the ordinary course of business), or (iii) the entering into of any guarantee of, or other contingent obligation with respect to, Indebtedness or other liability of any other Person and (without duplication) any amount committed to be advanced, lent or extended to such Person.

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“Joint Bookrunner” means each of Bank One Capital Markets, Inc. and Wachovia Capital Markets, LLC, in its capacity as Joint Bookrunner.

“LC Fee” is defined in Section 2.19.4.

“LC Issuer” means Bank One (or any subsidiary or affiliate of Bank One designated by Bank One) in its capacity as issuer of Facility LCs hereunder.

“LC Obligations” means, at any time, the sum, without duplication, of (i) the aggregate undrawn stated amount under all Facility LCs outstanding at such time, plus (ii) the aggregate unpaid amount at such time of all Reimbursement Obligations.

“LC Payment Date” is defined in Section 2.19.5.

“Lender” means each of the lending institutions listed on the signature pages of this Agreement or which becomes a signatory hereto as provided in Section 2.5 or Section 12.3.

“Lender Party Rate Management Transaction” means any Rate Management Transaction between the Borrower or any Restricted Subsidiary, on the one hand, and any Lender or any Affiliate of a Lender, on the other.

“Lending Installation” means, with respect to a Lender or the Administrative Agent, the office, branch, subsidiary or affiliate of such Lender or the Administrative Agent listed on the signature pages hereof or on a Schedule or otherwise selected by such Lender or the Administrative Agent pursuant to Section 2.17.

“Lien” means any interest in Property securing an obligation owed to, or a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including but not limited to (i) the lien or security interest arising from a mortgage, encumbrance or pledge, security agreement, conditional sale or trust receipt or a lease, Capital Lease, consignment or bailment for security purposes or (ii) production payments and the like payable out of Oil and Gas Properties. The term “Lien” shall include reservations, exceptions, encroachments, easements, rights of way, covenants, conditions, restrictions, leases and other title exceptions and encumbrances affecting Property.

“Loan” means, with respect to a Lender, such Lender’s loan made pursuant to Article II (or any conversion or continuation thereof).

“Loan Documents” means this Agreement, the Facility LC Applications, the Facility LCs, the Collateral Documents, any Notes issued pursuant to Section 2.13, the Subordination Agreements, any documents evidencing a Lender Party Rate Management Transaction, all applications, all instruments, certificates and agreements now or hereafter executed or delivered to the Administrative Agent or any Lender pursuant to any of the foregoing, and all amendments, modifications, renewals, extensions, increases and rearrangements of, and substitutions for, any of the foregoing.

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“Loan Party” means the Borrower, each Guarantor and their respective successors and permitted assigns.

“Material Adverse Effect” means a material adverse effect on (i) the business, Property, condition (financial or otherwise) or results of operations of the Borrower and its Restricted Subsidiaries taken as a whole, (ii) the ability of the Borrower and its Restricted Subsidiaries taken as a whole to timely perform their obligations under the Loan Documents to which each is a party, or (iii) the legality, validity or enforceability of any of the Loan Documents or the rights, benefits or remedies of the Administrative Agent, the LC Issuer or the Lenders thereunder.

“Material Domestic Subsidiary” means as of any date, any Domestic Subsidiary that (i) is a wholly-owned Restricted Subsidiary and (ii) together with its Restricted Subsidiaries, owns Property having a Fair Market Value of $5,000,000 or more.

“MLP” means Penn Virginia Resource Partners, L.P., a Delaware limited partnership.

“Modify” and “Modification” are defined in Section 2.19.1.

“Moody’s” means Moody’s Investors Service, Inc.

“Mortgage” means each Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing assigned and amended pursuant to the Assignment of Secured Indebtedness and the Mortgage Assignment and Amendment, any mortgage or deed of trust executed and delivered by each of the Borrower and its Restricted Subsidiaries hereunder, including pursuant to Section 6.1.9, and each mortgage supplement after execution and delivery of such mortgage supplement, in each case, as amended, supplemented, restated or otherwise modified from time to time in accordance with the terms of this Agreement and the other Loan Documents.

“Mortgage Assignment and Amendment” means each Assignment and Amendment of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing, in each case, delivered pursuant to Section 4.1 by the Borrower or any Loan Party as amended, supplemented, restated or otherwise modified from time to time in accordance with the terms of this Agreement and the other Loan Documents.

“Mortgaged Property” means the Property owned by the Borrower or any Guarantor and which is subject to the Liens existing and to exist under the terms of the Collateral Documents.

“Multiemployer Plan” means a Plan defined as such in Section 3(37) or 4001(a)(3) of ERISA.

“Net Mark-to-Market Exposure” of a Person means, as of any date of determination, the excess (if any) of all unrealized losses over all unrealized profits of such Person arising from Rate Management Transactions. “Unrealized losses” means the fair market value of the cost to such Person of replacing such Rate Management Transaction as of the date of determination

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(assuming the Rate Management Transaction were to be terminated as of that date), and “unrealized profits” means the fair market value of the gain to such Person of replacing such Rate Management Transaction as of the date of determination (assuming such Rate Management Transaction were to be terminated as of that date). All such determinations shall be made in accordance with GAAP.

“Non-U.S. Lender” is defined in Section 3.5(iv).

“Note” is defined in Section 2.13.

“Obligations” means all unpaid principal of and accrued and unpaid interest on the Loans, all Reimbursement Obligations, all accrued and unpaid fees and all expenses, reimbursements, indemnities and other obligations of the Borrower or any Guarantor to the Lenders or to any Lender, the Administrative Agent, the LC Issuer or any indemnified party arising under the Loan Documents.

“Oil and Gas Properties” means Hydrocarbon Interests; the Properties now or hereafter pooled or unitized with Hydrocarbon Interests; all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; all operating agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, the lands covered thereby and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests; and all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“Organic Documents” means, relative to any Person, its articles of organization, association, formation or incorporation (or comparable document), its by-laws, memorandum of association or operating agreement and all partnership agreements, limited liability company or operating agreements and similar arrangements applicable to ownership.

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“Other Taxes” is defined in Section 3.5(ii).

“Outstanding Credit Exposure” means, as to any Lender at any time, the sum of (i) the aggregate principal amount of its Loans outstanding at such time, plus (ii) an amount equal to its Pro Rata Share of the LC Obligations at such time.

“Participants” is defined in Section 12.2.1.

“Payment Date” means the last day of each quarter.

“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

“Person” means any natural person, corporation, firm, joint venture, partnership, limited liability company, association, enterprise, trust or other entity or organization, or any government or political subdivision or any agency, department or instrumentality thereof.

“Plan” means any employee pension benefit plan, as defined in Section 3(2) of ERISA, which is subject to Title IV of ERISA or which is intended to be qualified under Section 401(a) of the Code, excluding any such Plan which is a Multiemployer Plan, and which (i) is currently or hereafter sponsored, maintained or contributed to by the Borrower or an ERISA Affiliate or (ii) was at any time during the preceding six calendar years sponsored, maintained or contributed to, by the Borrower or an ERISA Affiliate.

“Pledge Agreement” means an Amended and Restated Pledge Agreement and Irrevocable Proxy made pursuant to Section 4.1 or Section 6.1.9 by a Pledgor in favor of the Administrative Agent, substantially in the form of Exhibit G, as amended, supplemented, restated or otherwise modified from time to time in accordance with the terms of this Agreement and the other Loan Documents. The term “Pledge Agreement” shall include each and every Pledge Agreement executed and delivered by a Pledgor hereunder.

“Pledgor” means each of Borrower, PVA Holding, PVA Oil & Gas, and each other Material Domestic Subsidiary that executes and delivers a Pledge Agreement pursuant to Section 6.1.9, and its successors and assigns.

“Pricing Schedule” means the Schedule attached hereto identified as such.

“Prime Rate” means a rate per annum equal to the prime rate of interest announced from time to time by Bank One or its parent (which is not necessarily the lowest rate charged to any customer), changing when and as said prime rate changes.

“Prior Credit Agreement” is defined in the first recital.

“Prior Lenders” is defined in the first recital.

“Pro Rata Share” means, with respect to a Lender, a portion equal to a fraction the numerator of which is such Lender’s Commitment and the denominator of which is the Aggregate Commitment.

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“Property” of a Person means any and all property, whether real, personal, tangible, intangible, or mixed, of such Person, or other assets owned, leased or operated by such Person.

“Proved Developed Producing Hydrocarbon Reserves” shall mean those Proved Hydrocarbon Reserves which are recoverable from completion intervals currently open and producing to market. Improved recovery reserves are considered to be producing only after an improved recovery project has been installed and is in operation.

“Proved Hydrocarbon Reserves” shall mean those recoverable Hydrocarbons which have been proved to a high degree of certainty by reason of existing production, adequate testing, or in certain cases by adequate core data and other engineering and geologic information on zones which are present in existing wells or in known reservoirs. Reserves that can be produced economically through the application of established improved recovery techniques are included in the proved classification when (i) successful testing by a pilot project or the operation of any installed program in that reservoir or one in the immediate area with similar rock and fluid properties provides support for the engineering analysis on which the project or program was based, and (ii) it is reasonably certain the project will proceed. Reserves to be recovered by improved recovery techniques that have yet to be established through repeated economically successful applications are included in the proved category only after successful testing by a pilot project or after the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based. Improved recovery includes all methods for supplement natural reservoir including (a) pressure maintenance, (b) cycling and (c) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids.

“Purchasers” is defined in Section 12.3.1.

“PVA Holding” means Penn Virginia Holding Corp., a Delaware corporation.

“PVA Oil & Gas” means Penn Virginia Oil & Gas Corporation, a Virginia corporation.

“PVA Texas” means Penn Virginia Oil & Gas Corporation, a Texas corporation.

“Rate Management Transaction” means any transaction (including an agreement with respect thereto) now existing or hereafter entered into that is a rate swap, basis swap, forward rate transaction, commodity swap, commodity option, equity or equity index swap, equity or equity index option, bond option, interest rate option, foreign exchange transaction, cap transaction, floor transaction, collar transaction, forward transaction, currency swap transaction, cross-currency rate swap transaction, currency option or any other similar transaction (including any option with respect to any of these transactions) or any combination thereof, whether linked to one or more interest rates, foreign currencies, commodity prices, equity prices or other financial measures.

“Rate Management Obligations” of a Person means any and all obligations of such Person, whether absolute or contingent and howsoever and whensoever created, arising, evidenced or acquired (including all renewals, extensions and modifications thereof and substitutions therefor), under (i) any and all Rate Management Transactions, and (ii) any and all cancellations, buy backs, reversals, terminations or assignments of any Rate Management Transactions.

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“Redetermination Date” means the date that the redetermined Borrowing Base becomes effective subject to the notice requirements specified in Section 2.21(ii) both for scheduled redeterminations and unscheduled redeterminations.

“Regulation D” means Regulation D of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor thereto or other regulation or official interpretation of said Board of Governors relating to reserve requirements applicable to member banks of the Federal Reserve System.

“Regulation U” means Regulation U of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor or other regulation or official interpretation of said Board of Governors relating to the extension of credit by banks for the purpose of purchasing or carrying margin stocks applicable to member banks of the Federal Reserve System.

“Reimbursement Obligations” means, at any time, the aggregate of all obligations of the Borrower then outstanding under Section 2.19 to reimburse the LC Issuer for amounts paid by the LC Issuer in respect of any one or more drawings under Facility LCs.

“Reportable Event” means a reportable event as defined in Section 4043 of ERISA and the regulations issued under such section, with respect to a Plan, excluding, however, such events as to which the PBGC has by regulation waived the requirement of Section 4043(a) of ERISA that it be notified within 30 days of the occurrence of such event, provided, however, that a failure to meet the minimum funding standard of Section 412 of the Code and of Section 302 of ERISA shall be a Reportable Event regardless of the issuance of any such waiver of the notice requirement in accordance with either Section 4043(a) of ERISA or Section 412(d) of the Code.

“Reports” is defined in Section 9.6.

“Required Lenders” means Lenders in the aggregate having at least sixty-six and two-thirds percent (66 ²/3%) of the Aggregate Commitment or, if the Aggregate Commitment has been terminated, Lenders in the aggregate holding at least sixty-six and two-thirds percent (66 ²/3%) of the Aggregate Outstanding Credit Exposure.

“Reserve Report” means a report, in form and substance satisfactory to the Administrative Agent, setting forth, as of each January 1 or July 1 (or such other date in the event of an unscheduled redetermination) the oil and gas reserves attributable to the Oil and Gas Properties of the Borrower and the Restricted Subsidiaries, together with a projection of the rate of production and future net income, taxes, operating expenses and capital expenditures with respect thereto as of such date, based upon the pricing assumptions consistent with SEC reporting requirements at the time.

“Reserve Requirement” means, with respect to an Interest Period, the maximum aggregate reserve requirement (including all basic, supplemental, marginal and other reserves) which is imposed under Regulation D on Eurocurrency liabilities.

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“Restricted Subsidiary” means, as of any date, any Subsidiary that is not designated as an Unrestricted Subsidiary either (i) on Schedule 5.14 or (ii) in the manner set forth in Section 6.2.6(ii). As of the Closing Date, the Restricted Subsidiaries are designated on Schedule 5.14 as such.

“S&P” means Standard and Poor’s Ratings Services, a division of The McGraw Hill Companies, Inc.

“Schedule” refers to a specific schedule to this Agreement, unless another document is specifically referenced.

“Scheduled Redetermination Date” means April 1st and October 1st of each year on which the Borrowing Base is scheduled for redetermination under Section 2.21, commencing April 1, 2004.

“SEC” means the Securities and Exchange Commission or any successor Governmental Authority.

“Section” means a numbered section of this Agreement, unless another document is specifically referenced.

“Subordination Agreement” means each Subordination Agreement made pursuant to Section 4.1(v) by certain Unrestricted Subsidiaries of the Borrower or made pursuant to Section 6.2.2(vi)(2) by other Subsidiaries of the Borrower that are not Guarantors in favor of the Agents, the LC Issuer and the Lenders, substantially in the form of Exhibit H, as amended, supplemented, restated or otherwise modified from time to time in accordance with the terms of this Agreement and the other Loan Documents.

“Stated Rate” is defined in Section 2.20(a).

“Subsidiary” of a Person means (i) any corporation more than fifty percent (50%) of the outstanding securities having ordinary voting power of which shall at the time be owned or controlled, directly or indirectly, by such Person or by one or more of its Subsidiaries or by such Person and one or more of its Subsidiaries, or (ii) any partnership, limited liability company, association, joint venture or similar business organization more than fifty percent (50%) of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower.

“Syndication Agent” means Wachovia Bank, National Association in its capacity as contractual representative of the Lenders, and not in its individual capacity as a Lender, and any successor Syndication Agent.

“Synthetic Leases” means, in respect of any Person, all leases which shall have been, or should have been, in accordance with GAAP, treated as operating leases on the financial statements of the Person liable (whether contingently or otherwise) for the payment of rent thereunder and which were properly treated as indebtedness for borrowed money for purposes of U.S. federal income taxes, if the lessee in respect thereof is obligated to either purchase for an

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amount in excess of, or pay upon early termination an amount in excess of, 85% of the residual value of the Property subject to such operating lease upon expiration or early termination of such lease.

“Taxes” means any and all present or future taxes, duties, levies, imposts, deductions, charges or withholdings, and any and all liabilities with respect to the foregoing, but excluding Excluded Taxes and Other Taxes.

“Total Debt” means all Indebtedness of the Borrower and its Restricted Subsidiaries on a consolidated basis described under clauses (i) through (xii) of the definition of “Indebtedness”.

“Transferee” is defined in Section 12.4.

“Type” means, with respect to any Advance, its nature as a Floating Rate Advance or a Eurodollar Advance and with respect to any Loan, its nature as a Floating Rate Loan or a Eurodollar Loan.

“Unmatured Default” means an event which but for the lapse of time or the giving of notice, or both, would constitute a Default.

“Unrestricted Subsidiary” means Penn Virginia Resource GP, LLC, a Delaware limited liability company, Penn Virginia Resource LP Corp., a Delaware corporation, Kanawa Rail Corp., a Virginia corporation, Penn Virginia Technology, Inc., a Delaware corporation, EnerSearch, Inc., a Virginia corporation, each of their respective Subsidiaries, and any other Subsidiary of Borrower that is designated either (i) on Schedule 5.14 or (ii) in the manner set forth in Section 6.2.6. As of the Closing Date, the Unrestricted Subsidiaries are designated on Schedule 5.14 as such.

“Wholly-Owned Subsidiary” of a Person means (i) any Subsidiary all of the outstanding voting securities of which shall at the time be owned or controlled, directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of such Person, or (ii) any partnership, limited liability company, association, joint venture or similar business organization one hundred percent (100%) of the ownership interests having ordinary voting power of which shall at the time be so owned or controlled.

1.2. Terms Generally. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise (i) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (ii) any reference herein to any Person shall be construed to include such Person’s successors and assigns, provided such successors and assigns are permitted by the Loan Documents, and (iii) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof.

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ARTICLE II

THE CREDITS

2.1. Commitment. From and including the date of this Agreement and prior to the Facility Termination Date, each Lender severally agrees, on the terms and conditions set forth in this Agreement, to (i) make Loans to the Borrower and (ii) participate in Facility LCs issued upon the request of the Borrower, in an amount not to exceed at any time outstanding the lesser of (x) the Commitment of such Lender or (y) the Pro Rata Share of such Lender of the Borrowing Base then in effect, provided that, after giving effect to the making of each such Loan and the issuance of each such Facility LC, such Lender’s Outstanding Credit Exposure shall not exceed its Commitment. Subject to the terms of this Agreement, the Borrower may borrow, repay and reborrow at any time prior to the Facility Termination Date. The Commitments to extend credit hereunder shall expire on the Facility Termination Date. The LC Issuer will issue Facility LCs hereunder on the terms and conditions set forth in Section 2.19.

2.2. Required Payments; Termination. The Aggregate Outstanding Credit Exposure and all other unpaid Obligations shall be paid in full by the Borrower on the Facility Termination Date.

2.3. Ratable Loans. Each Advance hereunder shall consist of Loans made from the several Lenders ratably according to their Pro Rata Shares.

2.4. Types of Advances. The Advances may be Floating Rate Advances or Eurodollar Advances, or a combination thereof, selected by the Borrower in accordance with Sections 2.8 and 2.9.

2.5. Commitment Fee; Increases and Reductions in Aggregate Commitment.

(i) The Borrower agrees to pay to the Administrative Agent for the account of each Lender according to its Pro Rata Share a commitment fee at a per annum rate equal to the Applicable Fee Rate on the average daily Available Aggregate Commitment from the date hereof to and including the Facility Termination Date, payable on each Payment Date hereafter and on the Facility Termination Date. All accrued commitment fees shall be payable on the effective date of any termination of the obligations of the Lenders to make Credit Extensions hereunder.

(ii) The Borrower shall have the right, with the prior written consent of the Administrative Agent (provided that such consent shall not be unreasonably withheld or delayed), to increase the Aggregate Commitment; provided that notwithstanding anything to the contrary in this Agreement, (a) the Aggregate Commitment after giving effect to such proposed increase or increases shall not exceed the lesser of (1) the Borrowing Base then in effect, and (2) $300,000,000, (b) each Lender shall be offered a Pro Rata Share of such proposed increase, (c) no Default or Unmatured Default shall have occurred and be continuing at the effective date of such proposed increase, (d) on the effective date of such increase, no Eurodollar Loans shall be outstanding (or if any Eurodollar Loans are outstanding, the effective date of such increase shall

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be the last day of the Interest Period in respect of such Eurodollar Loans), (e) no Lender’s Commitment may be increased or decreased without the consent of such Lender and (f) if necessary, other eligible financial institutions may become Lenders to accommodate such proposed increase.

If the Borrower desires to effect an increase in the Aggregate Commitment, the Borrower and the financial institution(s) that the Borrower proposes to become a Lender hereunder, and, if applicable, the existing Lender(s) that the Borrower proposes to increase its existing Commitment shall (subject at all times to the consent of each such financial institution or each such existing Lender, as applicable) execute and deliver to the Administrative Agent a certificate substantially in the form of Exhibit D hereto (an “Additional Lender Certificate”). Upon receipt of such Additional Lender Certificate, if the Administrative Agent consents to the proposed increase in the Aggregate Commitment: (1) the amount of the Aggregate Commitment shall be so increased, (2) the Administrative Agent shall amend and distribute to the Borrower and the Lenders a revised schedule of Commitments for each Lender adding or amending, as applicable, the Commitment of any Lender executing the Additional Lender Certificate and the revised Pro Rata Shares of the Lenders, (3) any such additional Lender shall be deemed to be a party in all respect to this Agreement and the other Loan Documents as of the effective date set forth in such Additional Lender Certificate and (4) upon the effective date set forth in such Additional Lender Certificate, any such Lender party to the Additional Lender Certificate shall purchase a pro rata portion of the outstanding Loans (and participation interests in Facility LCs) of each of the current Lenders such that the Lenders (including any additional Lender, if applicable) shall hold their Pro Rata Share of the outstanding Loans (and participation interests) as reflected in the revised schedule of Commitments required by this Section 2.5(ii). If the Administrative Agent does not consent to the increase in the Aggregate Commitment in accordance with this Section 2.5(ii), the Commitment shall remain unchanged.

(iii) The Borrower shall have the right to permanently reduce the Aggregate Commitment in whole, or in part ratably among the Lenders in integral multiples of $5,000,000, upon at least three Business Days’ written notice to the Administrative Agent, which notice shall specify the amount of any such reduction, provided, however, that the amount of the Aggregate Commitment may not be reduced below the Aggregate Outstanding Credit Exposure.

2.6. Minimum Amount of Each Advance. Each Eurodollar Advance shall be in the minimum amount of $1,000,000 (and in multiples of $500,000 if in excess thereof), and each Floating Rate Advance shall be in the minimum amount of $500,000 (and in multiples of $100,000 if in excess thereof), provided, however, that any Floating Rate Advance may be in the amount of the Available Aggregate Commitment.

2.7. Prepayments.

2.7.1. Optional Payments. The Borrower may from time to time pay, without penalty or premium, all outstanding Floating Rate Advances, or, in a minimum aggregate amount of $1,000,000 or any integral multiple of $1,000,000 in excess thereof, any portion of the outstanding Floating Rate Advances upon one Business Day’s prior notice to the Administrative Agent. The Borrower may from time to time pay, subject to the payment of any funding indemnification amounts required by Section 3.4 but without penalty or premium, all outstanding

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Eurodollar Advances, or, in a minimum aggregate amount of $1,000,000 or any integral multiple of $1,000,000 in excess thereof, any portion of the outstanding Eurodollar Advances upon three Business Days’ prior notice to the Administrative Agent.

2.7.2. Mandatory Payments. If at any time the Aggregate Outstanding Credit Exposure exceeds the Borrowing Base then in effect (whether as a result of any adjustment or redetermination of the Borrowing Base in accordance with Sections 2.21, 6.1.8(iv) or 6.2.11 or otherwise), the Borrower shall (a) prepay the Loans in an aggregate principal amount equal to the excess, together with interest on the principal amount paid accrued to the date of such prepayment and any funding indemnification amounts required by Section 3.4, and (b) if a Borrowing Base Deficiency remains after prepaying all of the Loans as a result of LC Obligations, pay to the Administrative Agent on behalf of the Lenders an amount equal to such Borrowing Base Deficiency to be held as cash collateral in a special collateral account as provided in Section 2.19.11. The Borrower shall be obligated to make such prepayment and/or deposit of cash collateral within sixty (60) days following its receipt of written notice from the Administrative Agent of any Borrowing Base Deficiency.

2.8. Method of Selecting Types and Interest Periods for New Advances. The Borrower shall select the Type of Advance and, in the case of each Eurodollar Advance, the Interest Period applicable thereto from time to time. The Borrower shall give the Administrative Agent irrevocable notice (a “Borrowing Notice”) not later than 10:00 a.m. (Chicago time) at least one Business Day before the Borrowing Date of each Floating Rate Advance and three Business Days before the Borrowing Date for each Eurodollar Advance, specifying: (i) the Borrowing Date, which shall be a Business Day, of such Advance, (ii) the aggregate amount of such Advance, (iii) the Type of Advance selected, and (iv) in the case of each Eurodollar Advance, the Interest Period applicable thereto. Not later than noon (Chicago time) on each Borrowing Date, each Lender shall make available its Loan or Loans in funds immediately available in Chicago to the Administrative Agent at its address specified pursuant to Article XIII. The Administrative Agent will make the funds so received from the Lenders available to the Borrower at the Administrative Agent’s aforesaid address.

2.9. Conversion and Continuation of Outstanding Advances. Floating Rate Advances shall continue as Floating Rate Advances unless and until such Floating Rate Advances are converted into Eurodollar Advances pursuant to this Section 2.9 or are repaid in accordance with Section 2.7. Each Eurodollar Advance shall continue as a Eurodollar Advance until the end of the then applicable Interest Period therefor, at which time such Eurodollar Advance shall be automatically converted into a Floating Rate Advance unless (x) such Eurodollar Advance is or was repaid in accordance with Section 2.7 or (y) the Borrower shall have given the Administrative Agent a Conversion/Continuation Notice (as defined below) requesting that, at the end of such Interest Period, such Eurodollar Advance continue as a Eurodollar Advance for the same or another Interest Period. Subject to the terms of Section 2.6, the Borrower may elect from time to time to convert all or any part of a Floating Rate Advance into a Eurodollar Advance. The Borrower shall give the Administrative Agent irrevocable notice (a “Conversion/Continuation Notice”) of each conversion of a Floating Rate Advance into a Eurodollar Advance or continuation of a Eurodollar Advance not later than 10:00 a.m. (Chicago time) at least three Business Days prior to the date of the requested conversion or continuation, specifying: (i) the requested date, which shall be a Business Day, of such conversion or

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continuation, (ii) the aggregate amount and Type of the Advance which is to be converted or continued, and (iii) the amount of such Advance which is to be converted into or continued as a Eurodollar Advance and the duration of the Interest Period applicable thereto.

2.10. Changes in Interest Rate, etc. Each Floating Rate Advance shall bear interest on the outstanding principal amount thereof, for each day from and including the date such Advance is made or is automatically converted from a Eurodollar Advance into a Floating Rate Advance pursuant to Section 2.9, to but excluding the date it is paid or is converted into a Eurodollar Advance pursuant to Section 2.9 hereof, at a rate per annum equal to the Floating Rate for such day. Changes in the rate of interest on that portion of any Advance maintained as a Floating Rate Advance will take effect simultaneously with each change in the Alternate Base Rate. Each Eurodollar Advance shall bear interest on the outstanding principal amount thereof from and including the first day of the Interest Period applicable thereto to (but not including) the last day of such Interest Period at the interest rate determined by the Administrative Agent as applicable to such Eurodollar Advance based upon the Borrower’s selections under Sections 2.8 and 2.9 and otherwise in accordance with the terms hereof. No Interest Period may end after the Facility Termination Date.

2.11. Rates Applicable After Default. Notwithstanding anything to the contrary contained in Section 2.8, 2.9 or 2.10, during the continuance of a Default or Unmatured Default the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that no Advance may be made as, converted into or continued as a Eurodollar Advance. During the continuance of a Default the Required Lenders may, at their option, by notice to the Borrower (which notice may be revoked at the option of the Required Lenders notwithstanding any provision of Section 8.2 requiring unanimous consent of the Lenders to changes in interest rates), declare that (i) each Eurodollar Advance shall bear interest for the remainder of the applicable Interest Period at the rate otherwise applicable to such Interest Period plus two percent (2%) per annum, (ii) each Floating Rate Advance shall bear interest at a rate per annum equal to the Floating Rate in effect from time to time plus two percent (2%) per annum and (iii) the LC Fee shall be increased by two percent (2%) per annum, provided that, during the continuance of a Default under Section 7.1(vi) or 7.1(vii), the interest rates set forth in clauses (i) and (ii) above and the increase in the LC Fee set forth in clause (iii) above shall be applicable to all Credit Extensions without any election or action on the part of the Administrative Agent or any Lender.

2.12. Method of Payment. All payments of the Obligations hereunder shall be made, without setoff, deduction, or counterclaim, in immediately available funds to the Administrative Agent at the Administrative Agent’s address specified pursuant to Article XIII, or at any other Lending Installation of the Administrative Agent specified in writing by the Administrative Agent to the Borrower, by noon (local time) on the date when due and shall (except in the case of Reimbursement Obligations for which the LC Issuer has not been fully indemnified by the Lenders, or as otherwise specifically required hereunder) be applied ratably by the Administrative Agent among the Lenders. Each payment delivered to the Administrative Agent for the account of any Lender shall be delivered promptly by the Administrative Agent to such Lender in the same type of funds that the Administrative Agent received at its address specified pursuant to Article XIII or at any Lending Installation specified in a notice received by the

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Administrative Agent from such Lender. The Administrative Agent is hereby authorized to charge the account of the Borrower maintained with Bank One for each payment of principal, interest, Reimbursement Obligations and fees as it becomes due hereunder. Each reference to the Administrative Agent in this Section 2.12 shall also be deemed to refer, and shall apply equally, to the LC Issuer, in the case of payments required to be made by the Borrower to the LC Issuer pursuant to Section 2.19.6.

2.13. Noteless Agreement; Evidence of Indebtedness. (i) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

(ii) The Administrative Agent shall also maintain accounts in which it will record (a) the amount of each Loan made hereunder, the Type thereof and the Interest Period with respect thereto, (b) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender hereunder, (c) the original stated amount of each Facility LC and the amount of LC Obligations outstanding at any time, and (d) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender’s share thereof.

(iii) The entries maintained in the accounts maintained pursuant to paragraphs (i) and (ii) above shall be prima facie evidence of the existence and amounts of the Obligations therein recorded; provided, however, that the failure of the Administrative Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of the Borrower to repay the Obligations in accordance with their terms.

(iv) Any Lender may request that its Loans be evidenced by a promissory note (a “Note”). In such event, the Borrower shall prepare, execute and deliver to such Lender a Note payable to the order of such Lender in a form supplied by the Administrative Agent. Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (prior to any assignment pursuant to Section 12.3) be represented by one or more Notes payable to the order of the payee named therein, except to the extent that any such Lender subsequently returns any such Note for cancellation and requests that such Loans once again be evidenced as described in paragraphs (i) and (ii) above.

2.14. Telephonic Notices. The Borrower hereby authorizes the Lenders and the Administrative Agent to extend, convert or continue Advances, effect selections of Types of Advances and to transfer funds based on telephonic notices made by any person or persons the Administrative Agent or any Lender in good faith believes to be acting on behalf of the Borrower, it being understood that the foregoing authorization is specifically intended to allow Borrowing Notices and Conversion/Continuation Notices to be given telephonically. The Borrower agrees to deliver promptly to the Administrative Agent a written confirmation, if such confirmation is requested by the Administrative Agent or any Lender, of each telephonic notice signed by an Authorized Officer. If the written confirmation differs in any material respect from the action taken by the Administrative Agent and the Lenders, the records of the Administrative Agent and the Lenders shall govern absent manifest error.

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2.15. Interest Payment Dates; Interest and Fee Basis. Interest accrued on each Floating Rate Advance shall be payable on each Payment Date, commencing with the first such date to occur after the date hereof, on any date on which the Floating Rate Advance is prepaid, whether due to acceleration or otherwise, and at maturity. Interest accrued on that portion of the outstanding principal amount of any Floating Rate Advance converted into a Eurodollar Advance on a day other than a Payment Date shall be payable on the date of conversion. Interest accrued on each Eurodollar Advance shall be payable on the last day of its applicable Interest Period, on any date on which the Eurodollar Advance is prepaid, whether by acceleration or otherwise, and at maturity. Interest accrued on each Eurodollar Advance having an Interest Period longer than three months shall also be payable on the last day of each three-month interval during such Interest Period. Interest and commitment fees for Eurodollar Advances and LC Fees shall be calculated for actual days elapsed on the basis of a 360-day year. Interest and commitment fees for Floating Rate Advances shall be calculated for actual days elapsed on the basis of a 365-day, or where appropriate 366-day, year. Interest shall be payable for the day an Advance is made but not for the day of any payment on the amount paid if payment is received prior to noon (local time) at the place of payment. If any payment of principal of or interest on an Advance shall become due on a day which is not a Business Day, such payment shall be made on the next succeeding Business Day and, in the case of a principal payment, such extension of time shall be included in computing interest in connection with such payment.

2.16. Notification of Advances, Interest Rates, Prepayments and Commitment Reductions. Promptly after receipt thereof, the Administrative Agent will notify each Lender of the contents of each Aggregate Commitment reduction notice, Borrowing Notice, Conversion/Continuation Notice, and repayment notice received by it hereunder. Promptly after notice from the LC Issuer, the Administrative Agent will notify each Lender of the contents of each request for issuance of a Facility LC hereunder. The Administrative Agent will notify each Lender of the interest rate applicable to each Eurodollar Advance promptly upon determination of such interest rate and will give each Lender prompt notice of each change in the Alternate Base Rate.

2.17. Lending Installations. Each Lender may book its Loans and its participation in any LC Obligations and the LC Issuer may book the Facility LCs at any Lending Installation selected by such Lender or the LC Issuer, as the case may be, and may change its Lending Installation from time to time. All terms of this Agreement shall apply to any such Lending Installation and the Loans, Facility LCs, participations in LC Obligations and any Notes issued hereunder shall be deemed held by each Lender or the LC Issuer, as the case may be, for the benefit of any such Lending Installation. Each Lender and the LC Issuer may, by written notice to the Administrative Agent and the Borrower in accordance with Article XIII, designate replacement or additional Lending Installations through which Loans will be made by it or Facility LCs will be issued by it and for whose account Loan payments or payments with respect to Facility LCs are to be made.

2.18. Non-Receipt of Funds by the Administrative Agent. Unless the Borrower or a Lender, as the case may be, notifies the Administrative Agent prior to the date on which it is scheduled to make payment to the Administrative Agent of (i) in the case of a Lender, the proceeds of a Loan or (ii) in the case of the Borrower, a payment of principal, interest or fees to the Administrative Agent for the account of the Lenders, that it does not intend to make such

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payment, the Administrative Agent may assume that such payment has been made. The Administrative Agent may, but shall not be obligated to, make the amount of such payment available to the intended recipient in reliance upon such assumption. If such Lender or the Borrower, as the case may be, has not in fact made such payment to the Administrative Agent, the recipient of such payment shall, on demand by the Administrative Agent, repay to the Administrative Agent the amount so made available together with interest thereon in respect of each day during the period commencing on the date such amount was so made available by the Administrative Agent until the date the Administrative Agent recovers such amount at a rate per annum equal to (x) in the case of payment by a Lender, the Federal Funds Effective Rate for such day for the first three days and, thereafter, the interest rate applicable to the relevant Loan or (y) in the case of payment by the Borrower, the interest rate applicable to the relevant Loan.

2.19. Facility LCs.

2.19.1. Issuance. The LC Issuer hereby agrees, on the terms and conditions set forth in this Agreement, to issue standby and commercial letters of credit (each, a “Facility LC”) and to renew, extend, increase, decrease or otherwise modify each Facility LC (“Modify,” and each such action a “Modification”), from time to time from and including the date of this Agreement and prior to the Facility Termination Date upon the request of the Borrower; provided that immediately after each such Facility LC is issued or Modified, (i) the aggregate amount of the outstanding LC Obligations shall not exceed $20,000,000 and (ii) the Aggregate Outstanding Credit Exposure shall not exceed the Aggregate Commitment. No Facility LC shall have an expiry date later than the earlier of (x) the fifth Business Day prior to the Facility Termination Date and (y) one year after its issuance, provided, however, that any Facility LC with a one-year term may provide for the renewal thereof for additional one-year periods (which shall in no event extend beyond the fifth business day prior to the Facility Termination Date) unless the Issuer provides prior notice of non-renewal to the beneficiary.

2.19.2. Participations. Upon the issuance or Modification by the LC Issuer of a Facility LC in accordance with this Section 2.19, the LC Issuer shall be deemed, without further action by any party hereto, to have unconditionally and irrevocably sold to each Lender, and each Lender shall be deemed, without further action by any party hereto, to have unconditionally and irrevocably purchased from the LC Issuer, a participation in such Facility LC (and each Modification thereof) and the related LC Obligations in proportion to its Pro Rata Share.

2.19.3. Notice. Subject to Section 2.19.1, the Borrower shall give the LC Issuer notice prior to 10:00 a.m. (Chicago time) at least five Business Days prior to the proposed date of issuance or Modification of each Facility LC, specifying the beneficiary, the proposed date of issuance (or Modification) and the expiry date of such Facility LC, and describing the proposed terms of such Facility LC and the nature of the transactions proposed to be supported thereby. Upon receipt of such notice, the LC Issuer shall promptly notify the Administrative Agent, and the Administrative Agent shall promptly notify each Lender, of the contents thereof and of the amount of such Lender’s participation in such proposed Facility LC. The issuance or Modification by the LC Issuer of any Facility LC shall, in addition to the conditions precedent set forth in Article IV (the satisfaction of which the LC Issuer shall have no duty to ascertain), be subject to the conditions precedent that such Facility LC shall be satisfactory to the LC Issuer and that the Borrower shall have executed and delivered such application agreement and/or such

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other instruments and agreements relating to such Facility LC as the LC Issuer shall have reasonably requested (each, a “Facility LC Application”). In the event of any conflict between the terms of this Agreement and the terms of any Facility LC Application, the terms of this Agreement shall control.

2.19.4. LC Fees. The Borrower shall pay to the Administrative Agent, for the account of the Lenders ratably in accordance with their respective Pro Rata Shares, with respect to each standby Facility LC, a letter of credit fee at a per annum rate equal to the Applicable Margin for Eurodollar Loans in effect from time to time (which fee shall be increased by two percent (2%) per annum after the occurrence of an Default) on the average daily undrawn stated amount under such standby Facility LC, such fee to be payable in arrears on each Payment Date beginning with the first Payment Date after such Facility LC is issued (“LC Fee”). The Borrower shall also pay to the LC Issuer for its own account (i) at the time of issuance of each Facility LC, a fronting fee for each Facility LC equal to the greater of (x) $500 or (y) 0.125% per annum on the initial stated amount thereof, such fee to be payable in arrears on each Payment Date beginning with the first Payment Date after such Facility LC is issued, and (ii) documentary and processing charges in connection with the issuance, Modification, cancellation, negotiation or transfer of and draws under Facility LCs in accordance with the LC Issuer’s standard schedule for such charges as in effect from time to time.

2.19.5. Administration; Reimbursement by Lenders. Upon receipt from the beneficiary of any Facility LC of any demand for payment under such Facility LC, the LC Issuer shall notify the Administrative Agent and the Administrative Agent shall promptly notify the Borrower and each other Lender as to the amount to be paid by the LC Issuer as a result of such demand and the proposed payment date (the “LC Payment Date”). The responsibility of the LC Issuer to the Borrower and each Lender shall be only to determine that the documents (including each demand for payment) delivered under each Facility LC in connection with such presentment shall be in conformity in all material respects with such Facility LC. The LC Issuer shall endeavor to exercise the same care in the issuance and administration of the Facility LCs as it does with respect to letters of credit in which no participations are granted, it being understood that in the absence of any gross negligence or willful misconduct by the LC Issuer, each Lender shall be unconditionally and irrevocably liable without regard to the occurrence of any Default or any condition precedent whatsoever, to reimburse the LC Issuer on demand for (i) such Lender’s Pro Rata Share of the amount of each payment made by the LC Issuer under each Facility LC to the extent such amount is not reimbursed by the Borrower pursuant to Section 2.19.6 below, plus (ii) interest on the foregoing amount to be reimbursed by such Lender, for each day from the date of the LC Issuer’s demand for such reimbursement (or, if such demand is made after 11:00 a.m. (Chicago time) on such date, from the next succeeding Business Day) to the date on which such Lender pays the amount to be reimbursed by it, at a rate of interest per annum equal to the Federal Funds Effective Rate for the first three days and, thereafter, at a rate of interest equal to the rate applicable to Floating Rate Advances.

2.19.6. Reimbursement by Borrower. The Borrower shall be irrevocably and unconditionally obligated to reimburse the LC Issuer on or before the applicable LC Payment Date for any amounts to be paid by the LC Issuer upon any drawing under any Facility LC, without presentment, demand, protest or other formalities of any kind; provided that neither the Borrower nor any Lender shall hereby be precluded from asserting any claim for direct (but not

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consequential) damages suffered by the Borrower or such Lender to the extent, but only to the extent, caused by (i) the willful misconduct or gross negligence of the LC Issuer in determining whether a request presented under any Facility LC issued by it complied with the terms of such Facility LC or (ii) the LC Issuer’s failure to pay under any Facility LC issued by it after the presentation to it of a request strictly complying with the terms and conditions of such Facility LC. All such amounts paid by the LC Issuer and remaining unpaid by the Borrower shall bear interest, payable on demand, for each day until paid at a rate per annum equal to (x) the rate applicable to Floating Rate Advances for such day if such day falls on or before the applicable LC Payment Date and (y) the sum of two percent (2%) plus the rate applicable to Floating Rate Advances for such day if such day falls after such LC Payment Date. The LC Issuer will pay to each Lender ratably in accordance with its Pro Rata Share all amounts received by it from the Borrower for application in payment, in whole or in part, of the Reimbursement Obligation in respect of any Facility LC issued by the LC Issuer, but only to the extent such Lender has made payment to the LC Issuer in respect of such Facility LC pursuant to Section 2.19.5. Subject to the terms and conditions of this Agreement (including without limitation the submission of a Borrowing Notice in compliance with Section 2.8 and the satisfaction of the applicable conditions precedent set forth in Article IV), the Borrower may request an Advance hereunder for the purpose of satisfying any Reimbursement Obligation.

2.19.7. Obligations Absolute. The Borrower’s obligations under this Section 2.19 shall be absolute and unconditional under any and all circumstances and irrespective of any setoff, counterclaim or defense to payment which the Borrower may have or have had against the LC Issuer, any Lender or any beneficiary of a Facility LC. The Borrower further agrees with the LC Issuer and the Lenders that the LC Issuer and the Lenders shall not be responsible for, and the Borrower’s Reimbursement Obligation in respect of any Facility LC shall not be affected by, among other things, the validity or genuineness of documents or of any endorsements thereon, even if such documents should in fact prove to be in any or all respects invalid, fraudulent or forged, or any dispute between or among the Borrower, any of its Affiliates, the beneficiary of any Facility LC or any financing institution or other party to whom any Facility LC may be transferred or any claims or defenses whatsoever of the Borrower or of any of its Affiliates against the beneficiary of any Facility LC or any such transferee. The LC Issuer shall not be liable for any error, omission, interruption or delay in transmission, dispatch or delivery of any message or advice, however transmitted, in connection with any Facility LC. The Borrower agrees that any action taken or omitted by the LC Issuer or any Lender under or in connection with each Facility LC and the related drafts and documents, if done without gross negligence or willful misconduct, shall be binding upon the Borrower and shall not put the LC Issuer or any Lender under any liability to the Borrower. Nothing in this Section 2.19.7 is intended to limit the right of the Borrower to make a claim against the LC Issuer for damages as contemplated by the proviso to the first sentence of Section 2.19.6.

2.19.8. Actions of LC Issuer. The LC Issuer shall be entitled to rely, and shall be fully protected in relying, upon any Facility LC, draft, writing, resolution, notice, consent, certificate, affidavit, letter, cablegram, telegram, telecopy, telex or teletype message, statement, order or other document believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons, and upon advice and statements of legal counsel, independent accountants and other experts selected by the LC Issuer. The LC Issuer shall be fully justified in failing or refusing to take any action under this Agreement unless it shall first

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have received such advice or concurrence of the Required Lenders as it reasonably deems appropriate or it shall first be indemnified to its reasonable satisfaction by the Lenders against any and all liability and expense which may be incurred by it by reason of taking or continuing to take any such action. Notwithstanding any other provision of this Section 2.19, the LC Issuer shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement in accordance with a request of the Required Lenders, and such request and any action taken or failure to act pursuant thereto shall be binding upon the Lenders and any future holders of a participation in any Facility LC.

2.19.9. Indemnification. The Borrower hereby agrees to indemnify and hold harmless each Lender, the LC Issuer and each Agent, and their respective directors, officers, agents and employees from and against any and all claims and damages, losses, liabilities, costs or expenses which such Lender, the LC Issuer or such Agent may incur (or which may be claimed against such Lender, the LC Issuer or such Agent by any Person whatsoever) by reason of or in connection with the issuance, execution and delivery or transfer of or payment or failure to pay under any Facility LC or any actual or proposed use of any Facility LC, including, without limitation, any claims, damages, losses, liabilities, costs or expenses which the LC Issuer may incur by reason of or in connection with (i) the failure of any other Lender to fulfill or comply with its obligations to the LC Issuer hereunder (but nothing herein contained shall affect any rights the Borrower may have against any defaulting Lender) or (ii) by reason of or on account of the LC Issuer issuing any Facility LC which specifies that the term “Beneficiary” included therein includes any successor by operation of law of the named Beneficiary, but which Facility LC does not require that any drawing by any such successor Beneficiary be accompanied by a copy of a legal document, satisfactory to the LC Issuer, evidencing the appointment of such successor Beneficiary; provided that the Borrower shall not be required to indemnify any Lender, the LC Issuer or such Agent for any claims, damages, losses, liabilities, costs or expenses to the extent, but only to the extent, caused by (x) the willful misconduct or gross negligence of the LC Issuer in determining whether a request presented under any Facility LC complied with the terms of such Facility LC or (y) the LC Issuer’s failure to pay under any Facility LC after the presentation to it of a request strictly complying with the terms and conditions of such Facility LC. Nothing in this Section 2.19.9 is intended to limit the obligations of the Borrower under any other provision of this Agreement.

2.19.10. Lenders’ Indemnification. Each Lender shall, ratably in accordance with its Pro Rata Share, indemnify the LC Issuer, its affiliates and their respective directors, officers, agents and employees (to the extent not reimbursed by the Borrower) against any cost, expense (including reasonable counsel fees and disbursements), claim, demand, action, loss or liability (except such as result from such indemnitees’ gross negligence or willful misconduct or the LC Issuer’s failure to pay under any Facility LC after the presentation to it of a request strictly complying with the terms and conditions of the Facility LC) that such indemnitees may suffer or incur in connection with this Section 2.19 or any action taken or omitted by such indemnitees hereunder.

2.19.11. Facility LC Collateral Account. The Borrower agrees that it will, upon the request of the Administrative Agent or the Required Lenders and until the final expiration date of any Facility LC and thereafter as long as any amount is payable to the LC Issuer or the Lenders in respect of any Facility LC, maintain a special collateral account pursuant to

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arrangements satisfactory to the Administrative Agent (the “Facility LC Collateral Account”) at the Administrative Agent’s office at the address specified pursuant to Article XIII, in the name of such Borrower but under the sole dominion and control of the Administrative Agent, for the benefit of the Lenders and in which such Borrower shall have no interest other than as set forth in Section 8.1. The Borrower hereby pledges, assigns and grants to the Administrative Agent, on behalf of and for the ratable benefit of the Administrative Agent, the Lenders and the LC Issuer, a security interest in all of the Borrower’s right, title and interest in and to all funds which may from time to time be on deposit in the Facility LC Collateral Account to secure the prompt and complete payment and performance of the Obligations. The Administrative Agent will invest any funds on deposit from time to time in the Facility LC Collateral Account in certificates of deposit of Bank One having a maturity not exceeding 30 days. Nothing in this Section 2.19.11 shall either obligate the Administrative Agent to require the Borrower to deposit any funds in the Facility LC Collateral Account or limit the right of the Administrative Agent to release any funds held in the Facility LC Collateral Account in each case other than as required by Section 2.7.2 or Section 8.1.

2.19.12. Rights as a Lender. In its capacity as a Lender, the LC Issuer shall have the same rights and obligations as any other Lender.

2.20. Limitation of Interest; Applicability of Texas Finance Code Chapter 346.

(a) The Borrower, the Administrative Agent and the Lenders intend to strictly comply with all applicable laws, including applicable usury laws. Accordingly, the provisions of this Section 2.20 shall govern and control over every other provision of this Agreement or any other Loan Document which conflicts or is inconsistent with this Section 2.20, even if such provision declares that it controls. As used in this Section 2.20, the term “interest” includes the aggregate of all charges, fees, benefits or other compensation which constitute interest under applicable law, provided that, to the maximum extent permitted by applicable law, (a) any non-principal payment shall be characterized as an expense or as compensation for something other than the use, forbearance or detention of money and not as interest, and (b) all interest at any time contracted for, reserved, charged or received shall be amortized, prorated, allocated and spread, in equal parts during the full term of the Obligations. In no event shall the Borrower or any other Person be obligated to pay, or any Lender have any right or privilege to reserve, receive or retain, (a) any interest in excess of the maximum amount of nonusurious interest permitted under the applicable laws (if any) of the United States or of any other applicable state, or (b) total interest in excess of the amount which such Lender could lawfully have contracted for, reserved, received, retained or charged had the interest been calculated for the full term of the Obligations at the Highest Lawful Rate. On each day, if any, that the interest rate (the “Stated Rate”) called for under this Agreement or any other Loan Document exceeds the Highest Lawful Rate, the rate at which interest shall accrue shall automatically be fixed by operation of this sentence at the Highest Lawful Rate for that day, and shall remain fixed at the Highest Lawful Rate for each day thereafter until the total amount of interest accrued equals the total amount of interest which would have accrued if there were no such ceiling rate as is imposed by this sentence. Thereafter, interest shall accrue at the Stated Rate unless and until the Stated Rate again exceeds the Highest Lawful Rate when the provisions of the

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immediately preceding sentence shall again automatically operate to limit the interest accrual rate. The daily interest rates to be used in calculating interest at the Highest Lawful Rate shall be determined by dividing the applicable Highest Lawful Rate per annum by the number of days in the calendar year for which such calculation is being made. None of the terms and provisions contained in this Agreement or in any other Loan Document which directly or indirectly relate to interest shall ever be construed without reference to this Section 2.20, or be construed to create a contract to pay for the use, forbearance or detention of money at an interest rate in excess of the Highest Lawful Rate. If the term of any Obligation is shortened by reason of acceleration of maturity as a result of any Default or by any other cause, or by reason of any required or permitted prepayment, and if for that (or any other) reason any Lender at any time, including but not limited to, the stated maturity, is owed or receives (and/or has received) interest in excess of interest calculated at the Highest Lawful Rate, then and in any such event all of any such excess interest shall be canceled automatically as of the date of such acceleration, prepayment or other event which produces the excess, and, if such excess interest has been paid to such Lender, it shall be credited pro tanto against the then-outstanding principal balance of the Borrower’s obligations to such Lender, effective as of the date or dates when the event occurs which causes it to be excess interest, until such excess is exhausted or all of such principal has been fully paid and satisfied, whichever occurs first, and any remaining balance of such excess shall be promptly refunded to its payor.

(b) Chapter 346 of the Texas Finance Code (which regulates certain revolving credit accounts (formerly Tex. Rev. Civ. Stat. Ann. Art. 5069, Ch. 15)) shall not apply to this Agreement or to any Loan, nor shall this Agreement or any Loan be governed by or be subject to the provisions of such Chapter 346 in any manner whatsoever.

2.21. Borrowing Base.

(i) Amount. For the period from and including the Closing Date to but not including the first Redetermination Date, the amount of the Borrowing Base shall be $200,000,000 (provided that the initial Aggregate Commitment shall be $150,000,000, until such time as the Borrower exercises its right to increase the Aggregate Commitment in accordance with Section 2.5(ii) or the Aggregate Commitments are otherwise adjusted in accordance with this Agreement). Notwithstanding the foregoing, the Borrowing Base will be subject to interim adjustments pursuant to either Section 6.1.8(iv) or Section 6.2.11.

(ii) Redetermination. On or before March 15th and September 15th of each year, commencing March 15, 2004, the Administrative Agent shall propose in writing to the Borrower and the Lenders a new Borrowing Base in accordance with Section 2.21(iii) (assuming receipt by the Administrative Agent of the Engineering Reports in a timely and complete manner). After having received notice of such proposal by the Administrative Agent, each Lender shall have fifteen (15) days to agree with such proposal or disagree by proposing an alternate Borrowing Base. If at the end of such fifteen (15) days, any Lender has not communicated its approval or disapproval, such silence shall be deemed to be an approval. If, however, at the end of such 15-day period, the Lenders or the Required Lenders, as applicable, have not approved or deemed to have approved, as aforesaid, the proposed Borrowing Base, then the Borrowing Base shall be

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determined in accordance with Section 2.21(iv). After such redetermined Borrowing Base is approved by (a) all Lenders in the case of any increase in the Borrowing Base, (b) the Required Lenders in the case of any maintenance or any decrease in the Borrowing Base, or (c) as otherwise determined as provided in Section 2.21(iv), the Administrative Agent will notify the Borrower and the Lenders of the amount of the redetermined Borrowing Base, and such amount shall become effective and applicable to the Borrower, the Agents, the LC Issuer and the Lenders as of the next succeeding April 1st or October 1st, as applicable. Notwithstanding the foregoing, however, any increase in the Borrowing Base shall require approval or deemed approval of all the Lenders as set forth in this Section 2.21(ii).

(iii) Engineering Reports. Upon receipt of the Reserve Report and such other reports, data and supplemental information, including the information provided pursuant to Section 6.1.7(iii), as may, from time to time, be reasonably requested by the Required Lenders (the “Engineering Reports”), the Administrative Agent will evaluate such information. The Administrative Agent, with the approval or deemed approval of the Lenders as set forth in Section 2.21(ii), but subject to the terms of Section 2.21(ii), shall, in good faith, redetermine the Borrowing Base based upon such information and such other information (including, without limitation, information described in the Engineering Reports, the status of title with respect to the Oil and Gas Properties and the existence of any other Indebtedness) as the Administrative Agent deems appropriate and consistent with its normal oil and gas lending criteria as it exists at the particular time. Such redetermination shall be accomplished not later than and effective as of the first (1st) day of each April and October of each calendar year, assuming that the Borrower shall have furnished the Engineering Reports in a timely and complete manner as required by Section 6.1.7. In assessing whether to approve or reject a proposed Borrowing Base, each Lender will assess, in good faith, the Engineering Reports and the other information as they deem appropriate and consistent with its respective oil and gas lending criteria and procedures as they exist at the particular time.

(iv) Consensus and Failure of Consensus. Except as hereinafter provided, the decision of the Lenders or Required Lenders, as applicable, with respect to any Borrowing Base determination shall control; provided, however, if the Lenders or Required Lenders, as applicable, have not approved or are not deemed to have approved the Borrowing Base as of the date such a determination is called for in Section 2.21(ii), the Administrative Agent shall determine the weighted arithmetic average of the Borrowing Bases determined by each Lender or each of the Required Lenders, as applicable, (weighted in accordance with each such Lender’s Pro Rata Share) for purposes of this Section 2.21 and such amount shall then become the Borrowing Base until the next Scheduled Redetermination Date or the next date on which an interim redetermination occurs under Section 2.21(v) or the next adjustment under either Section 6.1.8(iv) or Section 6.2.11. Notwithstanding the foregoing, however, any increase in the Borrowing Base shall require approval or deemed approval of all the Lenders as set forth in Section 2.21(ii).

(v) Interim Redeterminations. The Borrower may, at its option, one time during any 12-month period initiate an interim redetermination of the Borrowing Base. In addition, the Borrower may, at its option, in connection with any acquisition (or any series of acquisitions occurring since the most recent redetermination of the Borrowing Base) by the Borrower or a Restricted Subsidiary of Oil and Gas Properties having a purchase price, either individually or in

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the aggregate, of $50,000,000 or more, initiate an interim redetermination of the Borrowing Base. The Administrative Agent (at the direction of the Required Lenders, in their option) may one time during any 12-month period initiate an interim redetermination of the Borrowing Base. The Borrowing Base also may be redetermined in accordance with Section 6.2.10(i).

ARTICLE III

YIELD PROTECTION; TAXES

3.1. Yield Protection. If, on or after the date of this Agreement, the adoption of any law or any governmental or quasi-governmental rule, regulation, policy, guideline or directive (whether or not having the force of law), or any change in the interpretation or administration thereof by any governmental or quasi-governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender or applicable Lending Installation or the LC Issuer with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency:

(i) subjects any Lender or any applicable Lending Installation or the LC Issuer to any Taxes, or changes the basis of taxation of payments (other than with respect to Excluded Taxes) to any Lender or the LC Issuer in respect of its Eurodollar Loans, Facility LCs or participations therein, or

(ii) imposes or increases or deems applicable any reserve, assessment, insurance charge, special deposit or similar requirement against assets of, deposits with or for the account of, or credit extended by, any Lender or any applicable Lending Installation or the LC Issuer (other than reserves and assessments taken into account in determining the interest rate applicable to Eurodollar Advances), or

(iii) imposes any other condition the result of which is to increase the cost to any Lender or any applicable Lending Installation or the LC Issuer of making, funding or maintaining its Eurodollar Loans, or of issuing or participating in Facility LCs or reduces any amount receivable by any Lender or any applicable Lending Installation or the LC Issuer in connection with its Eurodollar Loans or Facility LC or participation therein, or requires any Lender or any applicable Lending Installation or the LC Issuer to make any payment calculated by reference to the amount of Eurodollar Loans, Facility LCs or participations therein held or interest or LC Fees received by it, by an amount deemed material by such Lender or the LC Issuer, as the case may be,

and the result of any of the foregoing is to increase the cost to such Lender or applicable Lending Installation or the LC Issuer, as the case may be, of making or maintaining its Eurodollar Loans or Commitment or of issuing or participating in Facility LCs or to reduce the return received by such Lender or applicable Lending Installation or the LC Issuer, as the case may be, in connection with such Eurodollar Loans, Commitment, Facility LCs or participations therein, then, within 15 days of demand by such Lender or the LC Issuer, as the case may be, the Borrower shall pay such Lender or the LC Issuer, as the case may be, such additional amount or amounts as will compensate such Lender or the LC Issuer, as the case may be, for such increased cost or reduction in amount received.

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3.2. Changes in Capital Adequacy Regulations. If a Lender or the LC Issuer determines the amount of capital required or expected to be maintained by such Lender or the LC Issuer, any Lending Installation of such Lender or the LC Issuer, or any corporation controlling such Lender or the LC Issuer is increased as a result of a Change, then, within 15 days of demand by such Lender or the LC Issuer, the Borrower shall pay such Lender or the LC Issuer the amount necessary to compensate for any shortfall in the rate of return on the portion of such increased capital which such Lender or the LC Issuer determines is attributable to this Agreement, its Outstanding Credit Exposure or its Commitment to make Loans and issue or participate in Facility LCs, as the case may be, hereunder (after taking into account such Lender’s or the LC Issuer’s policies as to capital adequacy). “Change” means (i) any change after the date of this Agreement in the Risk-Based Capital Guidelines or (ii) any adoption of or change in any other law, governmental or quasi-governmental rule, regulation, policy, guideline, interpretation, or directive (whether or not having the force of law) after the date of this Agreement which affects the amount of capital required or expected to be maintained by any Lender or the LC Issuer or any Lending Installation or any corporation controlling any Lender or the LC Issuer. “Risk-Based Capital Guidelines” means (i) the risk-based capital guidelines in effect in the United States on the date of this Agreement, including transition rules, and (ii) the corresponding capital regulations promulgated by regulatory authorities outside the United States implementing the July 1988 report of the Basle Committee on Banking Regulation and Supervisory Practices Entitled “International Convergence of Capital Measurements and Capital Standards,” including transition rules, and any amendments to such regulations adopted prior to the date of this Agreement.

3.3. Availability of Types of Advances. If any Lender determines that maintenance of its Eurodollar Loans at a suitable Lending Installation would violate any applicable law, rule, regulation, or directive, whether or not having the force of law, or if the Required Lenders determine that (i) deposits of a type and maturity appropriate to match fund Eurodollar Advances are not available or (ii) the interest rate applicable to Eurodollar Advances does not accurately reflect the cost of making or maintaining Eurodollar Advances, then the Administrative Agent shall suspend the availability of Eurodollar Advances and require any affected Eurodollar Advances to be repaid or converted to Floating Rate Advances, subject to the payment of any funding indemnification amounts required by Section 3.4.

3.4. Funding Indemnification. If any payment of a Eurodollar Advance occurs on a date which is not the last day of the applicable Interest Period, whether because of acceleration, prepayment or otherwise, or a Eurodollar Advance is not made on the date specified by the Borrower for any reason other than default by the Lenders, the Borrower will indemnify each Lender for any loss or cost incurred by it resulting therefrom, including, without limitation, any loss or cost in liquidating or employing deposits acquired to fund or maintain such Eurodollar Advance.

3.5. Taxes. (i) All payments by the Borrower to or for the account of any Lender, the LC Issuer or the Administrative Agent hereunder or under any Note or Facility LC Application shall be made free and clear of and without deduction for any and all Taxes. If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder to any Lender, the LC Issuer or the Administrative Agent, (a) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to

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additional sums payable under this Section 3.5) such Lender, the LC Issuer or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (b) the Borrower shall make such deductions, (c) the Borrower shall pay the full amount deducted to the relevant authority in accordance with applicable law and (d) the Borrower shall furnish to the Administrative Agent the original copy of a receipt evidencing payment thereof within 30 days after such payment is made.

(ii) In addition, the Borrower hereby agrees to pay any present or future stamp or documentary taxes and any other excise or property taxes, charges or similar levies which arise from any payment made hereunder or under any Note or Facility LC Application or from the execution or delivery of, or otherwise with respect to, this Agreement or any Note or Facility LC Application (“Other Taxes”).

(iii) The Borrower hereby agrees to indemnify the Administrative Agent, the LC Issuer and each Lender for the full amount of Taxes or Other Taxes (including, without limitation, any Taxes or Other Taxes imposed on amounts payable under this Section 3.5) paid by the Administrative Agent, the LC Issuer or such Lender as a result of its Commitment, any Loans made by it hereunder, any Facility LC issued or participated in, or otherwise, in connection with its participation in this Agreement and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto. Payments due under this indemnification shall be made within 30 days of the date the Administrative Agent, the LC Issuer or such Lender makes demand therefor pursuant to Section 3.6.

(iv) Each Lender that is not incorporated under the laws of the United States of America or a state thereof (each a “Non-U.S. Lender”) agrees that it will, not more than ten Business Days after the date of this Agreement, (a) deliver to the Administrative Agent two duly completed copies of United States Internal Revenue Service Form W-8BEN or W-8ECI, certifying in either case that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, and (b) deliver to the Administrative Agent a United States Internal Revenue Form W-8 or W-9, as the case may be, and certify that it is entitled to an exemption from United States backup withholding tax. Each Non-U.S. Lender further undertakes to deliver to each of the Borrower and the Administrative Agent (x) renewals or additional copies of such form (or any successor form) on or before the date that such form expires or becomes obsolete, and (y) after the occurrence of any event requiring a change in the most recent forms so delivered by it, such additional forms or amendments thereto as may be reasonably requested by the Borrower or the Administrative Agent. All forms or amendments described in the preceding sentence shall certify that such Lender is entitled to receive payments under this Agreement without deduction or withholding of any United States federal income taxes, unless an event (including without limitation any change in treaty, law or regulation) has occurred prior to the date on which any such delivery would otherwise be required which renders all such forms inapplicable or which would prevent such Lender from duly completing and delivering any such form or amendment with respect to it and such Lender advises the Borrower and the Administrative Agent that it is not capable of receiving payments without any deduction or withholding of United States federal income tax.

(v) For any period during which a Non-U.S. Lender has failed to provide the Borrower with an appropriate form pursuant to clause (iv), above (unless such failure is due to a

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change in treaty, law or regulation, or any change in the interpretation or administration thereof by any governmental authority, occurring subsequent to the date on which a form originally was required to be provided), such Non-U.S. Lender shall not be entitled to indemnification under this Section 3.5 with respect to Taxes imposed by the United States.

(vi) Any Lender that is entitled to an exemption from or reduction of withholding tax with respect to payments under this Agreement or any Note pursuant to the law of any relevant jurisdiction or any treaty shall deliver to the Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law as will permit such payments to be made without withholding or at a reduced rate.

(vii) If the U.S. Internal Revenue Service or any other governmental authority of the United States or any other country or any political subdivision thereof asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender (because the appropriate form was not delivered or properly completed, because such Lender failed to notify the Administrative Agent of a change in circumstances which rendered its exemption from withholding ineffective, or for any other reason), such Lender shall indemnify the Administrative Agent fully for all amounts paid, directly or indirectly, by the Administrative Agent as tax, withholding therefor, or otherwise, including penalties and interest, and including taxes imposed by any jurisdiction on amounts payable to the Administrative Agent under this subsection, together with all costs and expenses related thereto (including attorneys fees and time charges of attorneys for the Administrative Agent, which attorneys may be employees of the Administrative Agent). The obligations of the Lenders under this Section 3.5(vii) shall survive the payment of the Obligations and termination of this Agreement.

3.6. Lender Statements; Survival of Indemnity. To the extent reasonably possible, each Lender shall designate an alternate Lending Installation with respect to its Eurodollar Loans to reduce any liability of the Borrower to such Lender under Sections 3.1, 3.2 and 3.5 or to avoid the unavailability of Eurodollar Advances under Section 3.3, so long as such designation is not, in the judgment of such Lender, disadvantageous to such Lender. Each Lender shall deliver a written statement of such Lender to the Borrower (with a copy to the Administrative Agent) as to the amount due, if any, under Section 3.1, 3.2, 3.4 or 3.5. Such written statement shall set forth in reasonable detail the calculations upon which such Lender determined such amount and shall be final, conclusive and binding on the Borrower in the absence of manifest error. Determination of amounts payable under such Sections in connection with a Eurodollar Loan shall be calculated as though each Lender funded its Eurodollar Loan through the purchase of a deposit of the type and maturity corresponding to the deposit used as a reference in determining the Eurodollar Rate applicable to such Loan, whether in fact that is the case or not. Unless otherwise provided herein, the amount specified in the written statement of any Lender shall be payable on demand after receipt by the Borrower of such written statement. The obligations of the Borrower under Section 3.1, 3.2, 3.4 and 3.5 shall survive payment of the Obligations and termination of this Agreement.

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3.7. Time Limit; Etc.

(i) Time Limit. Notwithstanding anything to the contrary contained in Sections 3.1 through 3.6, the Borrower shall not be required to reimburse or pay any costs or expenses to any Lender as required by such Sections that have accrued more than 180 days prior to such Lender’s giving notice to the Borrower that such Lender has suffered or incurred such costs or expenses.

(ii) Non-Discriminatory Basis. None of the Lenders shall be permitted to pass through to the Borrower costs and expenses under Sections 3.1 through 3.6 on a discriminatory basis (i.e. which are not also passed through by such Lender to other customers of such Lender similarly situated when such customer is subject to documents containing similar provisions as those contained in such Sections).

ARTICLE IV

CONDITIONS PRECEDENT

4.1. Initial Credit Extension. The Lenders’ obligation to make the initial Credit Extension hereunder is subject to following conditions precedent being satisfied, including but not limited to the Administrative Agent having received on or before the date of such initial Credit Extension each of the documents listed below duly executed on behalf of each party thereto, each in form and substance satisfactory to the Administrative Agent, and the Administrative Agent determining that all such conditions precedent have otherwise been satisfied:

(i) Certain Loan Documents. The Administrative Agent shall have received multiple counterparts, as requested by the Administrative Agent, of the following documents: (a) this Agreement; (b) the Fee Letter; (c) the Guaranty duly completed and executed by each Guarantor; (d) the Assignment of Secured Indebtedness; (e) the Mortgage Assignment and Amendment, described on Exhibit E, duly completed and executed in a sufficient number of counterparts for recording, if necessary, and all documents and instruments, including Uniform Commercial Code Financing Statements (Form UCC-1), required by law or reasonably requested by the Administrative Agent with respect to such Mortgage Assignment and Amendment (or the underlying Mortgages); (f) the Pledge Agreements required by Section 4.1(ii); (g) any Notes requested by a Lender pursuant to Section 2.13 payable to the order of each such requesting Lender; and (h) the other Collateral Documents, including those described on Exhibit E, duly completed and executed in a sufficient number of counterparts for recording, if necessary. In connection with the execution and delivery of the Collateral Documents, the Administrative Agent shall be reasonably satisfied that the Collateral Documents create or continue, as applicable, first priority, perfected Liens (subject only to Excepted Liens identified in clauses (i) to (v), (vii) and (viii) of the definition thereof) on at least the lesser of (i) 75% of the total value of the Oil and Gas Properties evaluated in the Initial Reserve Report or (ii) 125% of the Aggregate Commitment.

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(ii) Pledge Agreements. The Administrative Agent shall have received counterparts of a Pledge Agreement, dated as of the Closing Date, duly executed and delivered by each Pledgor, together with the following:

(a) From Borrower. (1) stock certificates representing 100% of the outstanding shares of common stock of all Restricted Subsidiaries, and stock powers and instruments of transfer, endorsed in blank, with respect to such stock certificates; and (2) all documents and instruments, including Uniform Commercial Code Financing Statements (Form UCC-1), required by law or reasonably requested by the Administrative Agent to be filed, registered or recorded to create or perfect the Liens intended to be created under the Pledge Agreement.

(b) From PVA Holding. (1) stock certificates representing 100% of the outstanding shares of common stock of PVA Oil & Gas, and stock powers and instruments of transfer, endorsed in blank, with respect to such stock certificates; and (2) all documents and instruments, including Uniform Commercial Code Financing Statements (Form UCC-1), required by law or reasonably requested by the Administrative Agent to be filed, registered or recorded to create or perfect the Liens intended to be created under the Pledge Agreement.

(c) From PVA Oil & Gas. (1) stock certificates representing 100% of the outstanding shares of common stock of PVA Texas, and stock powers and instruments of transfer, endorsed in blank, with respect to such stock certificates; and (2) all documents and instruments, including Uniform Commercial Code Financing Statements (Form UCC-1), required by law or reasonably requested by the Administrative Agent to be filed, registered or recorded to create or perfect the Liens intended to be created under the Pledge Agreement.

(iii) Organizational Documents. The Administrative Agent shall have received a certificate of the Secretary or an Assistant Secretary of each Loan Party dated as of the Closing Date, on which the Administrative Agent and the Lenders may conclusively rely until the Administrative Agent receives notice in writing from the Borrower to the contrary, certifying:

(a) that attached to each such certificate are (1) a true and complete copy of the Organic Documents of such Loan Party, as the case may be, as in effect on the date of such certificate, (2) a true and complete copy of a certificate from the Governmental Authority of the state of such entity’s organization certifying that such entity is duly organized and validly existing in such jurisdiction, and (3) a true and complete copy of a certificate of good standing with respect to such entity from the Governmental Authority of the state of such entity’s organization;

(b) that attached to such certificate is a true and complete copy of resolutions duly adopted by the board of directors or management committee of such Loan Party, as applicable, authorizing the execution, delivery and performance of each of the Loan Documents to which such Loan Party is or is intended to be a party; and

(c) as to the incumbency and specimen signature of each officer of such Loan Party (1) who is authorized to execute the Loan Documents to which such Loan Party is or is intended to be a party and (2) who will, until replaced by another officer or officers duly authorized for that purpose, act as its representative for the purposes of signing documents and giving notices and other communications in connection with this Agreement and the transactions contemplated hereby.

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(iv) Legal Opinions. The Administrative Agent shall have received a written opinion of Nancy M. Snyder, Esq., as general counsel to Borrower and the Guarantors, addressed to the Lenders in form and substance satisfactory to the Administrative Agent.

(v) Subordination Agreements. The Administrative Agent shall have received multiple counterparts of the Subordination Agreement from each Unrestricted Subsidiary designated as a lender on Schedule 6.2.2 duly executed by each such Unrestricted Subsidiary.

(vi) UCC and Lien Searches. The Administrative Agent shall have received appropriate UCC search certificates reflecting no prior liens or security interests encumbering the Mortgaged Properties other than permitted by Section 6.2.3 for each of the following jurisdictions: Delaware, Kentucky, Louisiana, Mississippi, Texas, Virginia and West Virginia.

(vii) Insurance. The Administrative Agent and the Lenders shall have received certificates, dated within fifteen (15) days of the Closing Date, from the Borrower’s insurers reflecting (a) compliance with all of the insurance required by Section 6.1.3 and by the Collateral Documents and (b) that such insurance is in full force and effect.

(viii) Compliance Certificate. The Administrative Agent shall have received from Borrower a compliance certificate substantially in the form of Exhibit A.

(ix) Financial Statements. The Administrative Agent shall have received the financial statements described in Section 5.2(i).

(x) Environmental Review. The Administrative Agent shall be reasonably satisfied with the environmental condition of the Oil and Gas Properties and operations of the Borrower and its Restricted Subsidiaries.

(xi) Initial Reserve Report. The Administrative Agent shall have received a reserve engineering report as of December 31, 2002, prepared by one or more Approved Petroleum Engineers, as supplemented by a reserve report as of June 30, 2003 prepared by or under the supervision of the chief engineer of the Borrower (which supplemental reserve report shall be certified by the chief engineer of the Borrower as being true and accurate and having been prepared in accordance the procedures used to prepare the December 31, 2002 engineering report) (collectively, the “Initial Reserve Report”) with respect to the value of the Oil and Gas Properties of the Borrower and its Restricted Subsidiaries acceptable to the Administrative Agent using such reasonable assumptions as the Administrative Agent shall specify (including such discount rates and projected hydrocarbon price assumptions) and such other reserve, engineering, geological and title information as may be requested by the Administrative Agent.

(xii) Borrowing Base Determination. Determination of an initial Borrowing Base acceptable to the Borrower and all of the Lenders.

(xiii) Prior Credit Agreement. The Administrative Agent shall have received satisfactory evidence that the Prior Credit Agreement and the other “Loan Documents” defined therein shall have been assigned to the Lenders pursuant to the Assignment of Secured Indebtedness and the Mortgage Assignment and Amendment.

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(xiv) Money Transfer Instructions. The Administrative Agent shall have received written money transfer instructions, in substantially the form of Exhibit C, addressed to the Administrative Agent and signed by an Authorized Officer, together with such other related money transfer authorizations as the Administrative Agent may have reasonably requested.

(xv) Facility LC Application. If the initial Credit Extension will be the issuance of a Facility LC, the Administrative Agent shall have received a properly completed Facility LC Application.

(xvi) Other Documents. The Administrative Agent shall have received such other documents as any Lender or its counsel may have reasonably requested.

(xvii) Satisfactory Legal Form. All documents executed or submitted pursuant hereto by and on behalf of the Borrower or any other Loan Party shall be in form and substance reasonably satisfactory to the Administrative Agent and its counsel. The Administrative Agent and its counsel shall have received all information, approvals, documents or instruments as the Administrative Agent or its counsel may reasonably request.

(xviii) Fees and Expenses. The Administrative Agent, the other Agents and the Lenders shall have received all fees and other amounts due and payable pursuant to this Agreement or any other Loan Document on or prior to the date hereof, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses (including fees, charges and disbursements of counsel) required to be reimbursed or paid by any Loan Party hereunder or under any other Loan Document.

(xix) Due Diligence. The Administrative Agent shall be satisfied, in its reasonable discretion with its due diligence in connection with the Property and operations of the Borrower, its Subsidiaries and the Guarantors.

4.2. Each Credit Extension. The Lenders shall not be required to make any Credit Extension or reissuance or Modification of a Facility LC unless on the applicable Credit Extension Date or the date of such reissuance or Modification all of the following conditions precedent have been satisfied:

(i) There exists no Default or Unmatured Default.

(ii) No Material Adverse Effect shall have occurred since December 31, 2002.

(iii) No litigation, arbitration, governmental proceeding, claim for Taxes or Other Taxes, dispute or administrative or other proceeding shall be pending or, to the knowledge of the Borrower, threatened against the Borrower or any of its Subsidiaries which could reasonably be expected to have a Material Adverse Effect.

(iv) The representations and warranties contained in Article V and in the other Loan Documents are true and correct as of such Credit Extension Date except to the extent any such representation or warranty is stated to relate solely to an earlier date, in which case such representation or warranty shall have been true and correct on and as of such earlier date.

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(v) The making of such Credit Extension would not conflict with, or cause any Lender to exceed, any applicable Government Requirements.

(vi) The Administrative Agent shall have received a timely request therefor pursuant to Article II.

(vii) All legal matters incident to the making of such Credit Extension shall be satisfactory to the Lenders and their counsel.

Each Borrowing Notice or request for issuance, reissuance or Modification of a Facility LC with respect to each such Credit Extension shall be deemed to constitute a representation and warranty by the Borrower that the conditions contained in Sections 4.2(i), (ii) (iii) (iv) and (v) have been satisfied. Any Lender may require a duly completed compliance certificate in substantially the form of Exhibit A as a condition to making a Credit Extension.

ARTICLE V

REPRESENTATIONS AND WARRANTIES

The Borrower represents and warrants to the Administrative Agent and the Lenders that each representation and warranty herein is given as of the Closing Date and shall be deemed repeated and reaffirmed on the dates of each Credit Extension and issuance, reissuance or Modification of a Facility LC as provided in Section 4.2:

5.1. Existence. The Borrower and each Restricted Subsidiary: (a) is duly organized or formed, legally existing and in good standing, if applicable, under the laws of the jurisdiction of its formation, except as to any Restricted Subsidiary where the failure to so exist or remain in good standing could not reasonably be expected to have a Material Adverse Effect, (b) has all requisite power, and has all material governmental licenses, authorizations, consents and approvals necessary to own its assets and carry on its business as now being or as proposed to be conducted, except where failure to have such power could not reasonably be expected to have a Material Adverse Effect and (c) is qualified to do business in all jurisdictions in which the nature of the business conducted by it makes such qualification necessary and where failure so to qualify could reasonably be expected to have a Material Adverse Effect.

5.2. Financial Position; No Material Adverse Effect.

(i) The Borrower has heretofore furnished to the Administrative Agent and the Lenders its consolidated balance sheet, and the related consolidated statements of income, cash flows and shareholders’ equity of the Borrower and its consolidated Subsidiaries (a) as of and for the Fiscal Year ended December 31, 2002, audited by and accompanied by the unqualified opinion of KPMG, independent certified public accountants, and (b) as of and for the Fiscal Quarter ended September 30, 2003, certified by an Authorized Officer of the Borrower that such financial statements present fairly in all material respects, the financial condition and results of operations of the Borrower and its Subsidiaries as of such dates and for such periods. Such financial statements were prepared in accordance with GAAP applied on a consistent basis.

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(ii) Except as disclosed to the Administrative Agent in writing, neither the Borrower nor any consolidated Restricted Subsidiary of the Borrower has any material contingent liabilities, material liabilities for taxes, unusual and material forward or long-term commitments or material unrealized or anticipated losses from any unfavorable commitments, except as referred to or reflected or provided for in the consolidated balance sheets of the Borrower or as otherwise disclosed to the Lenders in writing.

(iii) The Borrower has disclosed to the Lenders in writing any and all facts that, in the reasonable good faith judgment of the Borrower, could reasonably be expected to result in a Material Adverse Effect.

5.3. Litigation. Except as set forth on Schedule 5.3, there is no litigation, legal, administrative or arbitral proceeding, investigation or other action of any nature pending or, to the knowledge of the Borrower, threatened against or affecting the Borrower or any Restricted Subsidiary which involves the possibility of any judgment or liability against the Borrower or any Restricted Subsidiary not fully covered by insurance (except for normal deductibles) and which if adversely determined could reasonably be expected to have a Material Adverse Effect.

5.4. No Breach. Neither the execution and delivery of this Agreement and the Loan Documents nor compliance with the terms and provisions hereof or thereof will conflict with or result in a breach of, or require any consent which has not been obtained as of the Closing Date under, the respective charter or by-laws of the Borrower or any Restricted Subsidiary, any Governmental Requirement or any material agreement or instrument to which the Borrower or any Restricted Subsidiary is a party or by which it is bound or to which it or its Properties are subject, or constitute a default under any such agreement or instrument, or result in the creation or imposition of any Lien upon any of the revenues or assets of the Borrower or any Restricted Subsidiary pursuant to the terms of any such agreement or instrument other than the Liens created by the Loan Documents.

5.5. Authority; Enforceability. The Borrower and each Restricted Subsidiary have all necessary power and authority to execute, deliver and perform its obligations under this Agreement and the Loan Documents to which it is a party. The execution, delivery and performance by the Borrower and each Restricted Subsidiary of this Agreement and the Loan Documents to which it is a party have been duly authorized by all necessary action on its and its shareholders’ part, and this Agreement and the Loan Documents constitute the legal, valid and binding obligations of the Borrower and each Restricted Subsidiary party thereto, enforceable in accordance with their terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the rights of creditors generally and general principles of equity.

5.6. Approvals. No authorizations, approvals or consents of, and no filings or registrations with, any Governmental Authority or any third Person are necessary for the execution, delivery or performance by the Borrower or any Restricted Subsidiary of this Agreement or the Loan Documents or for the validity or enforceability thereof, except for (i) the

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recording and filing of the Collateral Documents as required by this Agreement and (ii) those third party approvals or consents which, if not made or obtained, would not cause a Default or Unmatured Default hereunder, could not reasonably be expected to have a Material Adverse Effect and do not have an adverse effect on the enforceability of the Loan Documents.

5.7. Use of Loans and Letters of Credit. The proceeds of the Loans and the Facility LCs shall be used (i) to provide working capital to the Borrower and its Subsidiaries, (ii) to finance capital expenditures and acquisitions (other than acquisitions of “margin stock”) of the Borrower and its Subsidiaries, (iii) to provide for letters of credit for the account of the Borrower and its Subsidiaries, and (iv) to purchase, restructure, rearrange, renew, extend and continue the Existing Indebtedness as described in Section 9.14. The Borrower is not engaged principally, or as one of its important activities, in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of buying or carrying margin stock (within the meaning of Regulation U or X of the Board of Governors of the Federal Reserve System). No part of the proceeds of any Loan or Facility LC will be used for any purpose which violation the provisions of Regulations T, U or X of the Board of Governors of the Federal Reserve System.

5.8. ERISA. Except where the taking of such action (or where the failure to take such action, as applicable) could reasonably be expected to have a Material Adverse Effect:

(i) the Borrower and each ERISA Affiliate have complied with ERISA and, where applicable, the Code regarding each Plan; (ii) each Plan is, and has been, maintained in substantial compliance with ERISA and, where applicable, the Code; (iii) no act, omission or transaction has occurred with respect to any Plan which could result in imposition on the Borrower or any ERISA Affiliate (whether directly or indirectly) of (a) either a civil penalty assessed pursuant to section 502(c), (i) or (l) of ERISA or a tax imposed pursuant to Chapter 43 of Subtitle D of the Code or (b) breach of fiduciary duty liability damages under section 409 of ERISA; (iv) no Plan (other than a defined contribution plan) or any trust created under any such Plan has been terminated in the last six years. No liability to the PBGC (other than for the payment of current premiums which are not past due) by the Borrower or any ERISA Affiliate has been or is expected by the Borrower or any ERISA Affiliate to be incurred with respect to any Plan. No ERISA Event with respect to any Plan has occurred; (v) full payment when due has been made of all amounts which the Borrower or any ERISA Affiliate is required under the terms of each Plan or applicable law to have paid as contributions to such Plan, and no accumulated funding deficiency (as defined in section 302 of ERISA and section 412 of the Code), whether or not waived, exists with respect to any Plan; (vi) the actuarial present value of the benefit liabilities under each Plan which is subject to Title IV of ERISA does not, as of the end of the Borrower’s most recently ended Fiscal Year, exceed the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities by an amount in excess of $2,000,000. The term “actuarial present value of the benefit liabilities” shall have the meaning specified in section 4041 of ERISA; (vii) neither the Borrower nor any ERISA Affiliate sponsors, maintains, or contributes to an employee welfare benefit plan, as defined in section 3(1) of ERISA, including, without limitation, any such plan maintained to provide benefits to former employees of such entities, other than as required under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended, that may not be terminated by the Borrower or any ERISA Affiliate in its sole discretion at any time without any material liability; (viii) none of the Borrower or any ERISA

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Affiliate sponsors, maintains or contributes to, or has at any time in the preceding six calendar years, sponsored, maintained or contributed to, any Multiemployer Plan; and (ix) none of the Borrower or any ERISA Affiliate is required to provide security under section 401(a)(29) of the Code due to a Plan amendment that results in an increase in current liability for the Plan.

5.9. Taxes. Each of the Borrower and its Subsidiaries has filed all United States Federal income tax returns and all other tax returns which are required to be filed by them and have paid all material taxes due pursuant to such returns or pursuant to any assessment received by the Borrower or any Subsidiary, except any such taxes which are being contested in good faith by appropriate proceedings diligently conducted and for which adequate reserves are being maintained in accordance with GAAP. The charges, accruals and reserves on the books of the Borrower and its Subsidiaries in respect of taxes and other governmental charges are, in the opinion of the Borrower, adequate. No tax lien has been filed and, to the knowledge of the Borrower, no claim is being asserted with respect to any such tax or other such governmental charge.

5.10. Titles, Etc.

(i) Each of the Borrower and the Restricted Subsidiaries has good and defensible title to its material Oil and Gas Properties and good title to its material personal Properties, in each case, free and clear of all Liens except Liens permitted by Section 6.2.3. After giving full effect to the Excepted Liens, the Borrower or the Restricted Subsidiary specified as the owner owns the net interests in production attributable to the Hydrocarbon Interests as reflected in the most recently delivered Reserve Report, and the ownership of such Properties shall not in any material respect obligate the Borrower or such Restricted Subsidiary to bear the costs and expenses relating to the maintenance, development and operations of each such Property in an amount in excess of the working interest of each Property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Borrower’s or such Restricted Subsidiary’s net revenue interest in such Property.

(ii) All material leases and agreements necessary for the conduct of the business of the Borrower and the Restricted Subsidiaries are valid and subsisting, in full force and effect, and there exists no default or event or circumstance which with the giving of notice or the passage of time or both would give rise to a default under any such lease or leases, which would affect in any material respect the conduct of the business of the Borrower and the Restricted Subsidiaries, taken as a whole.

(iii) The rights, Properties and other assets presently owned, leased or licensed by the Borrower and the Restricted Subsidiaries including, without limitation, all easements and rights of way, include all rights, Properties and other assets necessary to permit the Borrower and the Restricted Subsidiaries to conduct their business in all material respects in the same manner as its business has been conducted prior to the Closing Date.

(iv) All of the assets and Properties of the Borrower and the Restricted Subsidiaries that are reasonably necessary for the operation of its business are in good working condition and are maintained in accordance with prudent business standards.

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5.11. No Material Misstatements. No written information, statement, exhibit, certificate, document or report furnished to the Administrative Agent and the Lenders (or any of them) by the Borrower or any Restricted Subsidiary or any of their Affiliates in connection with the negotiation of this Agreement and any amendments or modifications thereto contains any material misstatement of fact or omits to state a material fact or any fact necessary to make the statement contained therein not materially misleading in the light of the circumstances in which made and with respect to the Borrower and the Restricted Subsidiaries taken as a whole. There is no fact peculiar to the Borrower or any Restricted Subsidiary which has a Material Adverse Effect or in the future is reasonably likely to have (so far as the Borrower can now foresee) a Material Adverse Effect and which has not been set forth in this Agreement or the other documents, certificates and statements furnished to the Administrative Agent by or on behalf of the Borrower or any Restricted Subsidiary prior to, or on, the Closing Date in connection with the transactions contemplated hereby. There are no statements or conclusions in any Reserve Report which are based upon or include misleading information or fail to take into account material information regarding the matters reported therein, it being understood that each Reserve Report is necessarily based upon professional opinions, estimates and projections and that Borrower does not warrant that such opinions, estimates and projections will ultimately prove to have been accurate. No representation or warranty is made with respect to any Hydrocarbon Interest to which no Proved Hydrocarbon Reserves are properly attributed.

5.12. Investment Company Act. Neither the Borrower nor any Subsidiary is an “investment company” or a company “controlled” by an “investment company,” within the meaning of the Investment Company Act of 1940, as amended.

5.13. Public Utility Holding Company Act. Neither the Borrower nor any Subsidiary is a “holding company,” or a “subsidiary company” of a “holding company,” or an “affiliate” of a “holding company” or of a “subsidiary company” of a “holding company,” or a “public utility” within the meaning of the Public Utility Holding Company Act of 1935, as amended.

5.14. Subsidiaries. Except as set forth on Schedule 5.14 or as disclosed in writing to the Administrative Agent (which shall promptly furnish a copy to the Lenders) that shall be a supplement to Schedule 5.14, the Borrower has no Subsidiaries. Schedule 5.14 identifies each Subsidiary as either Restricted or Unrestricted, and each Restricted Subsidiary on such schedule is a wholly-owned Subsidiary.

5.15. Jurisdiction of Incorporation or Organization. The Borrower’s state of incorporation is Virginia. The state of incorporation or organization of each Restricted Subsidiary is stated on Schedule 5.14.

5.16. Defaults. Neither the Borrower nor any Restricted Subsidiary is in default nor has any event or circumstance occurred which, but for the expiration of any applicable grace period or the giving of notice, or both, would constitute a default under any material agreement or instrument to which the Borrower or any Restricted Subsidiary is a party or by which the Borrower or any Restricted Subsidiary is bound which default could reasonably be expected to have a Material Adverse Effect. No Default hereunder has occurred and is continuing.

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5.17. Environmental Matters. Except as could not be reasonably expected to have a Material Adverse Effect (or with respect to (iii), (iv) and (v) below, where the failure to take such actions could not be reasonably expected to have a Material Adverse Effect):

(i) neither any Property of the Borrower or any Restricted Subsidiary nor the operations conducted thereon violate any order or requirement of any court or Governmental Authority or any Environmental Laws;

(ii) no Property of the Borrower or any Restricted Subsidiary nor the operations currently conducted thereon or, to the knowledge of the Borrower, by any prior owner or operator of such Property or operation, are in violation of or subject to any existing, pending or threatened action, suit, investigation, inquiry or proceeding by or before any court or Governmental Authority or to any remedial obligations under Environmental Laws;

(iii) all notices, permits, licenses or similar authorizations, if any, required to be obtained or filed in connection with the operation or use of any and all Property of the Borrower and each Restricted Subsidiary, including, without limitation, past or present treatment, storage, disposal or release of a hazardous substance or solid waste into the environment, have been duly obtained or filed, and the Borrower and each Restricted Subsidiary are in compliance with the terms and conditions of all such notices, permits, licenses and similar authorizations;

(iv) all hazardous substances, solid waste and oil and gas exploration and production wastes, if any, generated at any and all Property of the Borrower or any Restricted Subsidiary have in the past been transported, treated and disposed of in accordance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or welfare or the environment, and, to the knowledge of the Borrower, all such transport carriers and treatment and disposal facilities have been and are operating in compliance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or welfare or the environment, and are not the subject of any existing, pending or threatened action, investigation or inquiry by any Governmental Authority in connection with any Environmental Laws;

(v) the Borrower has taken all steps reasonably necessary to determine and has determined that no hazardous substances, solid waste or oil and gas exploration and production wastes, have been disposed of or otherwise released, and there has been no threatened release of any hazardous substances on or to any Property of the Borrower or any Restricted Subsidiary, except in compliance with Environmental Laws and so as not to pose an imminent and substantial endangerment to public health or welfare or the environment;

(vi) to the extent applicable, all Property of the Borrower and each Restricted Subsidiary currently satisfies all design, operation, and equipment requirements imposed by the OPA, and the Borrower does not have any reason to believe that such Property, to the extent subject to the OPA, will not be able to maintain compliance with the OPA requirements during the term of this Agreement; and

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(vii) neither the Borrower nor any Restricted Subsidiary has any known contingent liability in connection with any release or threatened release of any oil, hazardous substance or solid waste into the environment.

5.18. Compliance with the Law; Maintenance of Properties. Neither the Borrower nor any Restricted Subsidiary has violated any applicable Governmental Requirement binding upon it or its Properties or failed to obtain any license, permit, franchise or other governmental authorization necessary for the ownership of any of its Properties or the conduct of its business, which violation or failure would have (in the event such violation or failure were asserted by any Person through appropriate action) a Material Adverse Effect. Except for such acts or failures to act as could not be reasonably expected to have a Material Adverse Effect, the Oil and Gas Properties (and properties unitized therewith) have been maintained, operated and developed in a good and workmanlike manner and in conformity with all applicable laws and all rules, regulations and orders of all duly constituted authorities having jurisdiction and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties; specifically in this connection, except for those as could not be reasonably expected to have a Material Adverse Effect, (i) after the Closing Date, no Oil and Gas Property is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) prior to the Closing Date and (ii) none of the wells comprising a part of the Oil and Gas Properties (or properties unitized therewith) owned by the Borrower or any of its Restricted Subsidiaries is deviated from the vertical more than the maximum permitted by applicable laws, regulations, rules and orders, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties (or in the case of wells located on properties unitized therewith, such unitized properties) owned by the Borrower or any of its Restricted Subsidiaries.

5.19. Insurance. The Borrower has, and has caused all its Restricted Subsidiaries to have, (i) all insurance policies sufficient for the compliance by each of them with all material Governmental Requirements and all material agreements and (ii) insurance coverage in at least amounts and against such risk (including, without limitation, public liability) that are usually insured against by companies similarly situated and engaged in the same or a similar business for the assets and operations of the Borrower and its Restricted Subsidiaries. The Agents, the LC Issuer and the Lenders have been named as additional insureds in respect of such liability insurance policies.

5.20. Rate Management Transactions. Schedule 5.20 sets forth, as of October 31, 2003, a true and complete list of all Rate Management Transactions (including commodity price swap agreements, forward agreements or contracts of sale which provide for prepayment for deferred shipment or delivery of oil, gas or other commodities) of the Borrower and each Subsidiary, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark to market value thereof, all credit support agreements relating thereto (including any margin required or supplied) and the counterparty to each such agreement.

5.21. Restriction on Liens. Neither the Borrower nor any of the Restricted Subsidiaries is a party to any material agreement or arrangement (other than instruments creating Liens

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permitted by Sections 6.2.3(iii), (iv) and (v), but then only on the Property subject of such Lien), or subject to any order, judgment, writ or decree, which either restricts or purports to restrict its ability to grant Liens to the Administrative Agent and the Lenders on or in respect of their respective assets or Properties to secure the Obligations and the Loan Documents.

5.22. Intellectual Property. The Borrower and its Restricted Subsidiaries either own or have valid licenses or other rights to use all databases, geological data, geophysical data, engineering data, maps, interpretations and other technical information used in their businesses as presently conducted, subject to the limitations contained in the agreements governing the use of the same, which limitations are customary for companies engaged in the business of the exploration and production of Hydrocarbons, with such exceptions as could not reasonably be expected to have a Material Adverse Effect.

5.23. Material Personal Property. All pipelines, wells, gas processing plants, platforms and other material improvements, fixtures and equipment owned in whole or in part by the Borrower or any of its Restricted Subsidiaries that are necessary to conduct normal operations are being maintained in a state adequate to conduct normal operations, and with respect to such of the foregoing which are operated by the Borrower or any of its Restricted Subsidiaries, in a manner consistent with the Borrower’s or its Restricted Subsidiaries’ past practices (other than those the failure of which to maintain in accordance with this Section 5.23 could not reasonably be expect to have a Material Adverse Effect).

5.24. Business. The Borrower and its Restricted Subsidiaries have not conducted and are not conducting any business other than businesses relating to the exploration, development, financing, acquisition, ownership, operation, maintenance, storage, transporting and marketing of the Oil and Gas Properties and related activities as currently conducted.

5.25. Solvency. Neither the Borrower nor any Restricted Subsidiary of the Borrower (i) is “insolvent” (within the meaning of Section 101(32) of the Bankruptcy Code, Section 2 of the Uniform Fraudulent Conveyance Act or Section 2 of the Uniform Fraudulent Transfer Act) or will become insolvent as a result of the incurrence of any obligation under any Loan Document to which it is a party; or (ii) has unreasonably small capital (after giving effect to the transactions contemplated in any Loan Document to which it is a party) for the conduct of its existing and contemplated business. Each of the Borrower and its Restricted Subsidiaries is able to perform its contingent obligations and other commitments as they mature in the normal course of business.

5.26. Licenses, Permits, Etc. The Borrower and each of its Restricted Subsidiaries possess such valid franchises, certificates of convenience and necessity, operating rights, licenses, permits, consents, authorizations, exemptions and orders of Governmental Authorities, as are necessary to carry on their respective businesses as now conducted and as proposed to be conducted, except to the extent a failure to obtain any such item could not reasonably be expected to result in a Material adverse Effect.

5.27. Fiscal Year. The Borrower’s Fiscal Year is January 1 through December 31.

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ARTICLE VI

COVENANTS

The Borrower covenants and agrees that, so long as any of the Aggregate Commitments is in effect and until payment in full of all Obligations and termination or expiration of all Facility LCs issued hereunder, all interest thereon and all other amounts payable by the Borrower hereunder and under the other Loan Documents:

6.1. Affirmative Covenants.

6.1.1. Reporting Requirements. The Borrower shall deliver, or shall cause to be delivered, to the Administrative Agent (and, with respect to the financial statements delivered pursuant to Sections 6.1.1(i) and (ii), with sufficient copies of each for the Lenders):

(i) Annual Financial Statements. As soon as available and in any event within 120 days after the end of each Fiscal Year of the Borrower, the audited consolidated and unaudited consolidating statements of income, stockholders’ equity, changes in financial position and cash flow of (a) the Borrower and its consolidated Subsidiaries and (b) the MLP and its Subsidiaries for such Fiscal Year, and the related audited consolidated and unaudited consolidating balance sheets of the Borrower and its consolidated Subsidiaries and the MLP and its Subsidiaries as at the end of such Fiscal Year, and setting forth in each case in comparative form the corresponding figures for the preceding Fiscal Year, and accompanied by either (x) with respect to any audited financial statements, the related opinion of independent public accountants of recognized national standing acceptable to the Administrative Agent which opinion shall state that said financial statements fairly present, in all material respects, the consolidated financial condition and results of operations of the Borrower and its consolidated Subsidiaries and the MLP and its Subsidiaries as at the end of, and for, such Fiscal Year and that such financial statements have been prepared in accordance with GAAP except for such changes in such principles with which the independent public accountants shall have concurred and such opinion shall not contain a “going concern” or like qualification or exception, and a certificate of such accountants stating that, in making the examination necessary for their opinion, they obtained no knowledge, except as specifically stated, of any Default or (y) with respect to any unaudited financial statements, the certificate of an Authorized Officer, which certificate shall state that said financial statements fairly present, in all material respects, the consolidated financial condition and results of operations of the Borrower and its consolidated Subsidiaries and the MLP and its Subsidiaries in accordance with GAAP, as at the end of, and for, such period.

(ii) Quarterly Financial Statements. As soon as available and in any event within 60 days after the end of each of the first three Fiscal Quarters of each Fiscal Year of the Borrower, consolidated and consolidating statements of income, stockholders’ equity, changes in financial position and cash flow of the Borrower and its consolidated Subsidiaries and the MLP and its Subsidiaries for such period and for the period from the beginning of the respective Fiscal Year to the end of such period, and the related consolidated and consolidating balance sheets as at the end of such period, and setting forth in each case in comparative form the corresponding figures for the corresponding period in the preceding Fiscal Year, accompanied by the certificate of an Authorized Officer, which certificate shall state that said financial statements fairly present, in all

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material respects, the consolidated and the consolidating financial condition and results of operations of the Borrower and its consolidated Subsidiaries and the MLP and its Subsidiaries in accordance with GAAP, as at the end of, and for, such period (subject to normal year-end audit adjustments).

(iii) Notice of Default, Etc. Promptly after the Borrower knows that any Default or any Material Adverse Effect has occurred, a notice of such Default or Material Adverse Effect, describing the same in reasonable detail and the action the Borrower proposes to take with respect thereto.

(iv) Other Accounting Reports. Promptly upon receipt thereof, a copy of each other report or letter submitted to the Borrower or any Subsidiary by independent accountants in connection with any annual, interim or special audit made by them of the books of the Borrower or any Subsidiary, and a copy of any response by the Borrower or any such Subsidiary of the Borrower, or the Board of Directors of the Borrower or any such Subsidiary of the Borrower, to such letter or report.

(v) SEC Filings, Etc. Promptly upon its becoming available, each financial statement, report, notice or proxy statement sent by the Borrower to stockholders generally and each regular or periodic report and any registration statement or prospectus filed by the Borrower with any securities exchange or the SEC.

(vi) Notices Under Material Instruments. Promptly after the furnishing thereof, copies of any financial statement, report or notice furnished to or any Person pursuant to the terms of any preferred stock designation, indenture, loan or credit or other similar agreement in respect of Indebtedness in excess of $2,000,000, other than this Agreement and not otherwise required to be furnished to the Lenders pursuant to any other provision of this Section 6.1.

(vii) Rate Management Transactions. Together with the delivery of the financial information to be supplied under Sections 6.1.1(i) and (ii), a report, in form and substance satisfactory to the Administrative Agent, setting forth as of the last Business Day of such Fiscal Quarter or Fiscal Year, a true and complete list of all Rate Management Transactions (including commodity price swap agreements, forward agreements or contracts of sale which provide for prepayment for deferred shipment or delivery of oil, gas or other commodities) of the Borrower and each Subsidiary, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark to market value therefor, any new credit support agreements relating thereto not listed on Schedule 5.20, any margin required or supplied under any credit support document, and the counterparty to each such agreement.

(viii) Compliance Certificates. At the time it furnishes each set of financial statements under Sections 6.1.1(i) and (ii) above, a certificate substantially in the form of Exhibit A hereto executed by an Authorized Officer (a) certifying as to the matters set forth therein and stating that no Default has occurred and is continuing (or, if any Default has occurred and is continuing, describing the same in reasonable detail), and (b) setting forth in reasonable detail the computations necessary to determine whether the Borrower is in compliance with Section 6.2.1 and Section 6.1.9(i) as of the end of the respective Fiscal Quarter or Fiscal Year.

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(ix) Taxes and Claims. In the event (a) not previously disclosed in the financial statements delivered under Section 6.1.1(i) and Section 6.1.1(ii) above and (b) that the amount of contested taxes or claims under Section 6.1.12 are in excess of $2,000,000 in the aggregate at any one time, written notice from an Authorized Officer of such circumstances, in detail satisfactory to the Administrative Agent.

(x) Notice of Sales. In the event the Borrower or any Restricted Subsidiary intends to sell, transfer, assign or otherwise dispose of any Oil or Gas Properties in accordance with this Agreement (but only if such transaction involves the disposition of Oil and Gas Properties for a value in excess of $2,000,000) prior written notice of such disposition, the price thereof and the anticipated date of closing.

(xi) Information Regarding Borrower and Guarantors. Prior written notice of any change (a) in the Borrower or any Guarantor’s corporate name or in any trade name used to identify such Person in the conduct of its business or in the ownership of its Properties, (b) in the location of the Borrower or any Guarantor’s chief executive office or principal place of business, (c) in the Borrower or any Guarantor’s identity or corporate structure or in the jurisdiction in which such Person is incorporated or formed, and (d) in the Borrower or any Guarantor’s federal taxpayer identification number.

(xii) Casualty and Condemnation. Prompt written notice, and in any event within three (3) Business Days, of the occurrence of any Casualty Event to the Mortgaged Property or the commencement of any action or proceeding for the taking of any material portion of the Mortgaged Property or any part thereof or interest therein under power of eminent domain or by condemnation, nationalization or similar proceeding.

(xiii) Lists of Purchasers. Promptly following the written request from the Administrative Agent thereof, a list of all Persons disbursing proceeds to the Borrower or any Restricted Subsidiary from its Oil and Gas Properties.

(xiv) Other Matters. From time to time, such other information regarding the business, affairs or financial condition of the Borrower or any Subsidiary (including, without limitation, any Plan or Multiemployer Plan and any reports or other information required to be filed under ERISA) as the Administrative Agent (at the request of any Lender) may reasonably request.

(xv) Intercompany Indebtedness. At the time it furnishes each set of financial statements under Sections 6.2.2(vi) above, a certificate executed by an Authorized Officer certifying as to the amount of all intercompany Indebtedness permitted to be incurred pursuant to Section 6.2.2(vi) outstanding as of the end of the respective Fiscal Year and setting forth in reasonable detail the lender and borrower with respect thereto, whether a Subordination Agreement from the lender with respect thereto has been provided to the Administrative Agent (which Subordination Agreement shall remain in full force and effect as of the date of such certificate) and such additional information related thereto as the Administrative Agent may request.

6.1.2. Litigation. The Borrower shall promptly give to the Administrative Agent notice of all legal or arbitral proceedings, and of all proceedings before any Governmental

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Authority filed against the Borrower or any Restricted Subsidiary, except proceedings which, if adversely determined, could not reasonably be expected to result in liability not fully covered by insurance, subject to normal deductibles, in excess of $2,000,000 (whether individually or in the aggregate).

6.1.3. Maintenance, Compliance with Laws, Inspections, Insurance, Etc.

(i) The Borrower shall, and shall cause each Restricted Subsidiary to: (a) except as permitted in Section 6.2.10, preserve and maintain its existence and all of its material rights, privileges and franchises and maintain, if necessary, its qualification to do business in each other jurisdiction in which its Oil and Gas Properties is located or the ownership of its Properties requires such qualification, except where the failure to so qualify could not reasonably be expected to have a Material Adverse Effect; (b) keep books of record and account in accordance with GAAP; (c) comply with all Governmental Requirements if failure to comply with such requirements could reasonably be expected to have a Material Adverse Effect; (d) upon reasonable notice, permit representatives of the Administrative Agent or any Lender, during normal business hours, to examine, copy and make extracts from its books and records, to inspect its Properties, and to discuss its business and affairs with its officers, all to the extent reasonably requested by such Lender or the Administrative Agent (as the case may be); and (e) keep, or cause to be kept, insured by financially sound and reputable insurers all Property of a character usually insured by Persons engaged in the same or similar business similarly situated against loss or damage of the kinds and in the amounts customarily insured against by such Persons and carry such other insurance against risks as is usually carried by such Persons. The loss payable clauses or provisions in said insurance policy or policies insuring any of the Collateral shall be endorsed in favor of and made payable to the Administrative Agent as its interests may appear and naming the Administrative Agent and the Lenders as “additional insureds” and shall provide that the insurer will endeavor to give at least 30 days prior notice of any cancellation to the Administrative Agent.

(ii) Contemporaneously with the delivery of the financial statements required by Section 6.1.1(i) to be delivered for each year, the Borrower will furnish or cause to be furnished to the Administrative Agent a certificate of insurance coverage from the insurer in form and substance satisfactory to the Administrative Agent and, if requested, will furnish the Administrative Agent and the Lenders copies of the applicable policies.

(iii) The Borrower will, and will cause each Restricted Subsidiary to, operate its Properties or cause such Properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable contracts and agreements and in compliance with all Governmental Requirements, including, without limitation, applicable pro ration and Environmental Laws and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom, except, in each case, where the failure to comply could not reasonably be expected to have a Material Adverse Effect.

(iv) The Borrower, at its own expense, will, and will cause each Restricted Subsidiary to, do or cause to be done all things reasonably necessary to preserve and keep in good repair,

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working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material Properties, including, without limitation, all equipment, machinery and facilities, and from time to time will make all the reasonably necessary repairs, renewals and replacements so that at all times the state and condition of its material Oil and Gas Properties and other material Properties will be preserved and maintained, except to the extent a portion of such Properties is no longer capable of commercially producing Hydrocarbons. The Borrower will, and will cause each Restricted Subsidiary to, promptly: (a) pay and discharge, or make reasonable and customary efforts to cause to be paid and discharged, all delay rentals, royalties, expenses and indebtedness accruing under the leases or other agreements affecting or pertaining to its Oil and Gas Properties and will do all other things necessary to keep unimpaired their rights with respect thereto and prevent any forfeiture thereof or default thereunder, and (b) perform or make reasonable and customary efforts to cause to be performed, in accordance with industry standards, the obligations required by each and all of the assignments, deeds, leases, sub-leases, contracts and agreements affecting its interests in its Oil and Gas Properties and other material Properties, except in each case of clauses (a) and (b) to the extent a portion of such Properties is no longer capable of producing Hydrocarbons in economically reasonable amounts and except for dispositions permitted by Section 6.2.11. The Borrower will and will cause each Restricted Subsidiary to operate its Oil and Gas Properties and other material Properties or cause or make reasonable and customary efforts to cause such Oil and Gas Properties and other material Properties to be operated in accordance with the practices of the industry and in material compliance with all applicable contracts and agreements and in compliance in all material respects with all Governmental Requirements. To the extent the Borrower is not the operator of such Property, the Borrower shall use reasonable efforts to cause the operator to comply with this Section 6.1.3(iv).

6.1.4. Environmental Matters.

(i) The Borrower will, and will cause each Restricted Subsidiary to, establish and implement such procedures as may be reasonably necessary to continuously determine and assure that any failure of the following could not reasonably be expected to have a Material Adverse Effect: (a) all Property of the Borrower and the Restricted Subsidiaries and the operations conducted thereon and other activities of the Borrower and the Restricted Subsidiaries are in compliance with and do not violate the requirements of any Environmental Laws, (b) no oil, oil and gas production or exploration wastes, hazardous substances or solid wastes are disposed of or otherwise released on or to any Property owned by any such party except in compliance with Environmental Laws, (c) no hazardous substance will be released on or to any such Property in a quantity equal to or exceeding that quantity which requires reporting pursuant to Section 103 of CERCLA and (d) no oil, oil and gas exploration and production wastes or hazardous substances or solid wastes are released on or to any such Property so as to pose an imminent and substantial endangerment to public health or welfare or the environment.

(ii) The Borrower will promptly notify the Administrative Agent and the Lenders in writing of any threatened action, investigation or inquiry by any Governmental Authority against the Borrower or any of its Restricted Subsidiaries or their Properties which the Borrower has knowledge in connection with any Environmental Laws (excluding routine testing and corrective action) if the Borrower reasonably anticipates that such action will result in liability, not fully covered by insurance, subject to normal deductibles, (whether individually or in the aggregate) in excess of $2,000,000.

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6.1.5. Further Assurances. The Borrower at its expense will, and will cause each Restricted Subsidiary to, promptly execute and deliver to the Administrative Agent all such other documents, agreements and instruments reasonably requested by the Administrative Agent to comply with, cure any defects or accomplish the covenants and agreements of the Borrower or any Restricted Subsidiary, as the case may be, in the Collateral Documents, Obligations and this Agreement, or to further evidence and more fully describe the Collateral, or to correct any omissions in the Collateral Documents, or to state more fully the security obligations set out herein or in any of the Collateral Documents, or to perfect, protect or preserve any Liens created pursuant to any of the Collateral Documents or the priority thereof, or to make any recordings, file any notices or obtain any consents, all as may be reasonably necessary or appropriate in connection therewith.

6.1.6. Performance of Obligations. The Borrower will pay the Obligations according to the terms set forth in this Agreement and the Loan Documents and the Borrower will and will cause each Restricted Subsidiary to do and perform every act and discharge all of the obligations to be performed and discharged by them under the Loan Documents and this Agreement, at the time or times and in the manner specified.

6.1.7. Reserve Reports.

(i) On or before March 1 and September 1 of each year, commencing March 1, 2004, the Borrower shall furnish to the Administrative Agent and the Lenders a Reserve Report. The Reserve Report as of December 31 of each year shall be prepared by one or more Approved Petroleum Engineers, and the June 30 Reserve Report of each year shall be prepared by or under the supervision of the chief engineer of the Borrower who shall certify such Reserve Report to be true and accurate and to have been prepared in accordance with the procedures used in the immediately preceding December 31 Reserve Report.

(ii) In the event of an unscheduled redetermination of the Borrowing Base, the Borrower shall furnish to the Administrative Agent and the Lenders a Reserve Report prepared by or under the supervision of the chief engineer of the Borrower who shall certify such Reserve Report to be true and accurate and to have been prepared in accordance with the procedures used in the immediately preceding Reserve Report. For any unscheduled redetermination requested by the Required Lenders or the Borrower pursuant to Section 2.21(v), the Borrower shall provide such Reserve Report with an “as of” date as required by the Administrative Agent as soon as possible, but in any event no later than thirty (30) days following the receipt of such request.

(iii) With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent and the Lenders, a certificate from an Authorized Officer certifying that, to the best of his knowledge and in all material respects: (a) the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct, (b) the Borrower or its Restricted Subsidiaries owns good and defensible title to the Oil and Gas Properties evaluated in such Reserve Report and such Properties are free of all Liens except for Liens permitted by Section 6.2.3, (c) except as set forth on an exhibit to the certificate, on a net

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basis there are no gas imbalances, take or pay or other prepayments with respect to its Oil and Gas Properties evaluated in such Reserve Report which would require the Borrower or any Restricted Subsidiary to deliver Hydrocarbons produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor, (d) none of their Oil and Gas Properties have been sold since the date of the last Borrowing Base determination except as set forth on an exhibit to the certificate, which certificate shall list all of its Oil and Gas Properties sold and in such detail as reasonably required by the Required Lenders and (e) attached thereto is a schedule of the Oil and Gas Properties evaluated by such Reserve Report that are Mortgaged Property.

6.1.8. Title Information.

(i) The Administrative Agent shall have received not later than ninety (90) days immediately following the Closing Date title opinions or other title information, as the Administrative Agent may reasonably require, satisfactory to the Administrative Agent setting forth the status of title to at least 60% of the value of the Oil and Gas Properties evaluated in the Initial Reserve Report and included in the Borrowing Base.

(ii) On or before the delivery to the Administrative Agent and the Lenders of each Reserve Report required by Section 6.1.7(i), the Borrower will deliver title information in form and substance acceptable to the Administrative Agent covering enough of the Oil and Gas Properties evaluated by such Reserve Report that were not included in the immediately preceding Reserve Report, so that the Administrative Agent shall have received together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 60% of the value of the Oil and Gas Properties evaluated by such Reserve Report.

(iii) If the Borrower has provided title information for additional Properties under Section 6.1.8(ii), the Borrower shall, within 60 days of notice from the Administrative Agent that title defects or exceptions exist with respect to such additional Properties, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) which are not permitted by Section 6.2.3 raised by such information, (ii) substitute acceptable Mortgaged Properties with no title defects or exceptions (except for Excepted Liens) having an equivalent value or (iii) deliver title information in form and substance acceptable to the Administrative Agent so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, satisfactory title information on at least 60% of the value of the Oil and Gas Properties evaluated by such Reserve Report.

(iv) If the Borrower is unable to cure any title defect requested by the Administrative Agent or the Lenders to be cured within the 60-day period or the Borrower does not comply with the requirements to provide acceptable title information covering 60% of the value of the Oil and Gas Properties evaluated in the most recent Reserve Report, such default shall not be a Default or an Unmatured Default, but instead the Administrative Agent and the Lenders shall have the right to exercise the following remedy in their sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by the Administrative Agent or the Lenders. To the extent that the Administrative Agent or the Lenders are not satisfied with title to any Mortgaged Property after the 60-day period has elapsed, such unacceptable Mortgaged Property shall not count towards the 60% requirement,

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and the Administrative Agent may send a notice to the Borrower and the Lenders that the then outstanding Borrowing Base shall be reduced by an amount as determined by the Majority Lenders to cause the Borrower to be in compliance with the requirement to provide acceptable title information on 60% of the value of the Oil and Gas Properties evaluated in the most recent Reserve Report. This new Borrowing Base shall become effective immediately after receipt of such notice.

6.1.9. Additional Collateral; Additional Guarantors.

(i) In connection with each redetermination of the Borrowing Base, the Borrower shall review the Reserve Report and the list of current Mortgaged Properties to ascertain whether the Mortgaged Properties represent at least the lesser of (i) 75% of the total value of the Oil and Gas Properties evaluated in the most recent Reserve Report and included in the Borrowing Base after giving effect to exploration and production activities, acquisitions, dispositions and production or (ii) 125% of the Aggregate Commitment. In the event that the Mortgaged Properties do not represent at least the lesser or (i) 75% of such total value or (ii) 125% of the Aggregate Commitment, then the Borrower shall, and shall cause its Restricted Subsidiaries to, grant to the Administrative Agent as security for the Obligations a first-priority Lien interest (subject only to Excepted Liens of the type described in clauses (i) to (v), (vii) and (viii) of the definition thereof) on additional Oil and Gas Properties not already subject to a Lien of the Collateral Documents such that after giving effect thereto, the Mortgaged Properties will represent at least the lesser of (i) 75% of such total value or (ii) 125% of the Aggregate Commitment. All such Liens will be created and perfected by and in accordance with the provisions of mortgages, deeds of trust, security agreements and financing statements, or other Collateral Documents, all in form and substance reasonably satisfactory to the Administrative Agent and in sufficient executed (and acknowledged where necessary or appropriate) counterparts for recording purposes. In order to comply with the foregoing, if any Restricted Subsidiary places a Lien on its Oil and Gas Properties and such Restricted Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with Section 6.1.9(ii).

(ii) In the event that the Borrower determines that any Subsidiary is a Material Domestic Subsidiary, the Borrower shall promptly cause such Material Domestic Subsidiary to guarantee the Obligations pursuant to the Guaranty. In connection with any such guaranty, the Borrower shall, or shall cause such Material Domestic Subsidiary or another Subsidiary to, (a) execute and deliver a supplement to the Guaranty executed by such Domestic Material Subsidiary, (b) pledge all of the capital stock of such Domestic Material Subsidiary (including, without limitation, delivery of original stock certificates evidencing the capital stock of such Material Domestic Subsidiary, together with an appropriate undated stock powers for each certificate duly executed in blank by the registered owner thereof) and (c) execute and deliver such other additional closing documents, certificates and legal opinions as shall reasonably be requested by the Administrative Agent.

6.1.10. ERISA Information and Compliance. As soon as available, and in any event, within ten (10) days after the Borrower obtains knowledge of any of the following, the Borrower will furnish and will cause each ERISA Affiliate to promptly furnish to the Administrative Agent with sufficient copies to the Lenders (i) a written notice signed by an Authorized Officer describing the occurrence of any ERISA Event or of any material “prohibited

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transaction,” as described in section 406 of ERISA or in section 4975 of the Code, in connection with any Plan or any trust created thereunder, and specifying what action the Borrower or the ERISA Affiliate is taking or proposes to take with respect thereto, and, when known, any action taken or proposed by the Internal Revenue Service, the Department of Labor or the PBGC with respect thereto, (ii) copies of any notice of the PBGC’s intention to terminate or to have a trustee appointed to administer any Plan and (iii) a written notice of the Borrower’s or an ERISA Affiliate’s participation in a Multiemployer Plan. With respect to each Plan (other than a Multiemployer Plan), the Borrower will, and will cause each ERISA Affiliate to, (a) satisfy in full and in a timely manner, without incurring any material late payment or underpayment charge or penalty and without giving rise to any Lien, all of the contribution and funding requirements of section 412 of the Code (determined without regard to subsections (d), (e), (f) and (k) thereof) and of section 302 of ERISA (determined without regard to sections 303, 304 and 306 of ERISA), and (b) pay, or cause to be paid, to the PBGC in a timely manner, without incurring any material late payment or underpayment charge or penalty, all premiums required pursuant to sections 4006 and 4007 of ERISA.

6.1.11. Business of the Borrower. The primary business of the Borrower and its consolidated Restricted Subsidiaries is and will continue to be the acquisition, exploration for, development, production, transportation, processing and marketing of Hydrocarbons and accompanying minerals.

6.1.12. Payment of Taxes and Claims. The Borrower will pay, and will cause each of its Restricted Subsidiaries to pay, (i) all taxes imposed upon it or any of its assets or with respect to any of its franchises, business, income or profits before any material penalty or interest accrues thereon and (ii) all material claims (including, without limitation, claims for labor, services, materials and supplies) for sums which have become due and payable and which by law have or might become a Lien (other than an Excepted Lien) on any of its assets; provided, however, no payment of taxes or claims shall be required if (a) the amount, applicability or validity thereof is currently being contested in good faith by appropriate action promptly initiated and diligently conducted in accordance with good business practices and no material part of the property or assets of the Borrower or any of its Restricted Subsidiaries are subject to levy or execution, and (b) the Borrower as and to the extent required in accordance with GAAP, shall have set aside on its books reserves (segregated to the extent required by GAAP) deemed by it to be adequate with respect thereto.

6.1.13. Permits, Licenses. The Borrower shall, and shall cause each Restricted Subsidiary to, maintain all material patents, copyrights, trademarks, service marks and trade names necessary to conduct its business, including, without limitation all consents, permits, licensees and agreements material to their Oil and Gas Properties.

6.1.14. Legal Opinion. The Borrower shall deliver to the Administrative Agent not later than December 19, 2003, the written opinion of Vinson & Elkins L.L.P., as special counsel to Borrower and the Guarantors, addressed to the Lenders with respect to, inter alia, the enforceability of this Agreement, the Guaranty, the Pledge Agreement and the Subordination Agreement, each as delivered in accordance with Section 4.1, which opinion shall be in form and substance satisfactory to the Administrative Agent.

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6.2. Negative Covenants

6.2.1. Financial Covenants.

(i) Total Debt to EBITDAX Ratio. The Borrower will not permit at any time its ratio of Total Debt to EBITDAX (calculated quarterly at the end of each Fiscal Quarter on a rolling four quarter basis) to be more than 3.5 to 1.0.

(ii) EBITDAX to Interest Expense Ratio. The Borrower will not permit at any time its ratio of EBITDAX to Interest Expense (calculated quarterly at the end of each Fiscal Quarter on a rolling four quarter basis) to be less than 2.5 to 1.0.

6.2.2. Indebtedness. Neither the Borrower nor any Restricted Subsidiary will incur, create, assume or suffer to exist any Indebtedness, except:

(i) the Obligations arising under the Loan Documents or any guaranty of or suretyship arrangement for the Obligations arising under the Loan Documents;

(ii) Indebtedness of the Borrower and its Restricted Subsidiaries existing on the Closing Date that is listed in Schedule 6.2.2, and any refinancings, renewals or extensions (but not increases) thereof;

(iii) accounts payable (for the deferred purchase price of Property or services) from time to time incurred in the ordinary course of business which, if greater than ninety (90) days past the invoice or billing date, are being contested in good faith by appropriate proceedings if reserves adequate under GAAP shall have been established therefor;

(iv) Indebtedness under Capital Leases (as required to be reported on the financial statements of the Borrower pursuant to GAAP) not to exceed $5,000,000;

(v) Indebtedness associated with bonds or surety obligations required by Governmental Requirements in connection with the operation of the Oil and Gas Properties;

(vi) unsecured intercompany Indebtedness between (a) the Borrower and any Restricted Subsidiary or between Restricted Subsidiaries to the extent permitted by Section 6.2.5(vii); provided that such Indebtedness is not held, assigned, transferred, negotiated or pledged to any Person other than the Borrower or a Restricted Subsidiary, and, provided further, that any such Indebtedness owed by either the Borrower or a Guarantor shall be subordinated to the Obligations on terms set forth in the Guaranty and (b) the Borrower and any Subsidiary of the Borrower or between Subsidiaries of the Borrower provided that such Indebtedness is not held, assigned, transferred, negotiated or pledged to any Person other than the Borrower or a Subsidiary of the Borrower, and, provided further that any such Indebtedness owed by the Borrower or a Guarantor to any Subsidiary of the Borrower that is not a Guarantor shall be subordinated to the Obligations on the term set forth in a Subordination Agreement that shall have been delivered by such Subsidiary to the Administrative Agent prior to the incurrence of such Indebtedness;

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(vii) endorsements of negotiable instruments for collection in the ordinary course of business;

(viii) Indebtedness under Rate Management Transactions permitted by Section 6.2.18; and

(ix) other Indebtedness (not included under subsections (i) through (viii) of this Section 6.2.2) not to exceed $10,000,000 in the aggregate at any one time outstanding.

6.2.3. Liens. Neither the Borrower nor any Restricted Subsidiary will create, incur, assume or permit to exist any Lien on any of its Properties (now owned or hereafter acquired), except:

(i) Liens securing the payment of any Obligations;

(ii) Excepted Liens;

(iii) Liens securing leases giving rise to Indebtedness allowed under Section 6.2.2(iv) but only on the Property under lease;

(iv) Liens (including the deposit of margin) on cash or other securities securing Rate Management Transactions permitted by Section 6.2.18, provided that the aggregate amount of cash and securities upon which such Liens have been granted do not exceed $7,500,000;

(v) Liens disclosed on Schedule 6.2.3;

(vi) any Lien arising out of the refinancing, extension, renewal or refunding of any Indebtedness secured by any Lien permitted by any of the foregoing clauses in this Section 6.2.3; provided that any such Indebtedness is not increased beyond the amount thereof outstanding on the Closing Date (other than increases associated with the capitalization of refinancing costs) and is not secured by any additional assets; and

(vii) additional Liens upon Property created after the date hereof, provided that the aggregate obligations secured thereby and incurred on or after the date hereof shall not exceed $1,000,000 in the aggregate at any one time outstanding.

6.2.4. Dividends, Distributions and Redemptions. The Borrower will not directly or indirectly declare or pay or incur any liability to pay, and the Borrower will not permit any of its Restricted Subsidiaries to directly or indirectly declare or pay, or incur any liability to pay any dividends or other distributions; provided that (i) any Subsidiary may pay dividends or make distributions to the Borrower or any Restricted Subsidiary, and (ii) if no Borrowing Base Deficiency then exists and no Default or Unmatured Default has occurred and is continuing or would result therefrom, the Borrower may (a) declare and pay dividends solely in additional shares of capital stock of the Borrower, (b) repurchase or redeem shares of its capital stock issued to its employees, officers or directors in an amount not to exceed $1,000,000 in any 12-month period, provided, however, that prior to January 1, 2004, the Borrower and its Restricted Subsidiaries may pay dividends or make distributions in an amount not to exceed $3,000,000 in the aggregate for all such dividends or distributions, and (c) on or after January 1, 2004, pay cash

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dividends and distributions to its shareholders from funds legally available for such purpose during any Fiscal Quarter in an amount not in excess of the amount of cash dividends or distributions received by the Borrower from the MLP during such Fiscal Quarter.

6.2.5. Investments, Loans and Advances. Neither the Borrower nor any Restricted Subsidiary will make or permit to remain outstanding any loans or advances to or investments in any Person, except that the foregoing restriction shall not apply to: (i) Investments reflected in the Financial Statements or which are disclosed to the Lenders in Schedule 6.2.5; (ii) accounts receivable arising in the ordinary course of business; (iii) direct obligations of the United States or any agency thereof, or obligations guaranteed by the United States or any agency thereof, in each case maturing within one year from the date of creation thereof; (iv) commercial paper maturing within one year from the date of creation thereof rated in the highest grade by S&P or Moody’s; (v) deposits maturing within one year from the date of creation thereof with, including certificates of deposit issued by, any Lender or any office located in the United States of any other bank or trust company which is organized under the laws of the United States or any state thereof, has capital, surplus and undivided profits aggregating at least $100,000,000 (as of the date of such Lender’s or bank or trust company’s most recent financial reports) and has a short term deposit rating of no lower than A2 or P2, as such rating is set forth from time to time, by S&P or Moody’s, respectively; (vi) deposits in money market funds investing exclusively in Investments described in Section 6.2.5(iii), 6.2.5(iv) or 6.2.5(v); (vii) Investments (a) made by the Borrower in or to the Guarantors, (b) made by any Restricted Subsidiary in the Borrower or any Guarantor, or (c) made by the Borrower or any Restricted Subsidiary in or to all other Domestic Subsidiaries which are not Guarantors in an aggregate amount at any one time outstanding not to exceed $5,000,000; (viii) Investments in direct ownership interests in additional Oil and Gas Properties and gas gathering systems related thereto or related to farm-out, farm-in, joint operating, joint venture or area of mutual interest agreements, gathering systems, pipelines or other similar arrangements which are usual and customary in the oil and gas exploration and production business; and (ix) other Investments, including Investments in Unrestricted Subsidiaries, not to exceed $10,000,000 in the aggregate at any time outstanding.

6.2.6. Designation and Conversion of Restricted and Unrestricted Subsidiaries; Indebtedness of Unrestricted Subsidiaries.

(i) Unless designated as an Unrestricted Subsidiary on Schedule 5.14 as of the Closing Date or thereafter pursuant to Section 6.2.6(ii), any Person that becomes a Subsidiary of the Borrower or any of its Restricted Subsidiaries shall be classified as a Restricted Subsidiary.

(ii) The Borrower may designate any Restricted Subsidiary or any newly formed or newly acquired Subsidiary of the Borrower or any Restricted Subsidiary as an Unrestricted Subsidiary if (a) such designation is made by the Borrower in a written notice to the Administrative Agent and (b) such designation is approved by a vote of all of the Lenders. Except as provided in this Section, no Restricted Subsidiary may be redesignated as an Unrestricted Subsidiary.

(iii) The Borrower may designate any Unrestricted Subsidiary to be a Restricted Subsidiary if after giving effect to such designation, (a) the representations and warranties of the

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Borrower and its Restricted Subsidiaries contained in each of the Loan Documents are true and correct on and as of such date as if made on and as of the date of such redesignation (or, if stated to have been made expressly as of an earlier date, were true and correct as of such date), (b) no Default or Unmatured Default would exist and (c) the Borrower complies with the requirements of Sections 6.1.9, 6.1.12 and 6.2.14. Any such designation shall be treated as a cash dividend in an amount equal to the lesser of (1) the Fair Market Value of the Borrower’s direct and indirect ownership interest in such Subsidiary or (2) the amount of the Borrower’s cash investment previously made for purposes of the limitation on Investments under Section 6.2.5(ix).

6.2.7. Nature of Business. Neither the Borrower nor any Restricted Subsidiary will allow any material change to be made in the character of its business as an independent oil and gas exploration and production company.

6.2.8. Proceeds of Loans. The Borrower will not permit the proceeds of the Obligations to be used for any purpose other than those permitted by Section 5.7. Neither the Borrower nor any Person acting on behalf of the Borrower has taken or will take any action which might cause any of the Loan Documents to violate Regulation T, U or X or any other regulation of the Board of Governors of the Federal Reserve System or to violate Section 7 of the Securities Exchange Act of 1934 or any rule or regulation thereunder, in each case as now in effect or as the same may hereinafter be in effect. If requested by the Administrative Agent, the Borrower will furnish to the Administrative Agent and each Lender a statement to the foregoing effect in conformity with the requirements of FR Form U-1 or such other form referred to in Regulation U, Regulation T or Regulation X of the Board of Governors of the Federal Reserve System, as the case may be.

6.2.9. ERISA Compliance. The Borrower will not at any time: (i) engage in, or permit any ERISA Affiliate to engage in, any transaction in connection with which the Borrower or any ERISA Affiliate could be subjected to either a material civil penalty assessed pursuant to section 502(c), (i) or (l) of ERISA or a material tax imposed by Chapter 43 of Subtitle D of the Code with respect to a Plan; (ii) terminate, or permit any ERISA Affiliate to terminate, any Plan in a manner, or take any other action with respect to any Plan, which could result in any liability to the Borrower or any ERISA Affiliate to the PBGC which could reasonably be expected to have a Material Adverse Effect; (iii) fail to make, or permit any ERISA Affiliate to fail to make, full payment when due of all amounts which, under the provisions of any Plan, agreement relating thereto or applicable law, the Borrower or any ERISA Affiliate is required to pay as contributions thereto if such failure could reasonably be expected to have a Material Adverse Effect; (iv) permit to exist, or allow any ERISA Affiliate to permit to exist, any accumulated funding deficiency within the meaning of Section 302 of ERISA or section 412 of the Code, whether or not waived, with respect to any Plan which exceeds $2,000,000; (v) except as provided in Section 6.2.9(vii), permit, or allow any ERISA Affiliate to permit, the actuarial present value of the benefit liabilities under any Plan maintained by the Borrower or any ERISA Affiliate which is regulated under Title IV of ERISA to exceed the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities by more than $2,000,000, with the term “actuarial present value of the benefit liabilities” having the meaning specified in section 4041 of ERISA; (vi) contribute to or assume an obligation to contribute to, or permit any Subsidiary or ERISA Affiliate to contribute to or assume an obligation to contribute to, any Multiemployer Plan if

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such action could reasonably be expected to have a Material Adverse Effect; (vii) acquire, or permit any ERISA Affiliate to acquire, an interest in any Person that causes such Person to become an ERISA Affiliate with respect to the Borrower or any ERISA Affiliate if such Person sponsors, maintains or contributes to, or at any time in the six-year period preceding such acquisition has sponsored, maintained, or contributed to, (a) any Multiemployer Plan if the funding status of such Multiemployer Plan is such that a total or partial withdrawal from it by such Person could reasonably be expected to have a Material Adverse Effect, or (b) any other Plan that is subject to Title IV of ERISA under which the actuarial present value of the benefit liabilities under such Plan exceeds the current value of the assets (computed on a plan termination basis in accordance with Title IV of ERISA) of such Plan allocable to such benefit liabilities by an amount in excess of $2,000,000; (viii) incur, or permit any ERISA Affiliate to incur, a liability to or on account of a Plan under sections 515, 4062, 4063, 4064, 4201 or 4204 of ERISA in excess of $2,000,000; or (ix) amend, or permit any ERISA Affiliate to amend, a Plan resulting in an increase in current liability such that the Borrower or any ERISA Affiliate is required to provide security to such Plan under section 401(a)(29) of the Code.

6.2.10. Mergers, Etc. Neither the Borrower nor any Restricted Subsidiary will merge into or with or consolidate with any other Person, or sell, lease or otherwise dispose of (whether in one transaction or in a series of transactions) all or substantially all of its Property or assets to any other Person (any such transaction, a “consolidation”); provided that

(i) the Borrower or any Restricted Subsidiary may participate in a consolidation with any other Person; provided that (a) no Default or Unmatured Default is continuing, (b) any such consolidation would not cause a Default or Unmatured Default hereunder, (c) if the Borrower consolidates with any Person, the Borrower shall be the surviving Person, (d) if any Restricted Subsidiary consolidates with any Person (other than the Borrower or a Restricted Subsidiary) and such Restricted Subsidiary is not the surviving Person, such surviving Person shall expressly assume in writing (in form and substance satisfactory to the Administrative Agent) all obligations of such Restricted Subsidiary under the Loan Documents and (e) the Borrowing Base will be redetermined in accordance with Section 2.21; and

(ii) any Restricted Subsidiary may participate in a consolidation with the Borrower (provided that the Borrower shall be the continuing or surviving corporation) or any other Restricted Subsidiary (provided that the surviving entity shall be a Restricted Subsidiary).

6.2.11. Sale of Oil and Gas Properties. The Borrower will not, and will not permit any Restricted Subsidiary to, sell, assign, farm-out, convey or otherwise transfer any Oil and Gas Property or any interest in any Oil and Gas Property except for (i) the sale of Hydrocarbons in the ordinary course of business; (ii) farmouts of undeveloped acreage and assignments in connection with such farmouts; (iii) the sale or transfer of equipment that is no longer necessary for the business of the Borrower or such Restricted Subsidiary or is replaced by equipment of at least comparable value and use; (iv) the sale, transfer or other disposition of equity interests in Unrestricted Subsidiaries; (v) the sale, transfer or other disposition of the Oil and Gas Properties described on Schedule 6.2.11 - West Texas Asset Disposition; and (vi) sales or other dispositions (including Casualty Events and dispositions resulting from the exercise of eminent domain, condemnation or nationalization) of Oil and Gas Properties or any interest therein or, with the prior written consent of the Required Lenders, all capital stock or other

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equity interests in Restricted Subsidiaries owning Oil and Gas Properties; provided that such sales or other dispositions of Oil and Gas Properties or of Restricted Subsidiaries owning Oil and Gas Properties included in the most recently delivered Reserve Report during any period between two successive Scheduled Redetermination Dates having a fair market value in excess of $15,000,000, individually or in the aggregate, shall result in an adjustment to the Borrowing Base in an amount equal to the value, if any, assigned such Property by the Required Lenders in good faith as provided in Section 2.21(ii); and provided further that if any such sale or other disposition is of a Restricted Subsidiary owning Oil and Gas Properties, such sale or other disposition shall include all the capital stock of such Restricted Subsidiary. To determine the amount by which the Borrowing Base shall be adjusted, the Borrower shall give the Administrative Agent and the Lenders notice of the proposed sale or other disposition not less than ten (10) days prior to the date of the proposed sale or other disposition. The Administrative Agent shall, in good faith and utilizing the Engineering Reports delivered in connection with the most recent redetermination of the Borrowing Base (or the initial determination, as applicable), propose to the Lenders a reduction to the Borrowing Base to reflect the value of the Properties being sold or otherwise disposed of. Thereafter, the Lenders shall have five (5) days to approve or object to such proposed amount; and any failure to object shall be deemed to be an approval. In the event there is no approval or deemed approval, the Administrative Agent shall poll the Lenders to ascertain the lowest reduction to the Borrowing Base then acceptable to a number of Lenders sufficient to constitute the Required Lenders for purposes of this Section 6.2.11 and such amount shall then be the allocated value of the Property subject to such sale or disposition.

6.2.12. Environmental Matters. Neither the Borrower nor any Restricted Subsidiary will cause or permit any of its Property to be in violation of, or do anything or permit anything to be done which will subject any such Property to any remedial obligations under any Environmental Laws, assuming disclosure to the applicable Governmental Authority of all relevant facts, conditions and circumstances, if any, pertaining to such Property where such violations or remedial obligations could reasonably be expected to result in an Environmental Liability to the Borrower or any of its Restricted Subsidiaries in excess of $4,000,000.

6.2.13. Transactions with Affiliates. Neither the Borrower nor any Restricted Subsidiary will enter into any transaction, including, without limitation, any purchase, sale, lease or exchange of Property or the rendering of any service, with any Affiliate (other than the Guarantors and wholly-owned Subsidiaries of the Borrower) unless such transactions are otherwise permitted under this Agreement and are upon fair and reasonable terms no less favorable to it than it would obtain in a comparable arm’s length transaction with a Person not an Affiliate.

6.2.14. Subsidiaries. The Borrower shall not, and shall not permit any Restricted Subsidiary to, create or acquire any additional Restricted Subsidiary or redesignate an Unrestricted Subsidiary as a Restricted Subsidiary unless the Borrower complies with Section 6.1.9(ii). The Borrower shall not, and shall not permit any Restricted Subsidiary to, sell, assign or otherwise dispose of any capital stock in any Restricted Subsidiary except in compliance with Section 6.2.11(vi).

6.2.15. Negative Pledge Agreements. Neither the Borrower nor any Restricted Subsidiary will create, incur, assume or suffer to exist any contract, agreement or understanding

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(other than this Agreement, the Collateral Documents, instruments governing Indebtedness permitted under Section 6.2.2(viii) or other instruments creating Liens permitted by Section 6.2.3(iii) and (v)) which in any way prohibits or restricts the granting, conveying, creation or imposition of any Lien on any of its Property in favor of the Agents, the LC Issuer and the Lenders or restricts any Restricted Subsidiary from paying dividends to the Borrower, or which requires the consent of or notice to other Persons in connection therewith.

6.2.16. Gas Imbalances, Take-or-Pay or Other Prepayments. The Borrower will not allow gas imbalances, take-or-pay or other prepayments with respect to the Oil and Gas Properties of the Borrower and its Restricted Subsidiaries that would require the Borrower or its Restricted Subsidiaries to deliver Hydrocarbons produced on Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor in excess of two (2) Bcf of gas (or its equivalent) in the aggregate on a net basis for the Borrower and its Restricted Subsidiaries.

6.2.17. Fiscal Year; Fiscal Quarter. The Borrower shall not, and shall not permit any of its Subsidiaries to, change its Fiscal Year or any of its Fiscal Quarters.

6.2.18. Rate Management Transactions. The Borrower will not enter into, and the Borrower will not permit any of its Restricted Subsidiaries to enter into, any Rate Management Transactions in respect of Hydrocarbons which would cause the amount of Hydrocarbons which are the subject of Rate Management Transactions in existence at such time to exceed either (i) eighty percent (80%) of the Borrower’s and its Restricted Subsidiaries’ projected production from Proved Hydrocarbon Reserves during the term of such existing Rate Management Transactions as set forth on the most current Reserve Report or (ii) ninety percent (90%) of the Borrower’s and its Restricted Subsidiaries’ projected production from Proved Developed Producing Hydrocarbon Reserves during the term of such existing Rate Management Transactions as set forth on the most current Reserve Report. The Borrower will not, and the Borrower will not permit any of its Restricted Subsidiaries to, post letters of credit to secure obligations under Rate Management Transactions which, when added to the amount of cash and other securities pledged under Section 6.2.3(iv) exceeds $7,500,000 in aggregate for all such Rate Management Transactions. For purposes of this Section 6.2.18, forecasts of projected production shall equal the projections for Proved Hydrocarbon Reserves or Proved Developed Producing Hydrocarbon Reserves, as applicable, set out in the most recent Reserve Report as revised to account for any increase or decrease therein anticipated because of information obtained by Borrower subsequent to the publication of the most recent Reserve Report including the Borrower’s internal forecasts of production decline rates for existing wells and additions to or deletions from anticipated future production from new wells and acquisitions coming on stream or failing to come on stream.

6.2.19. Restricted Subsidiaries. Except as permitted by Sections 6.2.10 and 6.2.11(vi), at all times, the Borrower shall directly or indirectly through a wholly-owned Restricted Subsidiary retain full, absolute and unencumbered title to all of the issued and outstanding stock or other ownership interests in each Restricted Subsidiary.

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ARTICLE VII

DEFAULTS

7.1. Events of Default. The occurrence of any one or more of the following events shall constitute a “Default”:

(i) the Borrower shall default in the payment or prepayment when due of any Obligation, or any fees or other amount payable by it hereunder or under any Loan Document and such default, other than a default of a payment or prepayment of principal (which shall have no cure period), shall continue unremedied for a period of three (3) Business Days;

(ii) (a) the Borrower or any Restricted Subsidiary shall default in the payment when due of any principal of or interest on any of its other Indebtedness in principal outstanding amount aggregating $5,000,000 or more, or any event specified in any note, agreement, indenture or other document evidencing or relating to any such Indebtedness shall occur if the effect of such event is to cause, or (with the giving of any notice or the lapse of time or both) to permit the holder or holders of such Indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, such Indebtedness to become due prior to its stated maturity or (b) a default or early termination event shall occur and be continuing under any Rate Management Transaction between the Borrower or any Restricted Subsidiary and any other Person which results in a net payment being due by the Borrower or such Restricted Subsidiary in excess of $5,000,000 and such payment is not paid when due or within three (3) Business Days thereafter;

(iii) any material representation or warranty made or deemed made herein or in any Loan Document by the Borrower or any Restricted Subsidiary, or any certificate furnished to any Lender or the Administrative Agent pursuant to the provisions hereof or any Loan Document, shall prove to have been false or misleading as of the time made or furnished in any material respect;

(iv) (a) the Borrower or any Restricted Subsidiary shall default in the performance of any of its obligations under Section 6.2 or (b) the Borrower or any Restricted Subsidiary shall default in the performance of any of its obligations under this Agreement (other than Section 6.2) or any other Loan Document (other than the payment of amounts due which shall be governed by Section 7.1(i)) and such default shall continue unremedied for a period of thirty (30) days after the earlier to occur of (1) notice thereof to the Borrower by the Administrative Agent or any Lender (through the Administrative Agent) or (2) an Authorized Officer of the Borrower or such Restricted Subsidiary otherwise becoming aware of such default;

(v) the Borrower or any Restricted Subsidiary shall admit in writing its inability to, or be generally unable to, pay its debts as such debts become due;

(vi) the Borrower or any Restricted Subsidiary shall (a) apply for or consent to the appointment of, or the taking of possession by, a receiver, custodian, trustee or liquidator of itself or of all or a substantial part of its Property, (b) make a general assignment for the benefit of its creditors, (c) commence a voluntary case under the Federal Bankruptcy Code (as now or hereafter in effect), (d) file a petition seeking to take advantage of any other law relating to

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bankruptcy, insolvency, reorganization, winding-up, liquidation or composition or readjustment of debts, (e) fail to controvert in a timely and appropriate manner, or acquiesce in writing to, any petition filed against it in an involuntary case under the Federal Bankruptcy Code or (f) take any action for the purpose of effecting any of the foregoing;

(vii) a proceeding or case shall be commenced, without the application or consent of the Borrower or any Restricted Subsidiary in any court of competent jurisdiction, seeking (a) its liquidation, reorganization, dissolution or winding-up, or the composition or readjustment of its debts, (b) the appointment of a trustee, receiver, custodian, liquidator or the like of such Person of all or any substantial part of its assets, (c) similar relief in respect of such Person under any law relating to bankruptcy, insolvency, reorganization, winding-up, or composition or adjustment of debts, and such proceeding or case shall continue undismissed, or an order, judgment or decree approving or ordering any of the foregoing shall be entered and continue unstayed and in effect, for a period of sixty (60) days or (d) an order for relief against such Person shall be entered in an involuntary case under the Federal Bankruptcy Code;

(viii) a judgment or judgments for the payment of money in excess of $5,000,000 (net of any amount payable because of insurance) in the aggregate shall be rendered by a court against the Borrower or any Restricted Subsidiary and the same shall not be discharged (or provision shall not be made for such discharge), or a stay of execution thereof shall not be procured, within thirty (30) days from the date of entry thereof and the Borrower or such Restricted Subsidiary shall not, within said period of thirty (30) days, or such longer period during which execution of the same shall have been stayed, appeal in good faith therefrom and cause the execution thereof to be stayed during such appeal;

(ix) the Loan Documents after delivery thereof shall for any reason, except to the extent permitted by the terms thereof, cease to be in full force and effect and valid, binding and enforceable in accordance with their terms against the Borrower or a Guarantor party thereto, or cease to create a valid and perfected Lien of the priority required thereby on any of the Collateral purported to be covered thereby, except to the extent permitted by the terms of this Agreement, or the Borrower or any Restricted Subsidiary or any of their Affiliates shall so state in writing; or

(x) any Person or two or more Persons acting as a group (as defined in Section 13(d)(3) of the Securities Exchange Act of 1934) shall have acquired beneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Securities Exchange Act of 1934) of 35% or more of the outstanding shares of voting stock of the Borrower; or individuals who, as of the Closing Date, constitute the Board of Directors of the Borrower (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors of the Borrower; provided, however, that any individual becoming a director of the Borrower subsequent to the date hereof whose election, or nomination for election by the Borrower’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board, shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened election contest (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Securities Exchange Act of 1934) or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board of Directors of the Borrower.

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ARTICLE VIII

ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES

8.1. Acceleration; Facility LC Collateral Amount. (i) If any Default described in Section 7.1(vi) or Section 7.1(vii) occurs with respect to the Borrower or any Guarantor, the obligations of the Lenders to make Loans hereunder and the obligation and power of the LC Issuer to issue Facility LCs shall automatically terminate and the Obligations shall immediately become due and payable without any election or action on the part of the Administrative Agent, the LC Issuer or any Lender and the Borrower will be and become thereby unconditionally obligated, without any further notice, act presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other formalities of any kind, all of which are hereby expressly waived by the Borrower, to pay to the Administrative Agent an amount in immediately available funds, which funds shall be held in the Facility LC Collateral Account, equal to the difference of (x) the amount of LC Obligations at such time, less (y) the amount on deposit in the Facility LC Collateral Account at such time which is free and clear of all rights and claims of third parties and has not been applied against the Obligations (such difference, the “Collateral Shortfall Amount”). If any other Default occurs, the Required Lenders (or the Administrative Agent with the consent of the Required Lenders) may (a) terminate or suspend the obligations of the Lenders to make Loans hereunder and the obligation and power of the LC Issuer to issue Facility LCs, or declare the Obligations to be due and payable, or both, whereupon the Obligations shall become immediately due and payable, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other formalities of any kind, all of which are hereby expressly waived by the Borrower, and (b) upon notice to the Borrower and in addition to the continuing right to demand payment of all Obligations, make demand on the Borrower to pay, and the Borrower will, forthwith upon such demand and without any further notice or act, pay to the Administrative Agent the Collateral Shortfall Amount, which funds shall be deposited in the Facility LC Collateral Account.

(ii) If at any time while any Default is continuing, the Administrative Agent determines that the Collateral Shortfall Amount at such time is greater than zero, the Administrative Agent may make demand on the Borrower to pay, and the Borrower will, forthwith upon such demand and without any further notice or act, pay to the Administrative Agent the Collateral Shortfall Amount, which funds shall be deposited in the Facility LC Collateral Account.

(iii) The Administrative Agent may at any time or from time to time after funds are deposited in the Facility LC Collateral Account, apply such funds to the payment of the Obligations and any other amounts as shall from time to time have become due and payable by the Borrower to the Lenders or the LC Issuer under the Loan Documents.

(iv) At any time while any Default is continuing, neither the Borrower nor any Person claiming on behalf of or through the Borrower shall have any right to withdraw any of the funds held in the Facility LC Collateral Account. After all of the Obligations have been indefeasibly paid in full and the Aggregate Commitment has been terminated, any funds remaining in the Facility LC Collateral Account shall be returned by the Administrative Agent to the Borrower or paid to whomever may be legally entitled thereto at such time.

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(v) If, within thirty (30) days after acceleration of the maturity of the Obligations or termination of the obligations (subject to the conditions of this Agreement) of the Lenders to make Loans and the obligation and power of the LC Issuer to issue Facility LCs hereunder as a result of any Default (other than any Default as described in Section 7.1(vi) or Section 7.1(vii) with respect to the Borrower) and before any judgment or decree for the payment of the Obligations due shall have been obtained or entered, the Required Lenders (in their sole discretion) shall so direct, the Administrative Agent shall, by notice to the Borrower, rescind and annul such acceleration and/or termination.

(vi) In the case of the occurrence of a Default, the Administrative Agent, the LC Issuer and the Lenders will have all other rights and remedies available at law and equity.

8.2. Amendments. Subject to the provisions of this Section 8.2, the Required Lenders (or the Administrative Agent with the consent in writing of the Required Lenders) and the Borrower may enter into agreements supplemental hereto for the purpose of adding or modifying any provisions to the Loan Documents or changing in any manner the rights of the Lenders or the Borrower hereunder or waiving any Default hereunder; provided, however, that no such supplemental agreement shall: (i) without the consent of all of the Lenders, (a) extend the final maturity of any Loan, or extend the expiry date of any Facility LC to a date after the Facility Termination Date, or postpone any regularly scheduled payment or date for mandatory prepayment of principal of any Loan or forgive all or any portion of the principal amount thereof or any Reimbursement Obligation related thereto, or reduce the rate or extend the time of payment of interest or fees thereon or Reimbursement Obligations related thereto; (b) forgive the principal amount of any Obligation under this Agreement or any other Loan Document; (c) reduce the interest rate applicable to the Loans or the fees payable to the Lenders generally; (d) reduce either percentage set forth in Section 6.1.9 to less than 75% or 125%, respectively; (e) reduce the percentage specified in the definition of Required Lenders; (f) increase the Borrowing Base; (g) modify Section 2.21; (h) amend this Section 8.2 or Section 12.3 or any related definitions contained in Section 1.1; (i) except as provided in the Collateral Documents, release any Guarantor or release all or substantially all of the Collateral (other than as provided in Section 10.16); or (j) permit the Borrower to assign its rights under this Agreement; or (ii) increase the amount of the Commitment of any Lender hereunder without the consent of such Lender.

No amendment, modification or waiver of any provision of this Agreement which modifies the rights, duties or obligations of, or which otherwise relates to, any Agent shall be effective without the written consent of such Agent, and no amendment, modification or waiver of any provision which modifies the rights, duties or obligations of, or which otherwise relates to, the LC Issuer shall be effective without the written consent of the LC Issuer. The Administrative Agent may waive payment of the fee required under Section 12.3.3 without obtaining the consent of any other party to this Agreement. Any supplement to Schedule 5.14 (Subsidiaries) shall be effective simply by delivering to the Administrative Agent a supplemental schedule clearly marked as such and, upon receipt, the Administrative Agent will promptly deliver a copy thereof to the Lenders.

8.3. Preservation of Rights. No delay or omission of the Lenders, the LC Issuer or the Administrative Agent in the exercise of any right under the Loan Documents shall impair such

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right or be construed to be a waiver of any Default or an acquiescence therein, and the making of a Credit Extension notwithstanding the existence of a Default or the inability of the Borrower to satisfy the conditions precedent to such Credit Extension shall not constitute any waiver or acquiescence. Any single or partial exercise of any such right shall not preclude other or further exercise thereof or the exercise of any other right, and no waiver, amendment or other variation of the terms, conditions or provisions of the Loan Documents whatsoever shall be valid unless in writing signed by the Lenders required pursuant to Section 8.2, and then only to the extent in such writing specifically set forth. All remedies contained in the Loan Documents or by law afforded shall be cumulative and all shall be available to the Agents, the LC Issuer and the Lenders until the Obligations have been paid in full.

8.4. Application of Payments. Any amount received by the Administrative Agent from the exercise of any rights or remedies hereunder or under any of the Collateral Documents shall be applied by the Administrative Agent to payment of the Obligations in the following order unless a court of competent jurisdiction shall otherwise direct:

(a) FIRST, to payment of all reasonable costs and expenses of the Administrative Agent incurred in connection with the collection and enforcement of the Obligations or of any security interest granted to the Administrative Agent in connection with any collateral securing the Obligations;

(b) SECOND, to payment of that portion of the Obligations constituting accrued and unpaid interest and fees, pro rata among the Lenders and their Affiliates in accordance with the amount of such accrued and unpaid interest and fees owing to each of them;

(c) THIRD, to payment of the principal of the Obligations and the net early termination payments and any other Lender Party Rate Management Obligations then due and unpaid from the Borrower to any of the Lenders or their Affiliates, pro rata among the Lenders and their Affiliates in accordance with the amount of such principal and such net early termination payments and other Lender Party Rate Management Obligations then due and unpaid owing to each of them;

(d) FOURTH, to payment of any Obligations (other than those listed above) pro rata among those parties to whom such Obligations are due in accordance with the amounts owing to each of them; and

(e) FIFTH, any surplus thereafter remaining shall be paid to the Borrower or it successor or assigns as its or their interests shall appear.

ARTICLE IX

GENERAL PROVISIONS

9.1. Survival of Representations. All representations and warranties of the Borrower contained in this Agreement shall survive the making of the Credit Extensions herein contemplated.

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9.2. Governmental Regulation. Anything contained in this Agreement to the contrary notwithstanding, neither the LC Issuer nor any Lender shall be obligated to extend credit to the Borrower in violation of any limitation or prohibition provided by any applicable statute or regulation.

9.3. Headings. Section headings in the Loan Documents are for convenience of reference only, and shall not govern the interpretation of any of the provisions of the Loan Documents.

9.4. Entire Agreement. The Loan Documents embody the entire agreement and understanding among the Borrower, the Administrative Agent, the LC Issuer and the Lenders and supersede all prior agreements and understandings among the Borrower, the Administrative Agent, the LC Issuer and the Lenders relating to the subject matter thereof other than those contained in the fee letter described in Section 10.13 which shall survive and remain in full force and effect during the term of this Agreement.

9.5. Several Obligations; Benefits of this Agreement. The respective obligations of the Agents, the Lenders and the LC Issuer hereunder are several and not joint and no Lender, Agent or LC Issuer shall be the partner or agent of any other (except to the extent to which the Administrative Agent or the LC Issuer is authorized to act as such). The failure of any Lender to perform any of its obligations hereunder shall not relieve any other Lender from any of its obligations hereunder. This Agreement shall not be construed so as to confer any right or benefit upon any Person other than the parties to this Agreement and their respective successors and assigns, provided, however, that the parties hereto expressly agree that the Co-Lead Arrangers shall enjoy the benefits of the provisions of Sections 9.6, 9.10 and 10.11 to the extent specifically set forth therein and shall have the right to enforce such provisions on its own behalf and in its own name to the same extent as if it were a party to this Agreement.

9.6. Expenses; Indemnification. (i) The Borrower shall reimburse the Administrative Agent, the LC Issuer and the Co-Lead Arrangers for any costs, internal charges and out-of-pocket expenses (including attorneys’ fees and time charges of attorneys for the Administrative Agent), paid or incurred by the Administrative Agent, the LC Issuer or the Co-Lead Arrangers in connection with the preparation, negotiation, execution, delivery, syndication, distribution (including, without limitation, via the internet), review, amendment, modification, and administration of the Loan Documents. The Borrower also agrees to reimburse the Agents, the Co-Lead Arrangers, the LC Issuer and the Lenders for any costs, internal charges and out-of-pocket expenses (including attorneys’ fees and time charges of attorneys for such Agent, the Co-Lead Arrangers, the LC Issuer and the Lenders), paid or incurred by such Agent, the Co-Lead Arrangers, the LC Issuer or any Lender in connection with the preservation of rights under, enforcement of, and refinancing, renegotiation or restructuring of, the Loan Documents and any amendment, waiver or consent related thereto and to satisfy any obligation of the Borrower under this Agreement or any Loan Document, including, without limitation, all costs and expenses of foreclosure. Expenses being reimbursed by the Borrower under this Section include, without limitation, costs and expenses incurred in connection with the Reports described in the following sentence. The Borrower acknowledges that from time to time Bank One may prepare and may distribute to the Lenders (but shall have no obligation or duty to prepare or to distribute to the Lenders) certain audit reports (the “Reports”) pertaining to the Borrower’s assets for internal use by Bank One from information furnished to it by or on behalf of the Borrower, after Bank One has exercised its rights of inspection pursuant to this Agreement.

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(ii) The Borrower hereby further agrees to indemnify the Agents, the Co-Lead Arrangers, the LC Issuer, each Lender, their respective Affiliates, and each of their directors, officers and employees (the “Indemnified Parties”) against all losses, claims, damages, penalties, judgments, liabilities and expenses (including, without limitation, all expenses of litigation or preparation therefor whether or not such Agent, the Co-Lead Arrangers, the LC Issuer, any Lender or any affiliate is a party thereto) which any of them may pay or incur arising out of or relating to this Agreement, the other Loan Documents, the transactions contemplated hereby or the direct or indirect application or proposed application of the proceeds of any Credit Extension hereunder except to the extent that they are determined in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the party seeking indemnification; PROVIDED THAT IT IS THE INTENTION OF THE PARTIES HERETO THAT THE INDEMNIFIED PARTIES BE INDEMNIFIED IN THE CASE OF THEIR OWN NEGLIGENCE, REGARDLESS OF WHETHER SUCH NEGLIGENCE IS SOLE OR CONTRIBUTORY, ACTIVE OR PASSIVE, IMPUTED, JOINT OR TECHNICAL. The obligations of the Borrower under this Section 9.6 shall survive the termination of this Agreement.

9.7. Numbers of Documents. All statements, notices, closing documents, and requests hereunder shall be furnished to the Administrative Agent with sufficient counterparts so that the Administrative Agent may furnish one to each of the Lenders.

9.8. Accounting. Except as provided to the contrary herein, all accounting terms used herein shall be interpreted and all accounting determinations hereunder shall be made in accordance with GAAP.

9.9. Severability of Provisions. Any provision in any Loan Document that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction, and to this end the provisions of all Loan Documents are declared to be severable.

9.10. Nonliability of Lenders. The relationship between the Borrower on the one hand and the Lenders, the LC Issuer and the Administrative Agent on the other hand shall be solely that of borrower and lender. Neither the Agents, the Co-Lead Arrangers, the LC Issuer nor any Lender shall have any fiduciary responsibilities to the Borrower or any of its Subsidiaries. None of the Agents, the Co-Lead Arrangers, the LC Issuer nor any Lender undertakes any responsibility to the Borrowers to review or inform the Borrower of any matter in connection with any phase of the Borrower’s or such Subsidiary’s business or operations. The Borrower agrees that none of the Agents, the Co-Lead Arrangers, the LC Issuer nor any Lender shall have liability to the Borrower or any of its Subsidiaries (whether sounding in tort, contract or otherwise) for losses suffered by the Borrower or any of its Subsidiaries in connection with, arising out of, or in any way related to, the transactions contemplated and the relationship established by the Loan Documents, or any act, omission or event occurring in connection therewith, unless it is determined in a final non-appealable judgment by a court of competent

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jurisdiction that such losses resulted from the gross negligence or willful misconduct of the party from which recovery is sought. None of the Agents, the Co-Lead Arrangers, the LC Issuer nor any Lender shall have any liability with respect to, and the Borrower hereby waives, releases and agrees not to sue for, any special, indirect, consequential or punitive damages suffered by the Borrower or any of its Subsidiaries in connection with, arising out of, or in any way related to the Loan Documents or the transactions contemplated thereby.

9.11. Confidentiality. Each Lender agrees to hold any confidential information which it may receive from the Borrower or any of its Restricted Subsidiaries pursuant to this Agreement or the other Loan Documents in confidence, except for disclosure (i) to its Affiliates and to other Lenders and their respective Affiliates, (ii) to legal counsel, accountants, and other professional advisors to such Lender or to a Transferee, (iii) to regulatory officials, (iv) to any Person as requested pursuant to or as required by law, regulation, or legal process, (v) to any Person in connection with any legal proceeding to which such Lender is a party, (vi) to such Lender’s direct or indirect contractual counterparties in swap agreements or to legal counsel, accountants and other professional advisors to such counterparties, (vii) permitted by Section 12.4 and (viii) to rating agencies if requested or required by such agencies in connection with a rating relating to the Advances hereunder. Notwithstanding anything to the contrary set forth herein or in any other agreement to which the parties hereto are parties or by which they are bound, the obligations of confidentiality contained herein and therein, as they relate to the transactions contemplated hereby (the “Transaction”), shall not apply to the tax structure or tax treatment of the Transaction, and each party hereto (and any employee, representative or agent of any party hereto) may disclose to any and all persons without limitation of any kind, the tax structure and tax treatment of the Transaction and all materials of any kind (including opinions or other tax analyses) that are provided to such party relating to such tax treatment and tax structure.

9.12. Nonreliance. Each Lender hereby represents that it is not relying on or looking to any margin stock (as defined in Regulation U of the Board of Governors of the Federal Reserve System) for the repayment of the Credit Extensions provided for herein.

9.13. Disclosure. The Borrower and each Lender hereby acknowledge and agree that Bank One and/or its Affiliates from time to time may hold investments in, make other loans to or have other relationships with the Borrower and its Affiliates.

9.14. Renewal and Continuation of Existing Indebtedness. Upon the effectiveness of this Agreement, all of the Existing Indebtedness outstanding on such date shall hereby be restructured, rearranged, renewed, extended and continued as provided in this Agreement and all Loans outstanding under the Prior Credit Agreement shall become Loans outstanding hereunder.

In connection herewith, the Prior Lenders have sold, assigned, transferred and conveyed, and Lenders party to this Agreement have purchased and accepted, and hereby purchase and accept, so much of the Existing Indebtedness such that each Lender’s percentage of the loans and obligations outstanding pursuant to the Prior Credit Agreement, as restructured, rearranged, renewed, extended and continued pursuant to this Agreement, shall be equal to such Lender’s Pro Rata Share upon the effectiveness of this Agreement. The Lenders acknowledge and agree that the assignment, transfer and conveyance of the Existing Indebtedness is without recourse to the Prior Lenders and without any warranties whatsoever by any Prior Lender, except as expressly set forth in the Assignment of Secured Indebtedness or the Mortgage Assignment and Amendment.

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9.15. Collateral Matters; Lender Party Rate Management Agreements. The benefit of the Collateral Documents and of the provisions of this Agreement relating to the Collateral shall also extend to and be available on a pro rata basis (as set forth in Section 8.4 of this Agreement) to each Lender or Affiliate of a Lender that is a counterparty to a Lender Party Rate Management Agreement in respect of any obligations of the Borrower or any of its Restricted Subsidiaries arising under such Lender Party Rate Management Transaction, but only so long as such Lender or its Affiliate remains a party to this Agreement and this Agreement remains in effect. No Lender or Affiliate of a Lender shall have any voting or consent right under this Agreement or any Collateral Document as a result of the existence of obligations owed to it under a Lender Party Rate Management Transaction.

ARTICLE X

THE ADMINISTRATIVE AGENT

10.1. Appointment; Nature of Relationship. Bank One, NA is hereby appointed by each of the Lenders and the LC Issuer as its contractual representative (herein referred to as the “Administrative Agent”) hereunder and under each other Loan Document, and each of the Lenders and the LC Issuer irrevocably authorizes the Administrative Agent to act as the contractual representative of such Lender and the LC Issuer with the rights and duties expressly set forth herein and in the other Loan Documents. The Administrative Agent agrees to act as such contractual representative upon the express conditions contained in this Article X. Notwithstanding the use of the defined term “Administrative Agent,” it is expressly understood and agreed that the Administrative Agent shall not have any fiduciary responsibilities to any Lender or the LC Issuer by reason of this Agreement or any other Loan Document and that the Administrative Agent is merely acting as the contractual representative of the Lenders and the LC Issuer with only those duties as are expressly set forth in this Agreement and the other Loan Documents. In its capacity as the Lenders’ and LC Issuer’s contractual representative, the Administrative Agent (i) does not hereby assume any fiduciary duties to any of the Lenders or the LC Issuer, (ii) is a “representative” of the Lenders and the LC Issuer within the meaning of the term “secured party” as defined in the Illinois Uniform Commercial Code and (iii) is acting as an independent contractor, the rights and duties of which are limited to those expressly set forth in this Agreement and the other Loan Documents. Each of the Lenders and the LC Issuer hereby agrees to assert no claim against the Administrative Agent on any agency theory or any other theory of liability for breach of fiduciary duty, all of which claims each Lender and the LC Issuer hereby waives.

10.2. Powers. The Administrative Agent shall have and may exercise such powers under the Loan Documents as are specifically delegated to the Administrative Agent by the terms of each thereof, together with such powers as are reasonably incidental thereto. The Administrative Agent shall have no implied duties to the Lenders or the LC Issuer, or any obligation to the Lenders or the LC Issuer to take any action thereunder except any action specifically provided by the Loan Documents to be taken by the Administrative Agent.

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10.3. General Immunity. Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable to the Borrower, the Lenders or any Lender or the LC Issuer for any action taken or omitted to be taken by it or them hereunder or under any other Loan Document or in connection herewith or therewith except to the extent such action or inaction is determined in a final non-appealable judgment by a court of competent jurisdiction to have arisen from the gross negligence or willful misconduct of such Person.

10.4. No Responsibility for Loans, Recitals, Etc. Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be responsible for or have any duty to ascertain, inquire into, or verify (i) any statement, warranty or representation made in connection with any Loan Document or any borrowing hereunder; (ii) the performance or observance of any of the covenants or agreements of any obligor under any Loan Document, including, without limitation, any agreement by an obligor to furnish information directly to each Lender or the LC Issuer; (iii) the satisfaction of any condition specified in Article IV, except receipt of items required to be delivered solely to the Administrative Agent; (iv) the existence or possible existence of any Default or Unmatured Default; (v) the validity, enforceability, effectiveness, sufficiency or genuineness of any Loan Document or any other instrument or writing furnished in connection therewith; (vi) the value, sufficiency, creation, perfection or priority of any Lien in any collateral security; or (vii) the financial condition of the Borrower or any guarantor of any of the Obligations or of any of the Borrower’s or any such guarantor’s respective Subsidiaries. The Administrative Agent shall have no duty to disclose to the Lenders or the LC Issuer information that is not required to be furnished by the Borrower to the Administrative Agent at such time, but is voluntarily furnished by the Borrower to the Administrative Agent (either in its capacity as Administrative Agent or in its individual capacity).

10.5. Action on Instructions of Lenders. The Administrative Agent shall in all cases be fully protected in acting, or in refraining from acting, hereunder and under any other Loan Document in accordance with written instructions signed by the Required Lenders, and such instructions and any action taken or failure to act pursuant thereto shall be binding on all of the Lenders and the LC Issuer. The Lenders and the LC Issuer hereby acknowledge that the Administrative Agent shall be under no duty to take any discretionary action permitted to be taken by it pursuant to the provisions of this Agreement or any other Loan Document unless it shall be requested in writing to do so by the Required Lenders. The Administrative Agent shall be fully justified in failing or refusing to take any action hereunder and under any other Loan Document unless it shall first be indemnified to its satisfaction by the Lenders pro rata against any and all liability, cost and expense that it may incur by reason of taking or continuing to take any such action.

10.6. Employment of Agents and Counsel. The Administrative Agent may execute any of its duties as Administrative Agent hereunder and under any other Loan Document by or through employees, agents, and attorneys-in-fact and shall not be answerable to the Lenders or the LC Issuer, except as to money or securities received by it or its authorized agents, for the default or misconduct of any such agents or attorneys-in-fact selected by it with reasonable care. The Administrative Agent shall be entitled to advice of counsel concerning the contractual arrangement between the Administrative Agent and the Lenders and the LC Issuer and all matters pertaining to the Administrative Agent’s duties hereunder and under any other Loan Document.

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10.7. Reliance on Documents; Counsel. The Administrative Agent shall be entitled to rely upon any Note, notice, consent, certificate, affidavit, letter, telegram, statement, paper or document believed by it to be genuine and correct and to have been signed or sent by the proper person or persons, and, in respect to legal matters, upon the opinion of counsel selected by the Administrative Agent, which counsel may be employees of the Administrative Agent.

10.8. Administrative Agent’s Reimbursement and Indemnification. The Lenders agree to reimburse and indemnify the Administrative Agent and the LC issuer ratably in proportion to their respective Commitments (or, if the Commitments have been terminated, in proportion to their Commitments immediately prior to such termination) (i) for any amounts not reimbursed by the Borrower for which the Administrative Agent or the LC Issuer is entitled to reimbursement by the Borrower under the Loan Documents, (ii) for any other expenses incurred by the Administrative Agent on behalf of the Lenders, in connection with the preparation, execution, delivery, administration and enforcement of the Loan Documents (including, without limitation, for any expenses incurred by the Administrative Agent in connection with any dispute between the Administrative Agent and any Lender or between two or more of the Lenders) and (iii) for any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind and nature whatsoever which may be imposed on, incurred by or asserted against the Administrative Agent or the LC Issuer in any way relating to or arising out of the Loan Documents or any other document delivered in connection therewith or the transactions contemplated thereby (including, without limitation, for any such amounts incurred by or asserted against the Administrative Agent or the LC Issuer in connection with any dispute between the Administrative Agent or the LC Issuer and any Lender or between two or more of the Lenders), or the enforcement of any of the terms of the Loan Documents or of any such other documents, provided that (i) no Lender shall be liable for any of the foregoing to the extent any of the foregoing is found in a final non-appealable judgment by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the Administrative Agent or the LC Issuer, as applicable, and (ii) any indemnification required pursuant to Section 3.5(vii) shall, notwithstanding the provisions of this Section 10.8, be paid by the relevant Lender in accordance with the provisions thereof. The obligations of the Lenders under this Section 10.8 shall survive payment of the Obligations and termination of this Agreement.

10.9. Notice of Default. The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Unmatured Default hereunder unless the Administrative Agent has received written notice from a Lender or the Borrower referring to this Agreement describing such Default or Unmatured Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give prompt notice thereof to the Lenders.

10.10. Rights as a Lender. In the event the Administrative Agent is a Lender, the Administrative Agent shall have the same rights and powers hereunder and under any other Loan Document with respect to its Commitment and its Loans as any Lender and may exercise the same as though it were not the Administrative Agent, and the term “Lender” or “Lenders” shall, at any time when the Administrative Agent is a Lender, unless the context otherwise indicates, include the Administrative Agent in its individual capacity. The Administrative Agent and its Affiliates may accept deposits from, lend money to, and generally engage in any kind of trust, debt, equity or other transaction, in addition to those contemplated by this Agreement or any

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other Loan Document, with the Borrower or any of its Subsidiaries in which the Borrower or such Subsidiary is not restricted hereby from engaging with any other Person. The Administrative Agent, in its individual capacity, is not obligated to remain a Lender.

10.11. Lender Credit Decision. Each Lender acknowledges that it has, independently and without reliance upon any Agent, the Co-Lead Arrangers, the LC Issuer or any other Lender and based on the financial statements prepared by the Borrower and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement and the other Loan Documents. Each Lender also acknowledges that it will, independently and without reliance upon any Agent, the Co-Lead Arrangers, the LC Issuer or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement and the other Loan Documents.

10.12. Successor Administrative Agent. The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, such resignation to be effective upon the appointment of a successor Administrative Agent or, if no successor Administrative Agent has been appointed, forty-five days after the retiring Administrative Agent gives notice of its intention to resign. The Administrative Agent may be removed at any time with or without cause by written notice received by the Administrative Agent from the Required Lenders, such removal to be effective on the date specified by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right to appoint, on behalf of the Borrower and the Lenders, a successor Administrative Agent. If no successor Administrative Agent shall have been so appointed by the Required Lenders within thirty days after the resigning Administrative Agent’s giving notice of its intention to resign, then the resigning Administrative Agent may appoint, on behalf of the Borrower, the LC Issuer and the Lenders, a successor Administrative Agent. Notwithstanding the previous sentence, the Administrative Agent may at any time without the consent of the Borrower, the LC Issuer or any Lender, appoint any of its Affiliates which is a commercial bank as a successor Administrative Agent hereunder. If the Administrative Agent has resigned or been removed and no successor Administrative Agent has been appointed, the Lenders may perform all the duties of the Administrative Agent hereunder and the Borrower shall make all payments in respect of the Obligations to the applicable Lender and for all other purposes shall deal directly with the Lenders. No successor Administrative Agent shall be deemed to be appointed hereunder until such successor Administrative Agent has accepted the appointment. Any such successor Administrative Agent shall be a commercial bank having capital and retained earnings of at least $100,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the resigning or removed Administrative Agent. Upon the effectiveness of the resignation or removal of the Administrative Agent, the resigning or removed Administrative Agent shall be discharged from its duties and obligations hereunder and under the Loan Documents. After the effectiveness of the resignation or removal of an Administrative Agent, the provisions of this Article X shall continue in effect for the benefit of such Administrative Agent in respect of any actions taken or omitted to be taken by it while it was acting as the Administrative Agent hereunder and under the other Loan Documents. In the event that there is a successor to the Administrative Agent by merger, or the Administrative Agent assigns its duties and obligations to an Affiliate pursuant to this Section 10.12, then the term “Prime Rate” as used in this Agreement shall mean the prime rate, base rate or other analogous rate of the new Administrative Agent.

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10.13. Fees. The Borrower agrees to pay to the Administrative Agent, for its own account, the fees agreed to by the Borrower and the Administrative Agent pursuant to the Fee Letter, or as otherwise agreed from time to time.

10.14. Delegation to Affiliates. The Borrower and the Lenders agree that the Administrative Agent may delegate any of its duties under this Agreement to any of its Affiliates. Any such Affiliate (and such Affiliate’s directors, officers, agents and employees) which performs duties in connection with this Agreement shall be entitled to the same benefits of the indemnification, waiver and other protective provisions to which the Administrative Agent is entitled under Articles IX and X.

10.15. Execution of Collateral Documents. The Lenders hereby empower and authorize the Administrative Agent to execute and deliver to the Borrower on their behalf the Collateral Documents and all related financing statements and any financing statements, agreements, documents or instruments as shall be necessary or appropriate to effect the purposes of the Collateral Documents.

10.16. Collateral Releases. The Lenders hereby empower and authorize the Administrative Agent to execute and deliver to the Borrower on their behalf any agreements, documents or instruments as shall be necessary or appropriate to effect any releases of Collateral which shall be permitted by the terms hereof or of any other Loan Document or which shall otherwise have been approved by the Required Lenders (or, if required by the terms of Section 8.2, all of the Lenders) in writing. Notwithstanding anything herein to the contrary, the Lenders hereby authorize the Administrative Agent to release from the Lien of the Mortgage upon with the effectiveness of this Agreement any and all of the Oil and Gas Properties described on Schedule 6.2.11 - West Texas Asset Disposition.

10.17. Co-Agents, Documentation Agent, Syndication Agent, etc. Neither any of the Lenders identified in this Agreement as a “co-agent” nor the Documentation Agent or the Syndication Agent shall have any right, power, obligation, liability, responsibility or duty under this Agreement other than those applicable to all Lenders as such. Without limiting the foregoing, none of such Lenders shall have or be deemed to have a fiduciary relationship with any Lender. Each Lender hereby makes the same acknowledgments with respect to such Lenders as it makes with respect to the Administrative Agent in Section 10.11.

ARTICLE XI

SETOFF; RATABLE PAYMENTS

11.1. Setoff. In addition to, and without limitation of, any rights of the Lenders under applicable law, if the Borrower becomes insolvent, however evidenced, or any Default occurs, any and all deposits (including all account balances, whether provisional or final and whether or not collected or available) and any other Indebtedness at any time held or owing by any Lender or any Affiliate of any Lender to or for the credit or account of the Borrower may be offset and applied toward the payment of the Obligations owing to such Lender, whether or not the Obligations, or any part thereof, shall then be due.

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11.2. Ratable Payments. If any Lender, whether by setoff or otherwise, has payment made to it upon its Outstanding Credit Exposure (other than payments received pursuant to Section 3.1, 3.2, 3.4 or 3.5) in a greater proportion than that received by any other Lender, such Lender agrees, promptly upon demand, to purchase a portion of the Aggregate Outstanding Credit Exposure held by the other Lenders so that after such purchase each Lender will hold its Pro Rata Share of the Aggregate Outstanding Credit Exposure. If any Lender, whether in connection with setoff or amounts which might be subject to setoff or otherwise, receives collateral or other protection for its Obligations or such amounts which may be subject to setoff, such Lender agrees, promptly upon demand, to take such action necessary such that all Lenders share in the benefits of such collateral ratably in proportion to their respective Pro Rata Shares of the Aggregate Outstanding Credit Exposure. In case any such payment is disturbed by legal process, or otherwise, appropriate further adjustments shall be made.

ARTICLE XII

BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS

12.1. Successors and Assigns. The terms and provisions of the Loan Documents shall be binding upon and inure to the benefit of the Borrower and the LC Issuer and the Lenders and their respective successors and assigns permitted hereby, except that (i) the Borrower shall not have the right to assign its rights or obligations under the Loan Documents without the prior written consent of each Lender and the LC Issuer, (ii) any assignment by any Lender must be made in compliance with Section 12.3, and (iii) any transfer by Participation must be made in compliance with Section 12.2. Any attempted assignment or transfer by any party not made in compliance with this Section 12.1 shall be null and void, unless such attempted assignment or transfer is treated as a participation in accordance with Section 12.3.2. The parties to this Agreement acknowledge that clause (ii) of this Section 12.1 relates only to absolute assignments and this Section 12.1 does not prohibit assignments creating security interests, including, without limitation, (x) any pledge or assignment by any Lender of all or any portion of its rights under this Agreement and any Note to a Federal Reserve Bank or (y) in the case of a Lender which is a Fund, any pledge or assignment of all or any portion of its rights under this Agreement and any Note to its trustee in support of its obligations to its trustee; provided, however, that no such pledge or assignment creating a security interest shall release the transferor Lender from its obligations hereunder unless and until the parties thereto have complied with the provisions of Section 12.3. The Administrative Agent may treat the Person which made any Loan or which holds any Note as the owner thereof for all purposes hereof unless and until such Person complies with Section 12.3; provided, however, that the Administrative Agent may in its discretion (but shall not be required to) follow instructions from the Person which made any Loan or which holds any Note to direct payments relating to such Loan or Note to another Person. Any assignee of the rights to any Loan or any Note agrees by acceptance of such assignment to be bound by all the terms and provisions of the Loan Documents. Any request, authority or consent of any Person, who at the time of making such request or giving such authority or consent is the owner of the rights to any Loan (whether or not a Note has been issued in evidence thereof), shall be conclusive and binding on any subsequent holder or assignee of the rights to such Loan.

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12.2. Participations.

12.2.1. Permitted Participants; Effect. Any Lender may at any time sell to one or more banks or other entities (“Participants”) participating interests in any Outstanding Credit Exposure of such Lender, any Note held by such Lender, any Commitment of such Lender or any other interest of such Lender under the Loan Documents. In the event of any such sale by a Lender of participating interests to a Participant, such Lender’s obligations under the Loan Documents shall remain unchanged, such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, such Lender shall remain the owner of its Outstanding Credit Exposure and the holder of any Note issued to it in evidence thereof for all purposes under the Loan Documents, all amounts payable by the Borrower under this Agreement shall be determined as if such Lender had not sold such participating interests, and the Borrower and the Administrative Agent shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under the Loan Documents.

12.2.2. Voting Rights. Each Lender shall retain the sole right to approve, without the consent of any Participant, any amendment, modification or waiver of any provision of the Loan Documents other than any amendment, modification or waiver with respect to any Credit Extension or Commitment in which such Participant has an interest which would require consent of all of the Lenders pursuant to the terms of Section 8.2 or of any other Loan Document. Participates shall have no voting rights except with respect to any amendment, modification or waiver of any provision with respect to any Credit Extension or Commitment in which such Participant has an interest which would require consent of all of the Lenders pursuant to the terms of Section 8.2 or of any other Loan Document.

12.2.3. Benefit of Certain Provisions. The Borrower agrees that each Participant shall be deemed to have the right of setoff provided in Section 11.1 in respect of its participating interest in amounts owing under the Loan Documents to the same extent as if the amount of its participating interest were owing directly to it as a Lender under the Loan Documents, provided that each Lender shall retain the right of setoff provided in Section 11.1 with respect to the amount of participating interests sold to each Participant. The Lenders agree to share with each Participant, and each Participant, by exercising the right of setoff provided in Section 11.1, agrees to share with each Lender, any amount received pursuant to the exercise of its right of setoff, such amounts to be shared in accordance with Section 11.2 as if each Participant were a Lender. The Borrower further agrees that each Participant shall be entitled to the benefits of Sections 3.1, 3.2, 3.4 and 3.5 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to Section 12.3, provided that (i) a Participant shall not be entitled to receive any greater payment under Section 3.1, 3.2 or 3.5 than the Lender who sold the participating interest to such Participant would have received had it retained such interest for its own account, unless the sale of such interest to such Participant is made with the prior written consent of the Borrower, and (ii) any Participant not incorporated under the laws of the United States of America or any State thereof agrees to comply with the provisions of Section 3.5 to the same extent as if it were a Lender.

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12.3. Assignments.

12.3.1. Permitted Assignments. Any Lender may at any time assign to one or more banks or other entities (“Purchasers”) all or any part of its rights and obligations under the Loan Documents. Such assignment shall be substantially in the form of Exhibit B or in such other form as may be agreed to by the parties thereto. Each such assignment with respect to a Purchaser which is not a Lender or an Affiliate of a Lender or an Approved Fund shall either be in an amount equal to the entire applicable Commitment and Loans of the assigning Lender or (unless each of the Borrower, the LC Issuer and the Administrative Agent otherwise consents) be in an aggregate amount not less than $5,000,000. The amount of the assignment shall be based on the Commitment or outstanding Loans (if the Commitment has been terminated) subject to the assignment, determined as of the date of such assignment or as of the “Trade Date,” if the “Trade Date” is specified in the assignment.

12.3.2. Consents. The consent of the Borrower shall be required prior to an assignment becoming effective unless the Purchaser is a Lender, an Affiliate of a Lender or an Approved Fund, provided that the consent of the Borrower shall not be required if a Default has occurred and is continuing. The consent of the Administrative Agent and the LC Issuer shall be required prior to an assignment becoming effective unless the Purchaser is a Lender, an Affiliate of a Lender or an Approved Fund. Any consent required under this Section 12.3.2 shall not be unreasonably withheld or delayed.

12.3.3. Effect; Effective Date. Upon (i) delivery to the Administrative Agent of an assignment, together with any consents required by Sections 12.3.1 and 12.3.2, and (ii) payment of a $3,500 fee to the Administrative Agent for processing such assignment (unless such fee is waived by the Administrative Agent), such assignment shall become effective on the effective date specified in such assignment. The assignment shall contain a representation by the Purchaser to the effect that none of the consideration used to make the purchase of the Commitment and Outstanding Credit Exposure under the applicable assignment agreement constitutes “plan assets” as defined under ERISA and that the rights and interests of the Purchaser in and under the Loan Documents will not be “plan assets” under ERISA. On and after the effective date of such assignment, such Purchaser shall for all purposes be a Lender party to this Agreement and any other Loan Document executed by or on behalf of the Lenders and shall have all the rights and obligations of a Lender under the Loan Documents, to the same extent as if it were an original party thereto, and the transferor Lender shall be released with respect to the Commitment and Outstanding Credit Exposure assigned to such Purchaser without any further consent or action by the Borrower, the Lenders or the Administrative Agent. In the case of an assignment covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a Lender hereunder but shall continue to be entitled to the benefits of, and subject to, those provisions of this Agreement and the other Loan Documents which survive payment of the Obligations and termination of the applicable agreement. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 12.3 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with Section 12.2. Upon the consummation of any assignment to a Purchaser pursuant to this Section 12.3.3, the transferor Lender, the Administrative Agent and the Borrower shall, if the transferor Lender or the Purchaser desires that its Loans be evidenced by Notes, make appropriate arrangements so

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that new Notes or, as appropriate, replacement Notes are issued to such transferor Lender and new Notes or, as appropriate, replacement Notes, are issued to such Purchaser, in each case in principal amounts reflecting their respective Commitments, as adjusted pursuant to such assignment.

12.3.4. Register. The Administrative Agent, acting solely for this purpose as an agent of the Borrower, shall maintain at one of its offices in Chicago, Illinois a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

12.4. Dissemination of Information. The Borrower authorizes each Lender to disclose to any Participant or Purchaser or any other Person acquiring an interest in the Loan Documents by operation of law (each a “Transferee”) and any prospective Transferee any and all information in such Lender’s possession concerning the creditworthiness of the Borrower and its Subsidiaries, including without limitation any information contained in any Reports; provided that each Transferee and prospective Transferee agrees to be bound by Section 9.11 of this Agreement.

12.5. Tax Treatment. If any interest in any Loan Document is transferred to any Transferee that is not incorporated under the laws of the United States or any State thereof, the transferor Lender shall cause such Transferee, concurrently with the effectiveness of such transfer, to comply with the provisions of Section 3.5(iv).

ARTICLE XIII

NOTICES

13.1. Notices. Except as otherwise permitted by Section 2.14 with respect to borrowing notices, all notices, requests and other communications to any party hereunder shall be in writing (including electronic transmission, facsimile transmission or similar writing) and shall be given to such party: (x) in the case of the Borrower or the Administrative Agent, at its address or facsimile number set forth on the signature pages hereof, (y) in the case of any Lender, at its address or facsimile number set forth below its signature hereto or in its administrative questionnaire or (z) in the case of any party, at such other address or facsimile number as such party may hereafter specify for the purpose by notice to the Administrative Agent and the Borrower in accordance with the provisions of this Section 13.1. Each such notice, request or other communication shall be effective (i) if given by facsimile transmission, when transmitted to the facsimile number specified in this Section and confirmation of receipt is received, (ii) if given by mail, 72 hours after such communication is deposited in the mails with first class postage prepaid, addressed as aforesaid, or (iii) if given by any other means, when delivered (or, in the case of electronic transmission, received) at the address specified in this Section; provided that notices to the Administrative Agent under Article II shall not be effective until received.

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13.2. Change of Address. The Borrower, the Administrative Agent and any Lender may each change the address for service of notice upon it by a notice in writing to the other parties hereto.

ARTICLE XIV

COUNTERPARTS

This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Administrative Agent, the LC Issuer and the Lenders and each party has notified the Administrative Agent by facsimile transmission or telephone that it has taken such action.

ARTICLE XV

CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL

15.1. CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS (WITHOUT REGARD TO PRINCIPLES OF THE CONFLICTS OF LAW), BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL BANKS.

15.2. CONSENT TO JURISDICTION. THE BORROWER HEREBY IRREVOCABLY SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR TEXAS STATE COURT SITTING IN HARRIS COUNTY, TEXAS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY SUCH COURT AND IRREVOCABLY WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE AS TO THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A COURT OR THAT SUCH COURT IS AN INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT THE RIGHT OF THE ADMINISTRATIVE AGENT, THE LC ISSUER OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE BORROWER IN THE COURTS OF ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE BORROWER AGAINST THE ADMINISTRATIVE AGENT, THE LC ISSUER OR ANY LENDER OR ANY AFFILIATE OF THE ADMINISTRATIVE AGENT, THE LC ISSUER OR ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN A COURT IN HARRIS COUNTY, TEXAS.

83

15.3. WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT, THE LC ISSUER AND EACH LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR OTHERWISE) IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT OR THE RELATIONSHIP ESTABLISHED THEREUNDER.

15.4. ORAL AGREEMENTS. THE LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

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84

IN WITNESS WHEREOF, the Borrower, the Lenders, the LC Issuer and the Administrative Agent have executed this Agreement as of the date first above written.

BORROWER:
PENN VIRGINIA CORPORATION
By:	/s/ FRANK A. PICI
Name:	Frank A. Pici
Title:	Executive Vice President and Chief Financial Officer
Address:	One Radnor Corporate Center, Suite 200 Radnor, Pennsylvania 19087
Attention:	Frank A. Pici, Executive Vice President & Chief Financial Officer
Telephone:	(610) 687-8900
Telecopier:	(610) 687-3688
E-mail:	fpici@pennvirginia.com

S - 1

	THE AGENTS AND LENDERS:
Commitment
$20,000,000	BANK ONE, NA, as Administrative Agent, the LC Issuer and as a Lender
	By:	/s/ JANE BEK KEIL
	Name:	Jane Bek Keil
	Title:	Director
	Address and Lending Installation:
	Bank One, NA         910 Travis         Houston, Texas 77002
	Attention:	Charles Kingswell-Smith
	Telephone:	(713) 751-7803
	Fax:	(713) 751-3544
	E-mail:	c_kingswell-smith@bankone.com
	with a copy to:
	Bank One, NA, Administrative Agent
	Syndicated Loans Division
	Mail Suite 0429
	Chicago, Illinois 60670-0429
	Attention:	Jessica Lucas
	Telephone:	(312) 732-1013
	Fax:	(312) 732-2117

S - 2

Commitment
$20,000,000	WACHOVIA BANK, NATIONAL ASSOCIATION, as Syndication Agent and as a Lender
	By:	/s/ RUSSELL CLINGMAN
	Name:	Russell Clingman
	Title:	Director
	Address and Lending Installation:
	1001 Fannin Street, Suite 2255                   Houston, Texas 77002
	Attention:	Russell Clingman
	Telephone:	(713) 346-2716
	Telecopier:	(713) 650-6354
	E-mail:	russell.clingman@wachovia.com

S - 3

Commitment
$16,000,000	ROYAL BANK OF CANADA, as a Documentation Agent and as a Lender
	By:	/s/ LORNE GARTNER
	Name:	Lorne Gartner
	Title:	Authorized Signatory
	Address and Lending Installation:
	New York Branch           One Liberty Plaza, 3rd Floor           New York, New York 10006-1404
	Attention:	Compton Singh
	Telephone:	(212) 428-6332
	Telecopier:	(212) 428-2372
	With a copy to:
	Royal Bank of Canada
	Attention: Lorne Gartner
	5700 Williams Tower
	2800 Post Oak Boulevard
	Houston, Texas 77056
	Telephone:	(713) 403-5662
	Telecopier:	(713) 403-5624

S - 4

Commitment
$16,000,000	BNP PARIBAS, as Documentation Agent and as a Lender
	By:	/s/ BETSY JOCHER
	Name:	Betsy Jocher
	Title:	Vice President
	and
	By:	/s/ GABE ELLISOR
	Name:	Gabe Ellisor
	Title:	Vice President
	Address and Lending Installation:
	1200 Smith Street, Suite 3100           Houston, Texas 77002
	Attention:	Doug Liftman
		Managing Director
	Telephone:	(212) 982-1154

S - 5

Commitment
$16,000,000	FLEET NATIONAL BANK, as Documentation Agent and as a Lender
	By:	/s/ CHRISTOPHER C. HOLMGREN
	Name:	Christopher C. Holmgren
	Title:	Managing Director
	Address and Lending Installation:
	100 Federal Street         Boston, Massachusetts 02110
	Attention:	Maria Dechellis
	Telephone:	(617) 434-7198
	Telecopier:	(617) 434-0201
	E-mail:	Maria_Dechellis@Fleet.com
	With a copy to:
	Fleet National Bank
	Attention: Mark Serice
	700 Louisiana Street, Suite 2500
	Houston, Texas 77002
	Telephone:	(713) 315-4217
	Telecopier:	(713) 224-1223
	E-mail:	Mark_Serice@Fleet.com

S - 6

Commitment
$12,400,000	COMERICA BANK, as a Lender
	By:	/s/ HUMA VADGAMA
	Name:	Huma Vadgama
	Title:	Assistant Vice President
	Address and Lending Installation:
	39200 Six Mile Road         Livonia, Michigan 48152
	Attention:	Anna Louisa Cheney
	Telephone:	(734) 632-3052
	Telecopier:	(734) 632-2993
	E-mail:	anna_l_cheney@comerica.com
	With a copy to:
	Comerica Bank
	Attention: Huma Vadgama
	910 Louisiana Street, Suite 410
	Houston, Texas 77002
	Telephone:	(713) 220-5615
	Telecopier:	(713) 220-5650
	E-mail:	hvadgama@comerica.com

S - 7

Commitment
$12,400,000	UFJ BANK LIMITED, as a Lender
	By:	/s/ CLYDE L. REDFORD
	Name:	Clyde L. Redford
	Title:	Senior Vice President
	Address and Lending Installation:
	55 E. 52nd Street, 25th Floor         New York, New York 10055
	Attention:	Seiji Tate
	Telephone:	(212) 339-6235
	Telecopier:	(212) 754-1336
	E-mail:	Seiji_tate@ufjbank.co.jp
	With a copy to:
	UFJ Bank Limited
	Attention: Clyde Redford
	1200 Smith Street, Suite 2265
	Houston, Texas 77002
	Telephone:	(713) 652-3190
	Telecopier:	(713) 654-1462
	E-mail:	clredford@sbcglobal.net

S - 8

Commitment
$12,400,000	FORTIS CAPITAL CORP., as a Lender
	By:	/s/ DAVID MONTGOMERY
	Name:	David Montgomery
	Title:	Senior Vice President
	and
	By:	/s/ DARRELL W. HOLLEY
	Name:	Darrell W. Holley
	Title:	Managing Director
	Address and Lending Installation:
	301 Tresser Boulevard         Stanford, Connecticut 06901
	Attention:	Jaime Silver
	Telephone:	(203) 705-5864
	Telecopier:	(203) 705-5888
	With a copy to:
	Fortis Capital Corp.
	Attention: David Montgomery
	15455 Dallas Parkway
	Addison, Texas 75001
	Telephone:	(214) 953-9311
	Telecopier:	(214) 754-5982
	E-mail:	david.montgomery@fortiscapitalusa

S - 9

Commitment
$12,400,000	MIZUHO CORPORATE BANK, LTD., as a Lender
	By:	/s/ MONSATOSHI ABE
	Name:	Monsatoshi Abe
	Title:	Senior Vice President
	Address and Lending Installation:
	1251 Avenue of the Americas, 32nd Floor                 New York, New York 10020
	Attention:	Yuji Kano
	Telephone:	(212) 282-3555
	Telecopier:	(212) 282-4488
	E-mail:	yuji.kano@mizuhocbus.com
	With a copy to:
	Mizuho Corporate Bank, Ltd.
	Attention: Jackie He
	1251 Avenue of the Americas, 32nd Floor
	New York, New York 10020
	Telephone:	(212) 282-4351
	Telecopier:	(212) 282-3618
	E-mail:	jackie.he@mizuhocbus.com

S - 10

Commitment
$12,400,000	WELLS FARGO BANK, N.A., as a Lender
	By:	/s/ J. ALAN ALEXANDER
	Name:	J. Alan Alexander
	Title:	Vice President
	Address and Lending Installation:
	1445 Ross Avenue                 Suite 2360, Mac# T5303-233                 Dallas, Texas 75202
	Attention:	Dustin S. Hansen
	Telephone:	(214) 661-1233
	Telecopier:	(214) 661-1242
	E-mail:	hanseds@wellsfargo.com

S - 11

EX-12

EXHIBIT 12

Penn Virginia Corporation and Subsidiaries

Statement of Computation of Ratio of Earnings to Fixed Charges Calculation

	Year Ended December 31,
	1998			1999			2000			2001			2002			2003
Earnings
Pre-tax income	$	11,953		$	18,834		$	59,230		$	54,271		$	29,705		$	55,987
Fixed charges		2,435			3,718			8,363			4,058			4,068			8,379
Total Earnings	$	14,388		$	22,552		$	67,593		$	58,329		$	33,773		$	64,366
Fixed Charges.
Interest expense	$	2,017		$	3,298		$	7,926		$	3,596		$	3,125		$	7,352
Rental Interest Factor		418			420			437			462			943			1,027
Total Fixed Charges	$	2,435		$	3,718		$	8,363		$	4,058		$	4,068		$	8,379
Ratio of Earnings to Fixed Charges		5.9	x		6.1	x		8.1	x		14.4	x		8.3	x		7.7	x

EX-14

Exhibit 14

PENN VIRGINIA CORPORATION

EXECUTIVE AND FINANCIAL OFFICER CODE OF ETHICS

In my role as Chief Executive Officer (“CEO”), Chief Financial Officer (“CFO”) or Controller of Penn Virginia Corporation (the “Company”), I will, to the best of my knowledge and ability, adhere to and advocate the following principles and responsibilities governing professional conduct and ethics influencing financial management and performance:

1. Act with honesty and integrity, avoiding actual or apparent conflicts of interest in personal and professional relationships. A “conflict of interest” exists when an individual’s private interests interfere or conflict in any way (or even appear to interfere or conflict) with the interests of the Company.

2. Provide constituents with information that is accurate, complete, objective, relevant, timely and understandable. If I am the CEO or CFO, I shall review the annual and quarterly reports before certifying and filing them with the SEC.

3. Comply with all applicable laws, rules and regulations of federal, state and local governments, and other appropriate private and public regulatory agencies.

4. Act in good faith, responsibly, with due care, competence and diligence, without misrepresenting material facts or allowing my independent judgment to be subordinated.

5. Respect the confidentiality of information acquired in the course of business except when authorized or otherwise legally obligated to disclose the information. I acknowledge that confidential information acquired in the course of business is not to be used for personal advantage.

6. Proactively promote ethical behavior among employees at the Company and as a responsible partner with industry peers and associates.

7. Responsibly manage all assets and resources employed or entrusted to me by the Company.

8. Share knowledge and maintain the skills important and relevant to my constituents’ needs.

9. Report illegal or unethical conduct by any director, officer or employee in accordance with procedures described in the Company’s Code of Business Conduct and Ethics.

10. Be accountable for adhering to this Code as well as the Company’s Code of Conduct. I understand that if I violate any part of either Code, I will be subject to disciplinary action.

I understand that this Code is subject to all applicable laws, rules and regulations.

I understand that if there is a conflict between this Code and a Company policy or procedure, the Company Code of Conduct, or any applicable law, rule or regulation, then I must consult with the Legal Department for guidance.

I understand that there shall be no waiver of, modification of, or change to any part of this Code except by a vote of the Board of Directors. In the event that a waiver of, modification of, or a change to this Code is granted, then the notice of the waiver, modification and/or change shall be disclosed and retained in the Company’s files as required by applicable laws and regulations.

	/s/ A. James Dearlove
[Date signed]    March 9, 2004	A. James Dearlove
	Chief Executive Officer
	/s/ Frank A. Pici
[Date signed]    March 9, 2004	Frank A. Pici
	Executive Vice President and Chief Financial Officer
	/s/ Dana G. Wright
[Date signed]    March 9, 2004	Dana G. Wright
	Vice President and Controller Principal Accounting Officer

2

EX-21

Exhibit 21

List of Subsidiaries

Name	Jurisdiction of Organization
Penn Virginia Holding Corp.	Delaware
Penn Virginia Oil & Gas Corporation	Virginia
Penn Virginia Oil & Gas Corporation	Texas
Penn Virginia Resource GP, LLC	Delaware
Penn Virginia Resource LP Corp.	Delaware
Kanawha Rail Corp.	Virginia

EX-23.1

Exhibit 23.1

Independent Auditors’ Consent

The Board of Directors

Penn Virginia Corporation

We consent to the incorporation by reference in the registration statements on Form S-8 (File Nos. 33-59647, 33-96463, 333-82274, 33-96465 and 333-103455) and Form S-3 (File No. 333-110193) of Penn Virginia Corporation of our report dated February 16, 2004, with respect to the consolidated balance sheet of Penn Virginia Corporation as of December 31, 2003 and the related consolidated statements of income, shareholders’ equity and comprehensive income, and cash flows for the year ended December 31, 2003, which report appears in the December 31, 2003, annual report on Form 10-K of Penn Virginia Corporation.

Our report dated February 16, 2004, contains an explanatory paragraph that states that the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.

KPMG LLP

Houston, Texas

March 11, 2004

EX-23.2

Exhibit 23.2

CONSENT OF WRIGHT & COMPANY, INC.

As independent oil and gas consultants, Wright & Company, Inc. hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 33-59647, 33-96463, 333-82274, 33-96465, 33-82304 and 333-103455) and Form S-3 (File No. 333-110193) of Penn Virginia Corporation of information from our reserve report dated March 4, 2004, entitled “Evaluation of Proved Reserves to the Interests of Penn Virginia Oil & Gas Corporation eastern and Gulf Coast Divisions Pursuant to the Requirements of the Securities and Exchange Commission Effective January 1, 2004” and all references to our firm included in or made a part of the Penn Virginia Corporation Annual Report on Form 10-K to be filed with the Securities and Exchange Commission on or about March 11, 2004.

WRIGHT AND COMPANY, INC.

Houston, Texas

March 10, 2004`

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

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

1. I have reviewed this annual report on Form 10-K of the Registrant;

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

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

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of Registrant’s board of directors:

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date:	March 9, 2004
		/s/    A. James Dearlove
		A. James Dearlove President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Frank A. Pici, Executive Vice President and Chief Financial Officer of Penn Virginia Corporation (the “Registrant”), certify that:

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

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

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

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

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

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of Registrant’s board of directors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date:	March 9, 2004
		/s/    Frank A. Pici
		Frank A. Pici
		Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Penn Virginia Corporation (the “Company”) on Form 10-K for the year ended December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, A. James Dearlove, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

March 9, 2004

/s/    A. James Dearlove        

A. James Dearlove

President and Chief Executive Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to Penn Virginia Corporation and will be retained by Penn Virginia Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Penn Virginia Corporation (the “Company”) on Form 10-K for the year ended December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Frank A. Pici, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

March 9, 2004

/s/    Frank A. Pici        

Frank A. Pici

Executive Vice President and Chief Financial Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to Penn Virginia Corporation and will be retained by Penn Virginia Corporation and furnished to the Securities and Exchange Commission or its staff upon request.