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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Commission file number: 001-14256

Westport Resources Corporation

1670 Broadway, Suite 2800

(Registrant’s telephone number including area code):

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

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

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

      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.     o

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

      The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2003 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $779,556,005. The number of shares of the Registrant’s common stock outstanding as of March 3, 2004, was 67,716,290.

DOCUMENTS INCORPORATED BY REFERENCE

      Parts of the definitive proxy statement for the Registrant’s 2003 annual meeting of stockholders are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

      Our disclosure and analysis in this report, including information incorporated by reference, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to our December 18, 2003 acquisition of South Texas properties and the financial condition, results of operations, plans, objectives, future performance and business of Westport Resources Corporation and its subsidiaries. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe” and other words and expressions of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events. All statements other than statements of historical facts included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements including, among other things, statements relating to:

	•	amount, nature and timing of capital expenditures;
	•	projected drilling of wells;
	•	timing and amount of future production of oil and natural gas;
	•	operating costs and other expenses;
	•	cash flow, anticipated liquidity and prospects for growth;
	•	estimates of proved reserves and exploitation and exploration opportunities; and
	•	marketing of oil and natural gas.

      These forward-looking statements are based on our expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. Although we believe that the expectations reflected in our forward-looking statements are reasonable, we do not know whether our expectations will prove correct. Any or all of our forward-looking statements in this report may turn out to be wrong. They can be affected by inaccurate assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report, including the risks outlined under “Risk Factors,” will be important in determining future results. Actual future results may vary materially. Because of these factors, we caution that investors should not place undue reliance on any of our forward-looking statements. Further, any forward-looking statement speaks only as of the date on which it is made, and except as required by law we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

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PART I

About Westport

      Unless otherwise indicated or the context otherwise requires, all references in this report to “Westport,” the “Company,” “us,” “our,” or “we” are to Westport Resources Corporation, a Nevada corporation, and its consolidated subsidiaries. We have provided definitions for some of the oil and natural gas industry terms used in this report in the “Glossary of Oil and Natural Gas Terms” beginning on page 23.

      We are an independent energy company engaged in oil and natural gas production, exploitation, acquisition and exploration activities primarily in the United States. Based upon publicly reported production levels during the fourth quarter of 2003, we are among the 20 largest domestic independent exploration and production companies. Our reserves and operations are concentrated in the following divisions: Northern, comprised primarily of properties in North Dakota and Wyoming; Western, comprised of properties in Utah; Southern, comprised primarily of properties in Oklahoma, Texas and Louisiana; and Gulf of Mexico, which includes our offshore properties. We focus on maintaining a balanced portfolio of lower-risk, long-lived primarily onshore reserves and higher-margin shorter lived Gulf Coast and Gulf of Mexico reserves to provide a diversified cash flow foundation for our exploitation, acquisition and exploration activities.

      On December 18, 2003, we closed, effective as of December 1, 2003, an acquisition of producing properties, undeveloped leasehold, seismic data, exploration projects and other assets in South Texas, also referred to as the South Texas Acquisition, for approximately $341.7 million. The acquired assets complement a growing core area for us in South Texas. The South Texas Acquisition increased our reserves by approximately 13%, raised our production by approximately 15% and replaced approximately 125% of our 2003 production. Approximately 97% of the acquired proved reserves are natural gas and 61% are proved developed. We have identified additional exploitation and exploration potential on the 90,358 net acres of acquired leasehold. The South Texas Acquisition was funded from existing cash and borrowings under our revolving credit facility.

      Over the last several years acquisitions, subsequent exploitation and exploration activity have fueled the growth of our reserves, production and cash flow. From December 31, 1997 to December 31, 2003, primarily as a result of these investments, we increased our estimated proved reserves from 197 Bcfe to 1,781 Bcfe, and our average daily production increased from 66 Mmcfe/d to 455 Mmcfed/d, yielding compound annual growth rates of approximately 44% and 38% respectively. Our reserve to production ratio increased to approximately 10 years at year-end 2003.

      Notwithstanding our rapid growth, we have maintained a disciplined approach to the control of costs. Over the six-year period ending December 31, 2003, we have reduced our per unit cost structure from $1.32 per Mcfe to $1.14 per Mcfe for the aggregate of lease operating expenses, transportation costs, production taxes and general and administrative costs. We have accomplished this while maintaining a strong balance sheet and significant financial flexibility.

      We believe that our exploitation and exploration inventory and our acquisition expertise, together with our operating experience and cost structure, provide us with the ability to generate substantial cash flow and position us for future growth. We operate approximately 77% of the net present value of our reserves, allowing us to better manage expenses, capital allocation and the decision-making processes related to all aspects of exploitation and exploration activities. For the year ended December 31, 2003, we generated oil and natural gas sales of $814 million. Our capital expenditures for 2003 were approximately $298 million (including $17.0 million of expensed geological and geophysical costs), which does not include acquisitions. We expect that our total 2004 capital budget, excluding acquisitions, will be approximately $370 million, 73% of which has been allocated to exploitation. We anticipate drilling between 400 and 450 wells during 2004.

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      As of December 31, 2003, our estimated proved reserves of 1,781 Bcfe had a pre-tax net present value, discounted at 10%, of approximately $3.5 billion based on year end New York Mercantile Exchange, or NYMEX, prices of $32.55 per barrel of oil and $5.83 per Mmbtu of natural gas. Approximately 65% of our reserves were classified as proved developed as of December 31, 2003. The following table sets forth the volume and net present value of our estimated proved reserves as of December 31, 2003 and a summary of our fourth quarter 2003 production by division:

Our Strategy

      Our strategy is to grow our reserve base and production, maintain our diversified risk profile and expand our investment opportunities primarily by executing on lower-risk exploitation projects and acquisitions. Although our emphasis is on exploitation and acquisition activities, we will continue drilling potentially higher-impact exploration prospects, thereby balancing risks while maintaining significant potential for growth. To accomplish this strategy, we will:

	•	enhance our exploitation activity by allocating approximately 75% of our capital budget to exploitation to increase production and enhance our reserve base;
	•	continue our acquisition activity to achieve greater immediate cash flow and expand our exploitation inventory;
	•	continue to generate and drill an extensive prospect inventory by applying current technology and leveraging our significant operational capabilities and acreage inventory; and
	•	maintain financial flexibility and a conservative capital structure through prudent financial and hedging activities.

Company History

      Westport was formed by the April 7, 2000 merger of Westport Oil and Gas Company, Inc., which we refer to as Westport Oil and Gas, and Equitable Production (Gulf) Company, which we refer to as EPGC, an indirect, wholly owned subsidiary of Equitable Resources, Inc. As a result of the merger, Westport Oil and Gas became a wholly owned subsidiary of EPGC, which subsequently changed its name to Westport Resources Corporation, and the stockholders of Westport Oil and Gas became the majority stockholders of EPGC. The senior management team of Westport Oil and Gas became the management team for the combined company, complemented by certain key managers from EPGC. The April 2000 merger was accounted for using purchase accounting with Westport Oil and Gas as the surviving

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      On August 21, 2001, the stockholders of Belco Oil and Gas Corp., or Belco, approved an agreement and plan of merger, dated as of June 8, 2001, between Belco and Westport. Pursuant to this agreement, Westport was merged with and into Belco, with Belco surviving and changing its name to Westport Resources Corporation. The 2001 merger was accounted for as a purchase transaction for financial accounting purposes with Westport as the surviving accounting entity. Westport began consolidating the results of Belco with its results as of the August 21, 2001 closing date.

      We are incorporated under the laws of the State of Nevada. Our principal offices are located at 1670 Broadway Street, Suite 2800, Denver, Colorado 80202. Our telephone number is (303) 573-5404, and our web site can be found at www.westportresourcescorp.com.

Purchasers and Marketing

      Our oil and natural gas production is principally sold to marketers and other purchasers having access to nearby pipeline facilities or is transported under our transportation agreements to expand our marketing opportunities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For 2003, our largest purchaser was Duke Energy, which accounted for 14% of our oil and natural gas sales. No other purchasers accounted for more than 10% of our oil and natural gas sales. We do not believe that the loss of any of our purchasers, including Duke Energy, would have a material adverse effect on our business or operations.

      We periodically enter into commodity derivative contracts (future contracts, swaps or options) in order to (i) reduce the effect of the volatility of price changes on the commodities we produce and sell, (ii) support our annual capital budgeting and expenditure plans and (iii) lock in prices to protect the economics related to certain capital projects. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation” for a description of our hedging activities, “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and Note 3 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for information concerning the impact to revenues during 2003, 2002 and 2001 from our commodity derivative activities, our open derivative positions and related prices.

Seasonality

      Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.

Competition

      We compete with major and independent oil and natural gas companies. Because oil and natural gas are commodities that are sold by hundreds of competitors, we cannot identify with certainty which of our competitors are material competitors. Some of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in Federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our competitors may be able to pay more for exploratory prospects and producing oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, these companies may enjoy technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for oil and natural gas prospects and to acquire additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties, implement advanced technologies and to consummate transactions in this highly competitive environment.

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Regulation

      Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission, or the FERC. In the past, the Federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining NGA and Natural Gas Policy Act price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future.

      Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive Federal regulation. Commencing in April 1992, the FERC issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open-access transportation on a basis that is equal for all natural gas suppliers. The FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. Although Order No. 636 does not directly regulate our production and marketing activities, it does affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines.

      In subsequent action, the FERC issued Order No. 637 and a series of related orders, which are intended to institute incremental reforms to the Order No. 636 regulatory model. The FERC’s stated purpose in Order No. 637 is to “improve the efficiency of the market and to provide captive customers with the opportunity to reduce their cost of holding long-term pipeline capacity while continuing to protect against the exercise of market power.” Order No. 637, among other things, (i) authorizes pipelines to implement peak and off-peak rates for short-term services and term-differentiated rates, (ii) requires pipelines to offer enhanced imbalance management services and to implement netting and trading of transportation imbalances, (iii) limits the use of pipeline penalties, and (iv) provides increased transparency through enhanced posting of transactional information on pipelines’ websites. Order No. 637 was implemented through compliance filings by pipelines, on which shippers were afforded the opportunity to comment. The FERC has now issued a number of orders in pipeline compliance proceedings, resolving most of the issues raised by the compliance filings. Pipeline interests and other parties challenged certain aspects of Order No. 637 on judicial review. In a decision issued in 2002, the U.S. Court of Appeals for the District of Columbia Circuit upheld almost all material aspects of Order No. 637.

      The Outer Continental Shelf Lands Act, or OCSLA, requires that all pipelines operating on or across the Outer Continental Shelf, or OCS, provide open-access, nondiscriminatory service. In mid-2000, the FERC issued Order Nos. 639 and 639-A, imposing reporting requirements on natural gas pipelines operating on the OCS that are not subject to regulation under the NGA. The stated purpose of these reporting requirements was to provide transparency for shippers on OCS natural gas pipelines in order to aid in detecting discriminatory conduct. Pipeline interests challenged the reporting requirements before the U.S. District Court for the District of Columbia on the ground that Congress did not delegate rulemaking authority to the FERC to implement the nondiscrimination requirement in Section 5(f) of the OCSLA. In January 2002, the District Court ruled in the pipelines’ favor, entering a permanent injunction against the OCS pipeline reporting requirements. The D.C. Circuit affirmed the District Court’s order in October 2003. As a result, further implementation and enforcement of the nondiscrimination requirement in Section 5(f) of the OCSLA will fall on the Minerals Management Service of the U.S. Department of Interior. At this juncture, the Minerals Management Service has taken no action to indicate how it will implement and enforce Section 5(f) of OCSLA.

      Commencing in May 1994, the FERC issued a series of orders that, among other matters, slightly broadened the types of facilities that would be found to be non-jurisdictional gathering facilities and

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      Concurrently with the transfer of gathering facilities onshore, a number of interstate pipelines requested authority to have their facilities on the OCS declared a non-jurisdictional gathering. Many of the pipelines on the OCS are large-capacity lines that move up to one Bcf of natural gas per day. Although the jurisdictional test for OCS facilities is somewhat different from the test used onshore, the general trend since 1994 has been toward an increasing number of facilities being viewed as non-jurisdictional gathering by the FERC. A major test case involving the Sea Robin Pipeline system was decided by a panel of the U.S. Court of Appeals for the D.C. Circuit in August 2002. A two-judge majority upheld the FERC’s “central point of aggregation” test for determining jurisdictional status of OCS pipelines. Under that test, the dividing line between non-jurisdictional gathering and jurisdictional transportation is generally identified as being located at the last major fork on the pipeline before it goes onshore. Although producer interests have now sought review of the D.C. Circuit’s decision before the United States Supreme Court, certiorari was denied in October 2003. As a result of the D.C. Circuit’s decision, producers on the OCS could be exposed to higher rates for gathering services over formerly jurisdictional facilities downstream of production platforms.

      In a related development, the FERC addressed a complaint by an OCS natural gas producer in 2002 stemming from the transfer by an interstate pipeline of formerly jurisdictional facilities on the OCS to a non-regulated gathering affiliate. Soon after receiving the facilities, the non-regulated affiliate instituted a three-fold rate increase to certain shippers. In an order issued in September 2002, the FERC determined that the gathering affiliate and the interstate pipeline had acted in concert to frustrate the effective regulation of transportation of natural gas interstate commerce on the pipeline. The FERC reasserted jurisdiction over the gathering affiliate and directed it to institute a prospective reduction in rates to a cost-of-service rate. The FERC’s order is now being challenged on rehearing in the U.S. Court of Appeals for the D.C. Circuit. Because the FERC’s order involves an untested legal theory, it is not possible to predict the extent to which the FERC will be permitted, if at all, to reassert jurisdiction over former jurisdictional facilities that have been found to be used for non-jurisdictional gathering.

      If the FERC ultimately decides that it should regulate fewer OCS facilities under the NGA and such determination is upheld on judicial review, or if it is determined that the FERC’s jurisdiction over crude oil and natural gas transportation on the OCS is more limited than previously asserted, we could face higher transmission costs for our OCS natural gas production and, possibly, reduced access to OCS transmission capacity. If we successfully develop our offshore exploration projects, we expect to own and operate facilities that we believe will be gathering lines. If the FERC should decide to classify lines on the OCS that traditionally have been viewed as gathering lines as jurisdictional transmission lines, our OCS facilities could be subject to regulation as interstate pipelines. However, given the limited scope of such facilities, it is not expected that such regulation would have a material impact on our business or operations.

      Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated; therefore, we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

      Federal and Tribal Leases. A substantial portion of our operations are located on Federal oil and natural gas leases, which are administered by the Bureau of Land Management (onshore) and Minerals Management Service (offshore) of the U.S. Department of the Interior and other agencies. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed Bureau of Land Management and Minerals Management Service regulations and orders pursuant

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      For offshore operations, lessees must obtain Minerals Management Service, or MMS, approval for exploration plans and exploitation and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations, and a recently issued policy statement, restricting the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil without prior authorization. MMS, working together with the Department of Justice, has recently taken aggressive action against another offshore lessee based on allegations that the lessee had conducted unauthorized flaring and venting of natural gas; MMS issued a news release on August 5, 2003, stating that its investigation into this matter resulted in the lessee making a $49 million settlement payment. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the MMS may require any of our operations on Federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

      In 2003, MMS issued a Notice which articulated the agency’s policy concerning the volume of production that a lessee must have to maintain an offshore lease beyond its primary term. Although the standard that the MMS announced is generally consistent with standards applicable under state law, it is not yet clear how the agency will apply this standard. It is possible that MMS may impose requirements for lease maintenance activities that could have a material adverse effect on our operations and financial condition.

      The United States Department of Transportation, or DOT, through its Office of Pipeline Safety, also imposes certain requirements on parties responsible for transportation pipelines associated with platforms located on the OCS. The MMS and DOT have entered into a Memorandum of Understanding regarding the agencies’ respective authority over offshore operations, and the MMS has adopted regulations implementing the Memorandum of Understanding by specifying the dividing point for any given pipeline at which MMS regulatory authority ends and DOT authority begins.

      The MMS has entered into a series of Memoranda of Understanding with other Federal agencies, such as the Environmental Protection Agency, the Coast Guard and the Occupational Safety and Health Administration, providing for the MMS to undertake certain inspection and, in some cases, enforcement responsibility for the respective regulatory mandates of these agencies. Those agencies do, however, retain varying degrees of jurisdiction over OCS operations to establish and enforce regulatory requirements.

      In recent years, the MMS has modified its regulations to, among other things, (i) impose the duty on any lessee of an offshore lease to meet end-of-lease obligations if the designated operator is unable to do so, (ii) establish joint and several liability for plugging and abandonment of wells, removal of platforms and other facilities, and clearance of well and platform locations, among OCS lessees, assignees and assignors, thus creating residual liability in certain parties for these decommissioning obligations, (iii) increase the level of bond coverage for drilling deep stratigraphic test wells and (iv) allow the MMS Regional Director to require, on a case-by-case basis, posting of additional bonds or other security in order to increase the amount of coverage for end-of-lease obligations or certain other operations. MMS carefully monitors lease abandonment liabilities and routinely requires lessees to furnish supplemental bonds to secure such liabilities. These requirements may operate to substantially increase our current bonding liabilities, and may also impact our residual liabilities, both with respect to existing leases acquired from third parties and with respect to leases that we may acquire or dispose of in the future.

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      Effective June 1, 2000, the MMS adopted regulations that changed significantly the valuation of crude oil for royalty payments on onshore and offshore Federal leases. These rules retained the concept of gross proceeds for calculating royalties on production sold to third parties in arm’s-length transactions, but added a new provision expressly requiring lessees to market oil at no cost to the Federal Government. Moreover, oil sold in non-arm’s-length contracts is to be valued using index pricing methods or other benchmarking procedures to determine a deemed arm’s-length price. The rules define non-arm’s-length sales to include sales to affiliates, certain exchange transactions, sales pursuant to certain call provisions, and other transactions. The breadth of these definitions and the new duty to market provision could cause certain sales by us to be impacted and might in some cases lead the MMS to claim royalty on a deemed value higher than that which we actually receive for our oil. The new regulations, were challenged judicially, and in August 2003 the MMS proposed a series of amendments to these rules (concerning, among other things, the indices used and the calculation of location adjustments to index values), but MMS has not finalized the amendments to the rules. MMS is expected to finalize the amendments in early 2004. The judicial challenge is still pending, but is currently inactive, and the outcome of this challenge is not known.

      In a series of regulations and rulings over the past several years, the MMS has also taken an expansive view of the lessee’s duty to market natural gas on behalf of the Federal government as lessor. For example, a rule promulgated in 1997 disallowed the deductibility of certain transportation costs from the calculation of royalty on natural gas sold off Federal leases, including marketer fees, cash out and other pipeline imbalance penalties and long-term storage fees. Although these regulations and rulings were challenged judicially, in 2002 that challenge was in large part rejected. Based on the new gas regulations, MMS may disallow deductions from royalty value of certain costs alleged to be marketing costs, or require certain costs to be added back to the royalty base, in effect imposing royalty obligations based on values established in sales occurring downstream of our leases.

      The MMS has also previously proposed natural gas valuation rules similar to those described above for oil royalty valuation that would value gas sold in certain non-arm’s length transactions in accordance with defined indices or other benchmarks. Those proposed rules were withdrawn in 1997, but in 2003 the MMS held a series of public workshops to discuss changes to its gas valuation rules, including changes to index based valuation methodologies. MMS is expected to publish proposed rules in early 2004. The potential effect of such rules, as with the revised oil royalty valuation rules, may be to move the valuation point downstream for purposes of royalty calculation and thereby to impose a royalty obligation on a deemed value higher than proceeds realized by the lessee from sales netted back to the wellhead. We cannot currently predict how the final form of any of these rules could impact our royalty obligations.

      Our leases in the Ouray field in our Western division are issued by the Ute Indian tribe and are subject to a variety of regulations and orders by the Tribe, the Bureau of Indian Affairs of the U.S. Department of the Interior, and the State of Utah, some of which are duplicative, relating to operational matters.

      State, Tribal and Local Regulation of Drilling and Production. We own interests in properties located in the Louisiana state waters off the Gulf of Mexico and on state lands in the states in which we operate. We also own interests on private lands that are subject to regulation by state and local governments.

      State regulations govern operational matters such as permits and bonds for drilling, reclamation and plugging, spacing and pooling of wells, and reporting requirements. The states in which we operate or plan to operate also have a variety of statutes and regulations governing conservation matters, ranging from establishment of maximum rates of production from oil and gas wells to the proration of production to the market demand for oil and natural gas to the limitation on ceiling prices for gas sold within the state. Such regulation could be applied to restrict the rate at which our wells produce oil or gas below the rate at which such wells would otherwise be produced, and the amount or timing of our revenues could thereby be adversely affected.

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      In recent years, pressure has increased in states in which we have been active to increase regulation of the oil and natural gas industry at the local government level. Such local regulation in general is aimed at increasing the involvement of local governments in the permitting of oil and natural gas operations, requiring additional restrictions or conditions on the conduct of operations to reduce the impact on the surrounding community and increasing financial assurance requirements. Accordingly, such regulation has the potential to delay and increase the cost, or even in some cases to prohibit entirely, our drilling activities.

      A significant amount of our Uinta Basin properties in our Western Division are located within the Uintah and Ouray Indian Reservations. As a result, our interests and operations therein are subject to the jurisdiction of various Tribal authorities.

      Oil Price Controls and Transportation Rates. Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. Effective as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that could increase the cost of transporting oil to the purchaser. We do not believe that these regulations affect us any differently than other oil producers, gatherers and marketers.

      Environmental Regulations. Our operations, which include the storage of oil and other hazardous materials, are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, including those listed below. We could incur substantial costs, including cleanup costs, fines and civil or criminal sanctions, as a result of violations of or liabilities under environmental laws or non-compliance with environmental permits required at our facilities. Public interest in the protection of the environment has increased dramatically in recent years. Drilling in some areas both offshore and onshore has been opposed by environmental groups and, in some areas, has been restricted. Westport’s Northern and Western Divisions include substantial amounts of Federal and Indian acreage. In recent years, environmental groups have brought lawsuits against federal agencies challenging various aspects of the leasing, development and production of oil and gas. These lawsuits have caused disruptions in the approval process for new wells and may continue to affect our pace of development. To the extent laws are enacted or other governmental action is taken that prohibits or restricts drilling or otherwise imposes environmental protection requirements that result in increased costs to the oil and natural gas industry, our business and prospects could be adversely affected.

      The drilling for and production, handling, transportation and disposal of oil, natural gas and by-products are subject to extensive regulation under Federal, state and local environmental laws. In most instances, the applicable regulatory requirements relate to water and air pollution control and oilfield management measures, permitting requirements, or restrictions on operations in environmentally sensitive areas such as coastal zones, wetlands and wildlife habitat. These requirements increase our cost of doing business, delay or preclude operations, and create potential liability to governmental agencies or third parties for environmental damage. For example, environmental regulation may in some circumstances impose “strict liability” for environmental contamination, rendering an owner or operator or other person with a connection to a property liable for environmental and natural resource damages and cleanup cost without regard to negligence or fault on the part of such person. 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, and such liability can be imposed on successor owners. In connection with our acquisitions, we generally perform environmental assessments. To the extent we have identified environmental liabilities in that process, such liabilities are not material or we have negotiated agreements requiring the sellers of the properties to undertake the required clean-up. However, generally we are required by the sellers to assume environmental responsibility for acquired properties except for material liabilities identified within the specified period following closing. We have not performed environmental assessments on all of our properties.

      Under the Comprehensive Environmental Response, Compensation, and Liability Act, also known as the “Superfund” law, as well as similar state statutes, an owner or operator of real property or a person who arranges for disposal of hazardous substances may be liable for the costs of removing or remediating

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      The Oil Pollution Act of 1990, or OPA, and regulations thereunder impose liability on “responsible parties,” including the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located, for oil removal costs and resulting public and private damages relating to oil spills in United States waters. The OPA assigns liability to “responsible parties” for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a Federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill and to prepare oil spill contingency plans. We believe we are in compliance in all material respects with these requirements.

      The Federal Water Pollution Control Act, or FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into regulated water of the U.S., which include nearly all streams, tributaries and adjacent wetlands. Permits must be obtained to discharge fill material or other pollutants and to conduct construction activities in regulated waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System generally limit and may otherwise prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into coastal or offshore waters. Although the costs to comply with zero discharge mandates under Federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. In 1992, the Environmental Protection Agency adopted regulations requiring certain oil and gas exploration and production facilities to obtain permits for storm water discharges, which requirement will cause the entire industry to incur additional costs associated with the treatment of storm water run-off and developing and implementing related storm water pollution prevention plans.

      The Endangered Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, seismic, exploration and production operations, as well as actions by Federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA provides for criminal penalties for willful violations of the Act. Other statutes provide protection to animal and plant species and may apply to our operations, such as the Marine Mammal Protection Act, or MMPA, the Migratory Bird Treaty Act, and the National Historic Preservation Act. The ESA and the MMPA prohibit taking of endangered species, including all sea turtle species found in the Gulf of Mexico, and all marine mammal species, except in accordance with specific incidental take statements or permits issued pursuant to each statute. Following formal ESA consultation between the MMS and NOAA Fisheries in 2002 regarding marine mammal and endangered species implications of exploration and production activities attendant to Gulf of Mexico OCS lease sales, the MMS has issued a series of Notices to Lessees, or NTLs, regarding the conduct of seismic operations, culminating with NTL 2004-G01, pertaining to incidental takes of sea turtles and whale species. NTL 2004-G01 applies to any seismic operations conducted in water depths of 200 meters or greater in Central and Western Gulf of Mexico, and to all water depths in the Eastern Gulf of Mexico. NTL 2004-G01 requires the employment of two trained visual observers during seismic operations to watch for sea turtles or whales within an “exclusion zone” of 500 meters around the center

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      The National Historic Preservation Act and related laws and regulations contain certain requirements and restrictions to protect and preserve various historic, archaeological and cultural resources. These laws can delay, prevent or alter our operations in areas, such as Utah, where such resources may exist.

      We conduct remedial activities at some of our onshore facilities as a result of spills of oil or produced saltwater from current or historical activities. To date, the costs of such activities have not been material. However, we could incur significant costs at these or other sites if additional contaminants are detected or clean-up obligations imposed.

      Our operations are also subject to the regulation of air emissions under the Clean Air Act, comparable state and local requirements and the OCSLA. We may be required to incur capital expenditures to upgrade pollution control equipment or become liable for non-compliance with applicable permits.

      A large portion of our operations in the Rocky Mountain Region is on federal public lands or involve federally or tribally owned minerals. Those areas are subject to land management plans and mineral development approvals by federal and tribal land management agencies, which often contain strict limits and requirements on oil and gas exploration and production operations, to protect wildlife, archaeological and cultural sites and other resources.

      New initiatives regulating the disposal of oil and gas waste are also pending or have been enacted in certain states, including states in which we conduct operations, and these various initiatives could have a similar impact on us. These rules establish significant permitting, record-keeping and compliance procedures that may require the termination of production from marginal wells for which the cost of compliance would exceed the value of remaining production and could lead to the incurring of significant remediation costs for properties found to have caused groundwater contamination or other environmental problems.

      In addition, legislation has been proposed in Congress from time to time that would reclassify some oil and natural gas exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. This, or the imposition of other environmental legislation, could increase our operating or compliance costs.

      We believe that we are in compliance in all material respects with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us.

      Environmental Cleanup Claims by Private Landowner/ Lessors. In addition to obligations owed under federal, state, and local environmental statutes and regulations, onshore operations on private state lands can also lead to litigation with landowner/lessors seeking restoration of their leased premises. A 2003 decision by the Louisiana Supreme Court in Corbello v. Iowa Production upheld a jury award of over $50 million against a mineral lessee for alleged surface damages and improper disposal of produced saltwater. The court expressly upheld the jury award even though damages greatly exceeded the property’s value, based on the lessee’s earlier contractual commitment to reasonably restore the premises as nearly as possible to their pre-lease condition. This decision can be expected to contribute to an already increasing number of lawsuits filed by landowners against their lessees seeking site restoration, especially as older oilfields near the end of their productive life. It is possible that lawsuits brought against us seeking such damages could have a material adverse effect on our operations and financial condition, although no such claims have been brought to date.

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Operating Hazards and Insurance

      The oil and natural gas business involves a variety of operating risks, including fires, explosions, blowouts, environmental hazards and other potential events, which can adversely affect our operations. In addition, our offshore operations also are subject to a variety of operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions, any of which can cause substantial damage to facilities. Any of these problems could adversely affect our ability to conduct operations and cause us to incur substantial losses. Such losses could reduce or eliminate the funds available for exploration, exploitation or leasehold acquisitions, or result in loss of properties.

      In accordance with industry practice, we maintain insurance against some, but not all, potential risks and losses. We do not carry business interruption insurance. We may elect not to obtain insurance for some risks if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable at a reasonable cost. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect us.

Title to Properties

      As is customary in the oil and natural gas industry, we make only a cursory review of title to farmout acreage and to onshore undeveloped oil and natural gas leases upon execution of contracts for the acquisition of leases. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. We perform complete reviews of title to Federal and state offshore lease blocks and onshore producing properties prior to acquisition. To the extent title opinions or other investigations reflect material title defects, the seller of the property, rather than us, is typically responsible for curing any such title defects at its expense. 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 undeveloped properties, we could suffer a loss of our entire investment in the property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and natural gas industry. Our producing properties are subject to a negative pledge in connection with our revolving credit facility.

Abandonment Costs

      We are responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on our oil and natural gas properties, pro rata to our working interest. As of January 1, 2003 we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets. We recorded asset retirement obligations of approximately $59 million and a cumulative effect of change in accounting principle on prior years of $3.4 million, net of tax effects, in our consolidated statement of operations on January 1, 2003. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates, and changes in environmental laws and regulations. Estimated asset retirement obligations are added to net unamortized historical oil and natural gas property costs for purposes of computing depreciation, depletion and amortization expense charges.

Employees

      At December 31, 2003, we had 372 full-time employees. We believe that our relationships with our employees are satisfactory. None of our employees is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site surveillance, permitting and environmental assessment.

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Risk Factors

      This section describes the material risks known to us that may adversely impact our operations and financial results. We encourage you to consider such risks in evaluating our business and future prospects. In addition we urge you to perform your own investigation with respect to us and our business. We also encourage you to read the other information included in this report, including our financial statements and the related notes.

      Our results of operations are highly dependent upon the prices of oil and natural gas. Historically, oil and natural gas prices have been volatile and are likely to continue to be volatile in the future. For example, our average sales prices for oil and natural gas for the year ended December 31, 2003 were $28.96/bbl and $4.93/Mcf before hedging, respectively, with 2003 production totaling 166.0 Bcfe and combined oil and natural gas sales of $813.9 million. In contrast, our average sales prices for oil and natural gas for the year ended December 31, 2002 were $23.66/bbl and $2.94/Mcf before hedging, respectively, with 2002 production totaling 129.9 Bcfe and combined oil and natural gas sales of $428.4 million. The prices received for oil and natural gas production depend upon numerous factors including, among others:

	•	consumer demand;
	•	governmental regulations and taxes;
	•	the price and availability of alternative fuels;
	•	geopolitical developments, including military activity in the Middle East;
	•	commodity processing, gathering and transportation availability;
	•	the level of foreign imports of oil and natural gas; and
	•	the overall economic environment.

      All of these factors are beyond our control. Any significant decrease in prices for oil and natural gas could have a material adverse effect on our financial condition, results of operations and quantities of reserves that are commercially recoverable. If the oil and natural gas industry experiences significant price decreases or other adverse market conditions in the future, we may not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures and our borrowing base and liquidity in general could be adversely impacted.

      We expect for the foreseeable future to make substantial capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. Historically, we have paid for these expenditures primarily with cash from operating activities and with proceeds from debt and equity financings. If revenues decrease as a result of lower oil and natural gas prices or for any other reason, we may not have the funds available to replace our reserves or to maintain production at current levels, which would result in a decrease in production over time.

      Our former independent public accountant, Arthur Andersen LLP, provided us with auditing services for prior fiscal periods through December 31, 2001, including issuing an audit report to our audited consolidated financial statements included in this report. On June 15, 2002, a jury in Houston, Texas found Arthur Andersen LLP guilty of a Federal obstruction of justice charge arising from the Federal

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      In addition, in connection with any future capital markets transaction in which we are required to include financial statements that were audited by Arthur Andersen LLP, as a result of the foregoing, investors may elect not to participate in any such offering or, in the alternate, may require us to obtain a new audit with respect to previously audited financial statements. Consequently, our financing costs may increase or we may miss attractive capital market opportunities.

      As of December 31, 2003, we had total long-term debt of $980.9 million and stockholders’ equity of $1.2 billion. Our level of debt could have important consequences to our business, including the following:

	•	it may be more difficult for us to satisfy our debt repayment obligations;
	•	we may have difficulties borrowing money in the future for acquisitions, to meet our operating expenses or other purposes;
	•	the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;
	•	we will need to use a portion of the money we earn to pay principal and interest on our debt which will reduce the amount of money we have to finance our operations and other business activities;
	•	we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
	•	we may be more vulnerable to economic downturns and adverse developments in our industry; and
	•	our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

      Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. Our earnings may be insufficient to allow us to pay the principal and/or interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. In addition, any failure to make scheduled payments of interest and/or principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Further our failure to make scheduled payments on our outstanding indebtedness or our failure to comply with the financial and other restrictive covenants in our debt instruments could result in an event of default

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      Together with our subsidiaries, we may be able to incur substantially more debt in the future. The restrictions in the indenture governing the terms of our debt relating to the incurrence of indebtedness are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. As of December 31, 2003, we had approximately $164.4 million of additional borrowing capacity under our revolving credit facility, subject to specific requirements, including compliance with financial covenants. To the extent new debt is added to our current debt levels, the risks described above could substantially increase.

      A significant amount of the oil and natural gas leases we acquired in December 2002, which are managed by our Western Division, cover interests located within the Uintah and Ouray Indian Reservations, in an area originally known as the Uncompahgre Reservation. These leases were granted by the State of Utah, the United States (through the Bureau of Land Management) or holders of patents from the United States. The Ute Indian Tribe has previously asserted various claims against the State of Utah and the United States regarding the existence, diminishment and/or abrogation of the Reservation’s boundaries and the extent of Tribal jurisdiction over these lands. These lawsuits raised questions as to whether the Ute Tribe could invalidate through litigation fee patents issued by the United States, the State of Utah’s ownership of such lands or the United States’ ownership of minerals subject to the acquired leases. These issues were settled as a result of the Ute Indian Tribe litigation. If claims of this nature were successfully asserted in the future, we might not be able to continue to produce hydrocarbons from or develop and exploit these assets, which could adversely affect our business and profitability.

      In addition, the Ute Indian Tribe as a sovereign nation has certain rights to regulate activities on Tribal lands, to approve access to and the right to use (occupy) Tribal lands, and to tax revenues from Tribal resources. Exercise of such rights can result in potential delays or increased costs to our operations on Tribal lands, which may not be foreseeable.

      All of the properties currently managed by our Western Division are located in Uintah County, Utah. Conditions such as severe weather, delays or decreases in production, the availability of equipment, facilities or services or the availability of capacity to transport, gather or process production could subject us to increased risk of loss of revenues and have a greater impact on our results of operations since most or all of these properties could be affected by the same event.

      Our estimates regarding the expenses and liabilities or the increase in our reserves and production resulting from our recent acquisitions may prove to be incorrect or we may not be successful in integrating the recently acquired properties into our existing business, all of which could have a material adverse effect on our financial condition and results of operations.

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      Our business strategy relies on growing our reserve base through acquisitions. We may not continue to be successful in identifying or consummating future acquisitions or integrating acquired businesses successfully into our existing business, or in anticipating the expenses or liabilities we will incur in doing so. Such failures may have a material adverse effect on future growth or results of operations.

      We are continually investigating opportunities for acquisitions. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Our ability to make future acquisitions may be constrained by our ability to obtain additional financing.

      Acquisitions may involve a number of special risks, including:

	•	unexpected losses of key employees, customers and suppliers of the acquired business;
	•	conforming the financial, technological and management standards, processes, procedures and controls of the acquired business with those of our existing operations; and
	•	increasing the scope, geographic diversity and complexity of our operations.

      Possible future acquisitions could result in our incurring additional debt and contingent liabilities, which could have a material adverse effect on our financial condition and operating results.

      Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues. Natural gas and oil production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain if available at all.

      Commodity prices and basis differentials significantly affect our financial condition, results of operations, cash flows and ability to borrow funds. Oil and natural gas prices, as well as basis differentials, are affected by several factors that we cannot control. We attempt to manage our exposure to oil and natural gas price volatility by entering into commodity price risk management arrangements for a portion of our expected production. In addition, we attempt to manage our exposure to basis differentials between delivery points by entering into basis swaps. In connection with the acquisition of our Uinta Basin properties, and as required by our revolving credit facility, we entered into a significant number of hedging arrangements relating to the production from such properties to help us manage our exposure. In the fourth quarter of 2003, we entered into additional commodity price risk management contracts in connection with the South Texas Acquisition. Commodity price and basis differential risk management transactions may limit our potential gains if oil and natural gas prices were to rise substantially, or basis differentials were to fall substantially, versus the price or basis differential established by the arrangements. These transactions also expose us to credit risk of non-performance by the counter-parties to the transaction. In addition, our commodity price and basis differential risk management transactions may

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	•	our production is less than expected;
	•	there is a widening of price differentials between delivery points for our production and the delivery point assumed in non-basis hedge arrangements;
	•	basis differentials tighten substantially from the prices established by these arrangements; or
	•	the counter-parties to our contracts fail to perform under terms of the contracts.

      In 2003, we recorded a realized loss of $102.4 related to hedge settlements, a realized gain of $2.7 million related to non-hedge settlements and an unrealized gain in the non-hedge change in fair value of derivatives of $9.5 million. No estimate of future settlements or mark-to-market gains or losses is determinable as such amounts are contingent upon commodity prices at the time of production. We may experience additional gains or losses from these activities in 2004. If commodity prices increase, our cash settlement costs will also increase. In addition, certain of our commodity price risk management arrangements will require us to deliver cash collateral or other assurances of performance to the counter-parties in the event that payment obligations with respect to commodity price risk management transactions exceed certain levels. As of February 19, 2004, we had $50.9 million of letters of credit outstanding for this purpose.

      The table below shows the effect of a range of assumed prices on future settlements of our commodity price risk management contracts outstanding as of December 31, 2003:

Estimate of Future Settlement of Outstanding Commodity Price Risk Management Contracts(1)

(1)	All of our commodity price risk management contracts outstanding as of December 31, 2003 expire by December 31, 2006.
(2)	Settlements were calculated based on the assumed high (Price Deck No. 1) and low (Price Deck No. 2) oil and natural gas prices on NYMEX, Northwest Pipeline Rocky Mountain Index, or Northwest, and Colorado Interstate Gas Index, or CIG.
(3)	Settlements were calculated based on the assumption that oil and natural gas prices will remain constant during the life of each contract.

      Our oil and natural gas operations are subject to the economic risks typically associated with drilling exploratory wells. In conducting exploration activities, we may drill unsuccessful wells and experience losses and, if oil and natural gas are discovered, we may be unable to economically produce or satisfactorily market such oil and natural gas. The new wells we drill may fail to be productive and we may be unable to recover all or any portion of our investment. The presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration activities to be unsuccessful, resulting in a total loss of our investment in such activities. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which may be beyond our control, including unexpected drilling

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      We rely to a significant extent on seismic data and other advanced technologies in conducting our exploration activities. Even when used and properly interpreted, seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. Such data is not conclusive in determining if hydrocarbons are present or economically producible. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. We could incur losses as a result of these expenditures.

      Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis. Furthermore, if oil and natural gas prices increase, our finding costs for additional reserves could also increase.

      There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control that could cause the quantities and net present value of our reserves to be overstated. The reserve information included or incorporated by reference in this report represents estimates based on reports prepared or audited by independent petroleum engineers and prepared by our internal engineers. Reserve engineering is not an exact science. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, any of which may cause these estimates to vary considerably from actual results, such as:

	•	historical production from the area compared with production from other producing areas;
	•	assumed effects of regulation by governmental agencies;
	•	assumptions concerning future oil and natural gas prices, future operating costs and capital expenditures; and
	•	estimates of future severance and excise taxes and workover and remedial costs.

      Estimates of reserves based on risk of recovery and estimates of expected future net cash flows prepared or audited by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variance may be material. The net present values referred to in this report should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. In accordance with requirements of the SEC, the estimated discounted net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower.

      We operate in the highly competitive areas of oil and natural gas exploitation, exploration and acquisition. The oil and natural gas industry is characterized by rapid and significant technological

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	•	seeking to acquire desirable producing properties or new leases for future exploration;
	•	marketing our oil and natural gas production;
	•	integrating new technologies; and
	•	acquiring the personnel, equipment and expertise necessary to develop and operate our properties.

      Many other companies have financial, technological and other resources substantially greater than our own. These companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Further, many of our competitors may enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for oil and natural gas and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

      Our operations and facilities are subject to certain Federal, state, Tribal and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations, or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations, such as:

	•	land use restrictions;
	•	drilling bonds and other financial responsibility requirements;
	•	spacing of wells;
	•	unitization and pooling of properties;
	•	habitat and endangered species protection, reclamation and remediation, and other environmental protection;
	•	protection and preservation of historic, archaeological and cultural resources;
	•	safety precautions;
	•	operational reporting; and
	•	taxation.

      Under these laws and regulations, we could be liable for:

	•	personal injuries;
	•	property and natural resource damages;
	•	oil spills and releases or discharges of hazardous materials;
	•	well reclamation costs;
	•	remediation and clean-up costs and other governmental sanctions, such as fines and penalties; and
	•	other environmental damages.

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      Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

      Other companies operate approximately 23% of the net present value of our reserves and we have limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling and exploitation activities on properties operated by others, therefore, depend upon a number of factors that will be outside our control, including:

	•	timing and amount of capital expenditures;
	•	the operator’s expertise and financial resources;
	•	approval of other participants in drilling wells; and
	•	selection of technology.

      Where we are not the majority owner or operator of a particular oil and natural gas project, we may have no control over the timing or amount of capital expenditures associated with such project. If we are unable or unwilling to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

      Our operations are subject to hazards and risks inherent in drilling for, producing and transporting oil and natural gas, such as:

	•	fires;
	•	natural disasters;
	•	explosions;
	•	formations with abnormal pressures;
	•	casing collapses;
	•	embedded oilfield drilling and service tools;
	•	uncontrollable flows of underground natural gas, oil and formation water;
	•	surface cratering;
	•	pipeline ruptures or cement failures; and
	•	environmental hazards such as natural gas leaks, oil spills and discharges of toxic gases.

      Any of these risks can cause substantial losses resulting from:

	•	injury or loss of life;
	•	damage to and destruction of property, natural resources and equipment;
	•	pollution and other environmental damage;

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	•	regulatory investigations and penalties;
	•	suspension of operations; and
	•	repair and remediation costs.

      As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. However, losses could occur for uninsurable or uninsured risks, or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could harm our financial condition and results of operations.

      Our operations and financial results could be significantly impacted by conditions in the Gulf of Mexico because we explore and produce extensively in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the Gulf of Mexico, including those relating to:

	•	adverse weather conditions;
	•	oil field service costs and availability;
	•	compliance with environmental and other laws and regulations;
	•	remediation and other costs resulting from oil spills or releases of hazardous materials; and
	•	failure of equipment or facilities.

      In addition, we are currently conducting some of our exploration in the deep waters (greater than approximately 1,000 feet) of the Gulf of Mexico, where operations are more difficult and costly than in shallower waters. The deep waters in the Gulf of Mexico lack the physical and oilfield service infrastructure present in its shallower waters. As a result, deep water operations may require a significant amount of time between a discovery and the time that we can market our production, thereby increasing the risk involved with these operations.

      Further, production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production, and as a result, our reserve replacement needs from new prospects may be greater there than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

      The successful implementation of our strategies and handling of other issues integral to our future success will depend, in part, on our experienced management team. The loss of key members of our management team, including Donald D. Wolf, our Chairman and Chief Executive Officer, and Barth E. Whitham, our President and Chief Operating Officer, could have an adverse effect on our business. We entered into employment agreements with Messrs. Wolf and Whitham to secure their employment with the Company. We do not carry key man insurance. Our exploratory drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for experienced explorationists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

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      The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities could adversely impact our ability to deliver the oil and natural gas we produce to market in an efficient manner, which could harm our financial condition and results of operations. We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Our ability to produce and market oil and natural gas is affected and may be also harmed by:

	•	Federal and state regulation of oil and natural gas production;
	•	transportation, tax and energy policies;
	•	changes in supply and demand; and
	•	general economic conditions.

      Our principal stockholders include Medicor Foundation, also referred to as Medicor, Westport Energy LLC, also referred to as WELLC, EQT Investments, Inc., an affiliate of Equitable Resources Inc. also referred to as EQT, and a group of former stockholders of Belco Oil & Gas Corp., also referred to as the Belfer Group. EQT, Medicor, the Belfer Group and WELLC beneficially owned approximately 17.0%, 14.3%, 6.8% and 4.8%, respectively, of our outstanding common stock as of January 31, 2004, which collectively represented approximately 42.9% of our outstanding common stock as of that date. These stockholders, acting together through a termination and voting agreement, dated as of October 1, 2003, or otherwise, based on their current share ownership, may be able to influence or control the outcome of the election of directors. In addition, based on their current share ownership, these stockholders may be able to control the adoption or amendment of provisions in our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions, if they choose to act together. These factors may also delay or prevent a change in our management or voting control.

      In addition to marketing our oil and gas production, our marketing activities generally include marketing oil and gas production for royalty owners. Over the past several years, royalty owners have commenced litigation against a number of companies in the oil and gas production business claiming that amounts paid for production attributable to the royalty owners’ interest violated the terms of the applicable leases and laws in various respects, including the value of production sold, permissibility of deductions taken and accuracy of quantities measured. Some of this litigation was commenced as class action suits, including two class action suits filed against Westport involving some of our Wyoming properties, and we may be required to make payments as a result of such litigation. In addition, our costs relating to the marketing of oil and gas may increase as new cases are decided and the law in this area continues to develop.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

      The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and this report:

      Basis differential. The difference between oil and natural gas prices quoted on the NYMEX and the prices we receive at the locations we deliver our produced oil and natural gas.

      bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

      bbl/d. One stock tank barrel of oil or other liquid hydrocarbons per day.

      Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.

      Bcfe. One billion cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

      CO₂ Flood or injections. A tertiary recovery method in which CO₂ is injected into the reservoir to enhance oil recovery.

      Completion. The installation of permanent equipment for the production of oil or natural gas.

      Delay Rentals. Fees paid to the owner of the oil and natural gas lease prior to the commencement of production.

      Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

      Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a strategic horizon known to be productive.

      Exploitation. The continuing development of a known producing formation in a previously discovered field. To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.

      Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

      Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

      Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

      Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

      Gross Producing Wells. The total number of producing wells in which we have a working interest.

      Horizontal Drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.

      Infill Drilling. A drilling operation in which one or more development wells is drilled within the proven boundaries of a field between two or more other wells.

      Injection Well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

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      Mbbl. One thousand barrels of oil or other liquid hydrocarbons.

      Mcf. One thousand cubic feet of natural gas.

      Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

      Mineral Interest. The property interest that includes the right to enter to explore for, drill for, produce, store and remove oil and natural gas from the subject lands, or to lease to another for those purposes.

      Mmbbl. One million barrels of oil or other liquid hydrocarbons.

      Mmbtu. One million British thermal units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

      Mmbtu/d. One million British thermal units per day.

      Mmcf. One million cubic feet of natural gas, measured at standard atmospheric conditions.

      Mmcf/d. One million cubic feet of natural gas per day.

      Mmcfe. One million cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

      Mmcfe/d. One million cubic feet equivalent of natural gas per day, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 bbl of oil.

      Net Acres or Net Wells. Gross acres or wells multiplied, as the case may be, by the percentage working interest owned by us.

      Net Production. Production that is owned by Westport less royalties and production due others.

      Non-operated Working Interest. The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.

      NYMEX. New York Mercantile Exchange.

      Oil. Crude oil or condensate.

      Operating Income. Gross oil and natural gas revenue less applicable production taxes and lease operating expense.

      Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.

      Present Value of Future Net Revenues or Present Value, or PV10. The pretax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

      Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

      Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made, as such reserves are further defined in Rule 4-10(a)(2).

      Proved Undeveloped Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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      Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

      Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

      Secondary Recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.

      2-D Seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.

      3-D Seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

      Tcf. One trillion cubic feet of natural gas, measured at standard atmospheric conditions.

      Tertiary Recovery. An enhanced recovery operation that normally occurs after waterflooding in which chemicals or gasses are used as the injectant.

      Undeveloped Acreage. Acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well.

      Waterflood. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.

      Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

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Properties — Principal Areas of Operations

      Our operations are concentrated in four divisions: Northern, Western, Southern and Gulf of Mexico. We operate approximately 77% of the net present value of our reserves. We finance our exploitation, exploration and acquisition activities through cash flows from operations and through borrowings under our revolving credit facility and other financing activities. Set forth below is summary information concerning average daily production during the fourth quarter of 2003, estimated reserves and a pre-tax SEC net present value of estimated proved reserves discounted at 10%, as of December 31, 2003 in our divisions.

(1)	Mmbbls converted to Bcfe at a six to one conversion.
(2)	Excludes value attributable to the gathering and compression assets of Westport Field Services, LLC, one of our subsidiaries.
(3)	Includes production from the South Texas Acquisition from December 19, 2003 through December 31, 2003.

      The Northern Division conducts operations in the Rocky Mountain region and primarily includes the Williston, Powder River, Big Horn, Wind River and Greater Green River Basins. The division represented approximately 17% of our net present value of estimated proved reserves as of December 31, 2003, and contributed approximately 22% of our fourth quarter 2003 net production. We have interests in 506,868 developed and 1,027,359 undeveloped gross acres and in 2,069 gross (approximately 730 net) producing wells in this division.

      Williston Basin. We continue to focus our activities on horizontal field extensions and growth of secondary recovery projects. Our most active project continues to be the Wiley field. We operate this waterflood with a 54% working interest. In 2000, we initiated a horizontal drilling program and through December 31, 2003 have drilled 48 wells, all of which were successful. In addition to the horizontal drilling, we increased water injection capacity to expand our waterflood program. As a result of this activity, average gross daily production in this field has increased from approximately 600 bbl/d in April 2000 to over 2,700 bbl/d during the fourth quarter 2003. Over the next 12 months, we plan to drill eight to 12 additional wells in the Wiley field while continuing to increase water injection capacity. In addition to our work in the Wiley field we drilled 10 operated horizontal wells, nine of which were successful, in our Horse Creek, TR, Tree Top and Bear Creek fields. In 2004, we plan to drill horizontal development wells in our Horse Creek, TR, Lone Butte and Putnam fields.

      Greater Green River Basin. We have interests in approximately 397,000 gross undeveloped acres in the Greater Green River Basin. Over the next 12 to 24 months we expect to drill five to ten exploration wells in this basin. One of our primary operating areas within the basin is the Moxa Arch Complex. Production from Moxa Arch wells tends to be long-lived, with the potential for greater than a 25 year reserve life. We drilled 14 wells in the Moxa Arch in 2003, 13 of which were successful. Our net

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      Big Horn Basin. The Gooseberry field is our most significant property in the Big Horn Basin. We own a 100% working interest (nearly 90% net revenue interest) in this field, which consists of two waterflood units. Since acquiring the field in February 1995, we have doubled gross production from 535 bbl/d to approximately 1,080 bbl/d in December 2003. In 2003 we drilled four development wells and one water source well, all of which were successful. We currently have interests in over 186,000 gross undeveloped acres in the Big Horn Basin.

      Coalbed Methane. Since initiating our coalbed methane drilling in the Powder River Basin in 2000, we have participated in 301 wells through December 31, 2003, 297 of which have been successful. We operate 160 of these wells. In 2003 we initiated an eight well development project in the Big George coal within the House Creek field. Net coalbed methane production in the Powder River Basin averaged approximately 13.4 Mmcf/d in fourth quarter 2003. In 2003 we initiated three additional coalbed methane projects, one each in the Greater Green River Basin, the Uinta Basin in northeastern Utah and the Raton Basin of southeastern Colorado. In the Greater Green River Basin we participated in one well in the Almond coal. In the Uinta Basin we drilled nine wells and established production of approximately 1.3 Mmcf/d (net) from the Navajo coal. In the Raton Basin we began operations in early January 2004 and drilled our first three wells in the Vermejo coal. Our coalbed methane acreage position covers over 58,000 gross developed acres in the Powder River Basin, over 28,500 gross undeveloped acres in the Uinta Basin and approximately 17,300 gross undeveloped acres in the Raton Basin. In 2004 we plan to drill 15 to 20 WyoDak and 10 to 16 Big George wells in the Powder River Basin, five to 10 wells in the Greater Green River Basin, 10 to 15 wells in the Uinta Basin and 10 to 15 wells in the Raton Basin.

      The Western Division conducts operations in the Greater Natural Buttes area of Uintah County, Utah. We acquired these properties in December 2002, which were producing approximately 68 Mmcfe/d net to us at the time of acquisition. We have increased net production to an average of 84 Mmcfe/d during the fourth quarter of 2003, representing 18% of our total net production. This division contributed approximately 25% of our net present value of estimated proved reserves as of December 31, 2003. We have interests in 191,612 developed and 79,068 undeveloped gross acres and in 1,081 gross (approximately 831 net) producing wells in this division.

      The Natural Buttes unit has undergone a series of downspacings from the original 320 acres per well spacing to a current spacing of 40 acres per well. Unit wells are characterized by established production profiles and long reserve lives. Producing horizons range from 3,000 to 13,000 feet. Historically production has been primarily from the Wasatch formation. In 2003, our drilling program focused on developing the Mesa Verde potential within and adjacent to the Natural Buttes unit. Production from this formation is often commingled with the Wasatch. Through our high working interest and significant level of operations we can control drilling, completion and production of the majority of our wells. In 2003 we drilled 83 wells, all of which were successful and we expect to drill 95 to 105 wells in this area in 2004.

      The Southern Division conducts operations in the onshore Gulf Coast, Permian Basin and Mid-Continent regions. This division represented 43% of the net present value of our estimated proved reserves as of December 31, 2003, and contributed 34% of our fourth quarter 2003 net production. We have interests in 582,160 developed and 182,689 undeveloped gross acres and in 3,436 gross (approximately 1,667 net) producing wells in this division.

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      Onshore Gulf Coast. Our Gulf Coast operations include producing trends in Louisiana and the Texas Gulf Coast.

	•	Southeast Texas Properties. We acquired our Southeast Texas properties in September 2002, which are focused in the Yegua, Frio, Vicksburg and Hackberry Trends. We maintained an active drilling program in this area during 2003, drilling two development wells, both of which were successful, and ten exploration wells, four of which were successful. Net production has increased from 28 Mmcfe/d at the time of acquisition to an average of 40.3 Mmcfe/d in the fourth quarter of 2003. We expect to drill 12 to 15 exploration prospects over the next 12 to 24 months.
	•	South Texas Properties. We acquired these properties in December 2003. At December 31, 2003 the proved reserves were estimated at 208 Bcfe, of which 97% is natural gas. These assets complement a growing core area for the company in South Texas and produce from the Lobo, Frio, Vicksburg and Wilcox Trends. The properties are currently producing at approximately 62.2 Mmcfe/d (net). In January 2004, the Company initiated a four-rig drilling program. We expect to spend approximately $50 million in capital during 2004 and plan to drill 30 to 35 development wells and five to 10 exploration wells in this area during the year. The three largest fields are Southwest Speaks, Cage Ranch and JC Martin.

	•	Southwest Speaks Field. The Southwest Speaks field in Lavaca County, Texas produces from the Frio, Yegua and Wilcox formations at depths ranging from 3,300 to 15,000 feet. The field currently produces approximately 11.9 Mmcfe/d (net). We expect to drill five to seven development wells and one exploration well in this field during 2004.
	•	Cage Ranch Field. The Cage Ranch field in Brooks County, Texas produces from the Frio and Vicksburg formations at depths ranging from 6,500 to 10,500 feet. The field currently produces approximately 15.0 Mmcfe/d (net). We expect to drill five to eight development wells and one exploration well in 2004.
	•	JC Martin Field. The JC Martin field in Zapata County, Texas produces from the Lobo formation at depths ranging from 8,500 to 10,000 feet. The field currently produces approximately 10.3 Mmcfe/d (net). We expect to drill eight to ten development wells in this field during 2004.

	•	Elm Grove Field. We maintained an active development drilling program in the Elm Grove field in 2003 by drilling 39 wells, 38 of which were successful. Net production averaged approximately 18.9 Mmcfe/d in fourth quarter 2003. In 2004 we expect to drill 30 to 35 development wells in this field.
	•	North Louisiana Field Complex. Development drilling in this four-field complex continues to be active. In 2003 we drilled 20 wells, all of which were successful. Net fourth quarter 2003 production averaged 7.5 Mmcfe/d. We anticipate drilling between 15 and 25 development wells in this region in each of the next two years.

      Permian Basin. Our principal Permian Basin activity continues to be focused on development of the Andrews unit and the Shafter Lake San Andres unit waterfloods.

	•	Andrews Unit. The Andrews unit waterflood produces from the Wolfcamp/ Penn formation at approximately 8,600 feet. We have a 98.6% working interest in this 3,230-acre unit. During 2003 we continued expanding the waterflood program by drilling additional wells, converting wells to injectors and performing workovers on existing wells. As a result, gross production continues to increase from an 855 bbl/d average in 2000 to an average of nearly 1,300 bbl/d in the fourth quarter of 2003. We believe that production from this unit can be further enhanced with the use of CO2 flooding or other tertiary recovery methods.
	•	Shafter Lake San Andres Unit. The Shafter Lake San Andres unit is a 12,880-acre unit that produces from the Grayburg and San Andres formations at a depth of approximately 4,500 feet. We have an 81.4% working interest in this secondary recovery unit. In 2003, we drilled 10 wells on

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		10-acre spacing and plan to drill 10 to 15 additional 10-acre wells in 2004. The unit produced an average of 685 gross bbl/d in the fourth quarter of 2003.

      Mid-Continent. Our Mid-Continent operations are currently focused in Oklahoma and Kansas. Oil production is concentrated in our operated waterfloods in Oklahoma, while natural gas production is primarily from third party operated wells in Oklahoma and in our operated wells in Kansas.

      The Gulf of Mexico Division represented 15% of the net present value of our estimated proved reserves as of December 31, 2003, and contributed 26% of our fourth quarter 2003 net production. As of December 31, 2003, we have interests in 329,229 developed and 286,793 undeveloped gross acres and in 157 gross (approximately 45 net) producing wells in the Gulf of Mexico.

      In addition to a production base with numerous exploitation opportunities within our developed acreage, the Gulf of Mexico provides us with moderate-risk exploration targets. We drilled 11 exploration wells in the Gulf of Mexico in 2003, four of which were successful, and two development wells , both of which were successful. We have under license 3-D seismic data covering approximately 30,470 square miles (approximately 3,900 blocks) and 2-D seismic data covering 150,000 linear miles within the Gulf of Mexico. In the third quarter of 2003 we entered into an exploration agreement with Chevron U.S.A. Inc. (a wholly owned subsidiary of ChevronTexaco). Under this agreement the parties have identified nine prospects, and expect to identify additional prospects over the next two years. We plan to participate for 45% of the interest held by Chevron U.S.A. Two unsuccessful wells were drilled in 2003.

      West Cameron Blocks 180/198. The West Cameron Blocks 180/198 complex is located 30 miles offshore in 52 feet of water. In 2003 we commenced production on one 2002 development well and drilled one unsuccessful exploration well. The complex has produced approximately 1.7 Tcf of natural gas and 10 Mmbbl of oil from over 20 separate producing zones since its discovery. In fourth quarter 2003, the field produced 36.4 Mmcfe/d net to our interest.

      South Timbalier Block 316. The South Timbalier Block 316 is located approximately 66 miles offshore in 400 feet of water, we discovered this field in the fourth quarter of 2001 and commenced production in the fourth quarter of 2003. We operate the field with a 40% working interest. In early February 2004 the field produced approximately 47 Mmcfe/d net to our interest.

      High Island Block 197. This field is located approximately 28 miles offshore in 50 feet of water and was discovered in the third quarter of 2001. We have a 25% non-operated working interest in the field. During 2003, four additional wells were drilled, following the discovery well, three of which were successful. The field commenced production in May 2002. In the fourth quarter of 2003 the field averaged 11.3 Mmcfe/d net to our interest.

      Ship Shoal Block 94. Ship Shoal Block 94 is located approximately 15 miles offshore in 20 feet of water. We discovered this field in the first quarter of 2003 and operate the field with a 60% working interest. The field commenced production in the third quarter of 2003 and averaged 8.9 Mmcfe/d net to our interest in the fourth quarter of 2003.

      Galveston Block 352. We drilled a successful exploratory well in the spring of 2002 and put the well on production in August of that year. We drilled a second well in 2003, which commenced production in the third quarter. We operate the wells with a 67% working interest. In the fourth quarter of 2003 the field averaged 5.4 Mmcfe/d net to our interest.

      West Cameron Block 73. This field is located approximately 12 miles offshore in 33 feet of water and was discovered in the second quarter of 2003. We have a 30% non-operated working interest in the field. The field commenced production in the fourth quarter of 2003 and is currently producing 4.1 Mmcfe/d net to our interest.

      High Island Block 84. This field is located approximately 23 miles offshore in 50 feet of water and was discovered in the third quarter of 2001. We drilled three development wells in the block during 2002.

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      Green Canyon Block 640. We have a 3.7% overriding royalty interest in the Green Canyon Block 640, part of the 2002 Tahiti discovery drilled by ChevronTexaco. Facility design and development is ongoing. A production test is expected in 2004.

Proved Reserves

      The following table sets forth estimated proved reserves for the periods indicated:

(1)	The difference in the net present value from December 31, 2002 to December 31, 2003 resulted almost entirely from (i) the addition of 208 Bcfe of proved reserves acquired in connection with the South Texas Acquisition, (ii) the addition of 188 Bcfe as discoveries and extensions, (iii) the increase in commodity prices used to determine net present value (from $31.23 to $32.55 per bbl of oil and from $4.58 to $5.83 per Mmbtu of natural gas) and (iv) the inclusion of a portion of our producing well overhead associated with general corporate expenses related to operated oil and natural gas producing activities.
(2)	The difference in net present value from December 31, 2001 to December 31, 2002 resulted almost entirely from (i) the addition of 722.7 Bcfe of proved reserves acquired in connection with the Williston Basin, Southeast Texas and Utah acquisitions in 2002, (ii) the addition of 58 Bcfe as discoveries and extensions and (iii) the increase in commodity prices used to determine net present value (from $19.78 to $31.23 per bbl of oil and from $2.72 to $4.58 per Mmbtu of natural gas).
(3)	The standardized measure is the value of the future after-tax net revenues discounted at 10%. The difference between the net present value and the standardized measure is the effect of income taxes discounted at 10%.

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      Estimated quantities of our oil and gas reserves and the net present value of such reserves as of December 31, 2003 are based upon reserve reports prepared by Ryder Scott Company, L. P., Netherland, Sewell & Associates, Inc. and our engineering staff. The Ryder Scott report covered approximately 71% of the total net present value of our proved reserves. The Netherland Sewell report covered the South Texas properties we acquired in December 2003, comprising approximately 16% of the total net present value of estimated proved reserves and the internally generated report covered the remaining 13% of the net present value of such reserves. At December 31, 2002 the Ryder Scott reports covered 81% of the total net present value of estimates of total proved reserves, preparing 58% and auditing 23%. The internally generated report covered the remaining 19% of the net present value of estimated proved reserves. At December 31, 2001 Ryder Scott audited 87% of the total net present value of estimates of total proved reserves and the remaining 13% of net present value of the reserves was unaudited.

      Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production.

      There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of exploitation expenditures. The data in the above table represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates may be revised from time to time and may vary from the quantities of oil and natural gas that are ultimately recovered.

      Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The present value shown should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is mandated by generally accepted accounting principles in the United States, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties that we operate, expenses include a portion of our producing well overhead associated with general corporate expenses related to operated oil and natural gas activities. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things, general and administrative costs and interest expense.

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Production and Price History

      The following table sets forth information regarding net production of oil, natural gas and natural gas liquids, and certain price and cost information for each of the periods indicated:

Producing Wells

      The following table sets forth information at December 31, 2003, relating to the producing wells in which we owned a working interest as of that date. We also held royalty interests in 1,904 producing wells as of that date. Wells are classified as oil or natural gas wells according to their predominant production stream.

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Acreage

      The following table sets forth information at December 31, 2003, relating to acreage held by us. Developed acreage is assigned to producing wells. Undeveloped acreage is acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well, including leasehold interests identified for exploitation or exploratory drilling. The term “gross acres” refers to the total number of acres in which we own a working interest. The term “net acres” refers to gross acres multiplied by our fractional working interest therein.

      The total net undeveloped acres expiring in 2004, 2005 and 2006 are 123,409, 168,764 and 82,722, respectively.

Drilling Results

      The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they generate a reasonable rate of return.

      As of December 31, 2003, nine additional exploration and 31 development wells were in progress.

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      Westport Oil and Gas Company, L.P., our wholly-owned subsidiary, is a defendant in a case brought in July 2001 against its predecessor, Belco Energy Corp., in the district court of Sweetwater County, Wyoming. The complaint seeks damages on behalf of a purported class of royalty owners for alleged improper deduction, valuation and reporting under the Wyoming Royalty Payment Act in connection with royalty payments made by Belco on production from wells it operates in the Moxa Arch area of the Green River Basin. During initial stages of the case plaintiffs have advised us that they calculate the amount of damages allegedly owed by Belco to be approximately $1,165,000, which includes attorneys fees and litigation costs. We have denied liability for any of these damages and believe that we have valid defenses to plaintiffs’ claims. Class certification and discovery have been stayed pending the decision by the Wyoming Supreme Court in a case involving unrelated parties that may have a bearing on this case and other similar cases filed by plaintiffs against other oil and natural gas industry operators in the Green River Basin. Settlement discussions have occurred with plaintiffs and are ongoing. We believe that our potential liability with respect to this proceeding is not material in the aggregate to our financial position, results of operations or cash flows. Accordingly, we have not established a reserve for loss in connection with this proceeding.

      From time to time, we may be a party to various other legal proceedings. Except as discussed herein, we are not currently party to any material pending legal proceedings.

      No matters were submitted during the fourth quarter of the fiscal year covered by this Form 10-K to a vote of our security holders, through the solicitation of proxies or otherwise.

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PART II

Price Range of Common Stock

      Our common stock is listed and traded on the New York Stock Exchange, or NYSE, under the symbol “WRC.” Prior to our merger with and into Belco, Belco common stock was listed and traded on the NYSE under the symbol “BOG.” The following table sets forth the high and low sales prices per share of Belco and Westport common stock on the NYSE, for the periods indicated: