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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)

OR

Commission file number: 001-14256

WESTPORT RESOURCES CORPORATION
(Exact name of Registrant as specified in its charter)

410 Seventeenth Street, Suite 2300
Denver, Colorado 80202
(Address of principal executive offices)
(Zip code)

(303) 573-5404
(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:
None
(Title of class)

        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 ý    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. / /

        The aggregate market value of the 16,380,684 shares of voting common stock held by non-affiliates of the Registrant, based upon the closing sale price of the common stock on March 1, 2002 of $18.69 per share as reported on the New York Stock Exchange, was $306,154,984. At such date, 52,091,897shares of the Registrant's common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

        Parts of the definitive proxy statement for the Registrant's 2002 annual meeting of stockholders are incorporated by reference into Part III of this Form 10-K.

Table of Contents

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 the merger of Westport Resources Corporation and Belco Oil & Gas Corp., also referred to as the Merger, 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 terms 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 and include, among other things, statements relating to:

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amount, nature and timing of capital expenditures;



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drilling of wells;



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reserve estimates;



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timing and amount of future production of oil and natural gas;



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operating costs and other expenses;



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cash flow and anticipated liquidity;



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estimates of proved reserves, exploitation potential or exploration prospect size; and



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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.

PART I

ITEM 1. BUSINESS

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. Except as otherwise specified, references to "Old Westport" are to Westport Resources Corporation prior to its merger, referred to as the Merger, with and into Belco Oil & Gas Corp. on August 21, 2001. Belco survived the Merger and changed its name to "Westport Resources Corporation." Because former Old Westport stockholders now own a majority of Westport common stock as a result of the Merger, the Merger is accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco. References to "Belco" are to Belco Oil & Gas Corp. prior to the Merger. 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 22.

        We are an independent energy company engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the United States. Based upon production levels for the year ended December 31, 2001, we are among the 25 largest domestic independent exploration and production companies. Our corporate headquarters are in Denver, Colorado and we have division offices in Denver, Colorado, Dallas, Texas and Houston, Texas.

        We focus on maintaining a balanced portfolio of lower-risk, long-life onshore reserves and higher-margin offshore reserves to provide a diversified cash flow foundation for our exploitation, acquisition and exploration activities. Our reserves and production operations are concentrated in the following divisions: Northern, which includes primarily properties in North Dakota and Wyoming; Southern, which includes primarily properties in Oklahoma, Texas and Louisiana; and Gulf of Mexico, which includes our offshore properties. As of December 31, 2001, our reserve base consisted of 56% natural gas and 44% oil and had a reserve life index of 7.2 years, based upon our annualized production rate in the fourth quarter of 2001. We produced 88.1 Bcfe in 2001 while generating oil and natural gas sales and EBITDAX of $317.3 million and $244.9 million, respectively.

        Over the last several years, growth in our reserves, production and cash flow has resulted primarily from our acquisitions and subsequent development drilling activities focused in core project areas. From Old Westport year-end 1997 to Westport as of December 31, 2001, we increased proved reserves from 197 Bcfe to 930 Bcfe, a compounded annual growth rate of approximately 47%. Over the same period we increased average daily production from 66 Mmcfe/d to 353 Mmcfe/d, a compounded annual growth of approximately 52%. This growth has been complemented by management's ability to substantially reduce our cost structure, including lease operating expenses, transportation costs, production taxes and general and administrative costs, over the same period from $1.32 per Mcfe to $1.04 per Mcfe.

        We believe that our exploitation and acquisition expertise and our sizable exploration inventory, together with our operating experience and efficient cost structure, provide us with the ability to generate substantial current cash flow and position us for future growth. We operate approximately 70% of the net present value of our reserves, allowing us to better manage expenses, capital allocation and the decision-making processes related to other aspects of exploitation and exploration activities. Our capital budget for 2001 excluding amounts related to the Merger was approximately $195 million, balanced between exploitation and exploration both onshore and offshore. We have a capital budget of approximately $170 million for 2002, which does not include potential acquisitions. Nearly 70% of the 2002 budget is allocated to exploitation, which includes lower-risk drilling and continued expansion of a number of our secondary recovery projects. We have over 1,000 identified drilling opportunities and anticipate drilling over 300 of these locations in 2002.

        As of December 31, 2001, our estimated proved reserves of 930 Bcfe had a pre-tax SEC net present value, discounted at 10%, of approximately $924 million based on year-end NYMEX prices of $19.78 per barrel of oil and $2.72 per Mmbtu of natural gas. Approximately 76% of our reserves were classified as proved developed as of December 31, 2001. The following table sets forth the volume and net present value of our estimated proved reserves as of December 31, 2001 and a summary of our fourth quarter 2001 production by division:

Our Strategy

        Our strategy is to grow our reserve base, diversify our risk profile and expand our investment opportunities by (a) executing on lower-risk exploitation projects and acquisitions and (b) drilling potentially higher-impact exploration prospects, thereby balancing risks while maintaining significant potential for growth. To accomplish this, we will:

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allocate approximately 65% to 75% of our capital budget to exploitation activities and 25% to 35% to exploration projects;



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enhance our existing and acquired properties through exploitation to increase production and enlarge our reserve base;



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pursue acquisitions with developmental upside to grow our inventory of exploitation projects and to employ our operating expertise;



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generate and drill an extensive prospect inventory by applying current technology and leveraging off our significant operational capabilities; and



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maintain financial flexibility and a conservative capital structure.

        We intend to implement our strategy as follows:

        Continue an Active Exploitation Program.  We drilled 242 development wells onshore and nine development wells offshore in the Gulf of Mexico in 2001, 242 of which were successful, resulting in a 96% success rate. In 2000, we drilled 153 development wells onshore and 24 development wells in the Gulf of Mexico with a 95% success rate. We have identified significant prospective exploitation projects both onshore and offshore and have a proven track record of executing such projects. For example, in 2000 we initiated a horizontal infill drilling program in our Wiley field in North Dakota, and enhanced our water injection capacity in that area to enhance the recovery of reserves. Through December 31, 2001, we have drilled 22 wells in this field, all of which have been successful. This activity increased gross production in this field from approximately 600 bbl/d in April 2000 to over 2,400 bbl/d in December 2001. In the next 12 months, we plan to drill 10 to 15 additional wells in the Wiley field. Company-wide we plan to drill more than 300 development wells in 2002.

        Pursue and Capitalize on Acquisitions.  Through a series of acquisitions from 1995 through 2000, Old Westport substantially increased its reserve base by investing approximately $454 million in acquiring oil and natural gas properties at an average unit acquisition cost of $1.10 per Mcfe. Old Westport invested an additional $199 million to exploit these acquired properties and added proved reserves of 161 Bcfe. The subsequent reserve additions resulting from these exploitation activities replaced approximately 87% of production from the acquired properties. These acquisitions generated cash flows through December 31, 2001 of approximately $482 million.

        In August 2001, we completed our Merger with Belco resulting in approximately $1.0 billion of allocated costs, including approximately $701.1 million allocated to proved oil and natural gas properties, or $1.39/Mcfe. We believe that, due to the significant geographic overlap and the similarity of reserve characteristics, the Belco operations complement our existing onshore areas of operations. Within our Northern Division, the Merger added in excess of 1.1 million gross acres to our exploration inventory in the gas-prone basins of Wyoming, while adding 43 Mmcfe/d to production in this region. The Merger also added critical mass to our onshore Gulf Coast, Permian and Mid-Continent regions, growing our net daily production in these regions from 24 Mmcfe/d to over 144 Mmcfe/d after the Merger.

        Due to a trend toward industry consolidation and asset rationalization, we believe that we will continue to have opportunities to acquire oil and natural gas properties at attractive rates of return. We have an experienced management team focused on executing our disciplined approach to identifying and capturing these opportunities.

        Capitalize on Exploration Opportunities.  Our strategy continues to focus on enhancing reserve and production growth in our core areas by emphasizing and applying the latest geological, geophysical and drilling technologies. We seek exploration opportunities with characteristics similar to producing properties in our core areas in order to leverage our technical and operational expertise. For the twelve months ended December 31, 2001, we had a 75% success ratio on our exploration projects.

        Onshore, we hold interests in approximately 1.6 million gross (approximately 0.6 million net) undeveloped acres, two-thirds of which are located in the principal natural gas basins of Wyoming—the Greater Green River, Wind River and Big Horn. Over the next 12 to 24 months, we plan to drill 18 to 23 exploratory wells onshore, primarily in Wyoming and in the Texas Gulf Coast.

        In the Gulf of Mexico, we had a 21 prospect exploration inventory located on 24 blocks as of December 31, 2001, and had additional exploration opportunities in several of our 67 developed blocks. We have under license 3-D seismic data covering over 18,000 square miles (2,300 blocks) and 2-D seismic data covering over 150,000 linear miles in this area. In order to control activity, our strategy typically includes retaining large working interests in our internally-generated prospects. Prior to drilling, we typically trade a portion of these prospects for interests in prospects developed by others. This strategy allows us to achieve multiple prospect exposure while diversifying our investment risk.

        Maintain Financial Flexibility and a Conservative Capital Structure.  We plan to maintain financial flexibility and a conservative capital structure, which we believe is integral to the successful execution of our exploitation, acquisition and exploration strategy. Our total debt to total capitalization ratio of 31.8% at year-end 2001 is one of the lowest for publicly traded companies in our industry, and our pro forma debt to EBITDAX ratio for the year ended December 31, 2001 was 1.75x.

        On November 5, 2001, we completed the private placement of $275 million of 8¹/4% Senior Subordinated Notes due 2011 pursuant to Rule 144A promulgated under the Securities Act. Proceeds of approximately $268 million, net of underwriting discounts and offering costs, were used to reduce outstanding indebtedness under our revolving credit facility. On March 14, 2002, we completed the exchange of these notes for new notes with substantially identical terms, except that the new notes are generally freely tradable.

Company History

        Prior to the Merger, Old Westport was a Denver-based independent energy company with exploitation, exploration and acquisition activities in the Gulf of Mexico, the Rocky Mountains, West Texas/Mid-Continent and the Gulf Coast. Old Westport was formed in connection with the merger in April 2000 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.

        Prior to the Merger, Belco was an independent energy company with its primary operating office in Dallas, Texas. Formed in 1992, Belco was engaged in the exploration for, and the acquisition, exploitation, development and production of, natural gas and oil in the United States, primarily in the Rocky Mountains, the Gulf Coast, the Permian Basin and the Mid-Continent region.

        We are incorporated under the laws of the State of Nevada. Our principal offices are located at 410 Seventeenth Street, Suite 2300, Denver, Colorado 80202. After June 1, 2002, our principal offices will be located at 1670 Broadway, 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 end users, marketers and other purchasers having access to nearby pipeline facilities. 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 2001, our largest purchaser was Dynegy Inc., which accounted for 23% of oil and natural gas sales. There were no other purchasers which accounted for more than 10% of oil and natural gas sales. We do not believe, however, that the loss of any of our purchasers would have a material adverse effect on our operations.

        On November 29, 2001, we terminated our production sales contracts with Enron North America Corp., or ENA, a wholly-owned subsidiary of Enron Corp., and with other Enron affiliates except for an ongoing month-to-month sales arrangement with EOTT Energy Partners, L.P., a publicly traded entity owned in part by Enron Corp. EOTT currently supports its payment obligations to us by posting letters of credit. We continue to monitor EOTT's credit condition closely and will take appropriate action should it deteriorate. We believe that our exposure to potential loss for payment on production delivered to Enron affiliates is less than $1.0 million.

        We periodically enter into commodity derivative contracts (swaps and collars) 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 Operations" for a description of our hedging activities, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information concerning the impact to revenues during 2001, 2000 and 1999 from our commodity derivative activities and our open derivative positions at December 31, 2001 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 commodity products 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 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 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.

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 (i) removes price caps on short-term (i.e., less than 12 months in duration) capacity release transactions through September 30, 2002; (ii) authorizes pipelines to implement peak and off-peak rates for short-term services and term-differentiated rates; (iii) requires pipelines to offer enhanced imbalance management services and to implement netting and trading of transportation imbalances; (iv) limits the use of pipeline penalties; and (v) 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 have challenged certain aspects of Order No. 637 on judicial review, now pending before the U.S. Court of Appeals for the District of Columbia Circuit. We anticipate that all or most aspects of Order No. 637 will be upheld on judicial review, but even if they are not, it is not likely that judicial review of Order No. 637 will have a material effect on our business.

        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 gas pipelines operating on the OCS that are not subject to regulation under the NGA. The stated purpose of these reporting requirements is to provide transparency for shippers on OCS 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 FERC and certain producer/shipper interests have now appealed to the U.S. Court of Appeals for the D.C. Circuit. If it is ultimately determined on judicial review that the FERC does not have authority to implement reporting requirements for OCS pipelines, it will be difficult for producers on the OCS to enforce the nondiscrimination requirement in the statute, thus raising the possibility of increased discriminatory conduct by OCS gas pipelines.

        Commencing in May 1994, the FERC issued a series of orders that, among other matters, slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not have pervasive jurisdiction over natural gas gathering facilities and services, and that such facilities and services located in state jurisdictions are most properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. We do not believe that we will be affected by the FERC's new gathering policy any differently than other natural gas producers, gatherers and marketers.

        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 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 is now pending before the U.S. Court of Appeals for the D.C. Circuit. The outcome in that case, in which a decision is expected in the spring of 2002, could have a significant impact on jurisdictional classification of OCS pipelines.

        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, Westport could face higher transmission costs for its OCS natural gas production and, possibly, reduced access to OCS transmission capacity. Upon the successful development of 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, Westport's 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 operations or business.

        Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the Federal Energy Regulatory Commission and the courts. The natural gas industry historically has been very 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 Leases.  A substantial portion of our operations is 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 to the Mineral Lands Leasing Act, OCSLA and other Federal statutes (which are subject to interpretation and change by the agencies charged with their administration).

        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 restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. 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.

        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 where 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, Coast Guard, and 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 1997, the MMS 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 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. These requirements could substantially increase our current bonding liabilities, and could also impact our residual liabilities, both with respect to existing leases acquired from third parties and with respect to leases that it may acquire or dispose of in the future.

        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. The new rules retained the concept of gross proceeds for calculating royalties on production sold to third parties in arm's-length transactions. However, oil sold in non-arm's-length contracts is to be valued using index pricing method 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 could cause certain sales by us to be impacted and could in some cases require that we pay royalty on a deemed value higher than that which we actually receive for our oil. The new regulations have been challenged judicially.

        In a series of regulations and rulings, 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 recent rule has disallowed the deductibility of certain transportation costs from the calculation of royalty on 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 have been challenged judicially, that challenge was recently rejected in large part. The impact of these regulations and rulings could be to increase our costs of marketing production from Federal leases and in effect impose royalty obligations on certain downstream sale transactions.

        The MMS has also previously proposed gas valuation rules similar to those described above for oil royalty valuation, i.e., rules which 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, and it is not known whether the MMS intends to reissue them. The potential effect of such rules, as with the revised oil royalty valuation rules, is 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. Although we do not have marketing affiliates and do not currently market our production in exchanges or other transactions that appear to be the target of these regulatory proposals, we cannot predict how the final form of any of these rules could impact our royalty obligations.

        State 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 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.

        Also in recent years, pressure has increased in states in which we have been active to increase regulation of the oil and 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 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, the conduct of our drilling activities.

        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 Federal Energy Regulatory Commission 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 the non-compliance with environmental permits required at our facilities. Public interest in the protection of the environment has increased dramatically in recent years. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted. 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 and 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 environmental liabilities have been identified, such liabilities are not material or we have negotiated agreements requiring the sellers of the properties to undertake the required clean-up. We have assumed responsibility for some of these matters identified. Environmental assessments have not been performed 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 hazardous substance contamination. Liability may be imposed on a current owner or operator without regard to fault and for the entire cost of the cleanup. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. However, we are not aware of any current claims under the Superfund law or similar state statutes against us.

        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 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 navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in 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 recently enacted 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. Costs may be associated with the treatment of wastewater or developing and implementing 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, 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, the Migratory Bird Treaty Act, and the National Historic Preservation Act.

        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.

        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.

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. For some risks, we may elect not to obtain insurance 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 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 gas industry. Our producing properties are subject to a negative pledge in connection with our 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 gas properties, pro rata to our working interest. As reflected in our December 31, 2001 reserve report, our total estimated undiscounted future abandonment costs net of salvage value for properties in Federal waters in the Gulf of Mexico were approximately $24.6 million. For onshore properties, salvage values received for equipment are usually sufficient to offset abandonment costs. 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. No significant abandonment costs are anticipated to be incurred in 2002. Estimated future abandonment costs are added to net unamortized historical oil and gas property costs for purposes of computing depreciation, depletion and amortization expense charges.

Employees

        At December 31, 2001, we had 280 full-time employees. At April 1, 2002, following terminations associated with the Merger, we expect to have 260 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.

Risk Factors

        In addition to the other information included in this report, the following risk factors should be considered in evaluating our business and future prospects. The risk factors described below are not necessarily exhaustive and you are encouraged to perform your own investigation with respect to us and our business. You should also read the other information included in this report, including our financial statements and the related notes.

    Oil and natural gas prices fluctuate widely, and low prices could harm our business.

        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, 2001 were $21.69/bbl and $3.59/Mcf, respectively, with production totaling 88.1 Bcfe and combined oil and natural gas sales of $317.3 million during this period. In contrast, our average sales prices for oil and natural gas for the year ended December 31, 2000 were $27.98/bbl and $4.21/Mcf, with production totaling 55.8 Bcfe and combined oil and natural gas sales of $244.7 million during this period. 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;



•

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. For example, the decline in oil and natural gas prices over the past year has impacted our cash flow and could adversely impact our borrowing base and liquidity in general. If the oil and natural gas industry continues to experience significant future price decreases or other adverse market conditions, we may not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures.

    We will require substantial capital to fund our operations.

        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 leverage and debt service obligations may adversely affect our cash flow and our ability to make payments on our long-term debt.

        As of December 31, 2001, we had total debt of $429.2 million and stockholders' equity of $920.3 million. 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. We cannot be certain that our earnings will be sufficient 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. Further, failing to comply with the financial and other restrictive covenants in our debt instruments could result in an event of default under such instruments, which could adversely affect our business, financial condition and results of operations.

    In light of our current indebtedness, we may be able to incur substantially more debt. This could exacerbate the risks described above.

        Together with our subsidiaries, we may be able to incur substantially more debt in the future. Although the agreements governing the terms of our debt impose restrictions on our incurrence of additional indebtedness, these restrictions 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, 2001, we had approximately $361.2 million of additional borrowing capacity under our existing 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.

    Any failure to meet our debt obligations could harm our business, financial condition and results of operations.

        If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. 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. Our cash flow and capital resources may be insufficient for payment of interest on and/or principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.

    We may not realize the benefits of integrating the operations, systems and personnel of Old Westport and Belco or be successful in managing our combined company.

        The Merger of Old Westport with and into Belco on August 21, 2001 approximately doubled the size of our company. To be successful following this business combination, we will need to integrate the operations, financial, technological and management systems, controls and personnel of the two companies. The integration process has required and will continue to require the time of our management and other personnel, which may distract their attention from day-to-day business, the development or acquisition of new properties and the pursuit of other business opportunities. We may encounter difficulties in the integration process and in the ongoing management of the combined business, such as the loss of key employees, customers or suppliers. In addition, our efforts to integrate these businesses could be affected by factors beyond our control, such as regulatory developments, general economic conditions and increased competition. We also expect to incur additional costs related to the Merger. Unless management is successful in integrating and managing on a going- forward basis the resources of the combined company in a cost-efficient manner, we will not realize the benefits sought from the Merger. We may not be able to successfully integrate the operations of Old Westport and Belco, or successfully manage the combined company, and the failure to do so could harm our business, profitability and growth prospects.

    We may not be able to consummate future acquisitions or successfully integrate acquisitions into our business.

        Our business strategy includes 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, contingent liabilities and amortization expenses related to intangible assets, all of which could have a material adverse effect on our financial condition and operating results.

    Repercussions from the recent terrorist acts committed in the United States could harm our business.

        On September 11, 2001, terrorists destroyed the World Trade Center in New York, New York and substantially damaged the Pentagon in Arlington, Virginia. The nature of the repercussions from these incidents and the effect they will have on us and our industry are unknown, cannot be predicted and are beyond our control, but could harm our business. For example, current U.S. military action in Afghanistan, future armed conflict relating to U.S. anti-terrorist efforts, civil unrest, additional terrorist activities and the attendant political instability and societal disruption may prevent us from meeting our financial or other obligations. Additionally, if the adverse effect on the United States and global economies resulting from the terrorist attacks, military activity or related events persist, overall demand for oil and natural gas may be reduced, which could result in downward pressure on prevailing oil and natural gas prices and a reduction in our revenues. Costs for insurance and other security may increase, and some insurance protection may be unavailable or more difficult to obtain. Natural gas and oil production facilities, transportation systems and storage facilities could be targets of terrorist attacks. These attacks could have a material adverse impact on our operations if certain natural gas and oil infrastructures integral to our operations are destroyed or damaged.

    Belco's recent pre-Merger commodity price risk management activities have resulted in losses. These and other commodity price risk management arrangements may limit our potential gains.

        In 1999 and 2000 Belco recorded non-hedge commodity price risk management losses. These losses consisted of cash settlements and unrealized non-cash mark-to-market losses due to substantial increases in commodity prices for 1999 and 2000.

        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 losses from these activities in 2002. 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 counterparties in the event that payment obligations with respect to commodity price risk management transactions exceed certain levels. As of December 31, 2001, we had no letters of credit outstanding for this purpose.

        In order to manage our exposure to price volatility in marketing our oil and natural gas, we may enter into oil and natural gas price risk management arrangements for a portion of our expected production. While intended to reduce the effects of volatile oil and natural gas prices, commodity price risk management transactions may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the arrangements, as was the case with a significant portion of the Belco hedges described above. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

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 the hedge arrangement; or



•

the counterparties to our contracts fail to perform under terms of the contracts.

    Our commodity price risk management and production sales transactions with Enron North America Corp. and its affiliates may expose us to certain financial losses.

        Prior to the Merger, Belco entered into a substantial portion of its natural gas and crude oil commodity swap agreements and option agreements with Enron North America Corp., or ENA, formerly known as Enron Capital & Trade Resources Corp., a wholly owned subsidiary of Enron Corp. Mr. Robert A. Belfer, one of our directors, is a member of the Board of Directors of Enron Corp. and was the CEO of Belco at the time these transactions were entered into. These agreements were entered into in the ordinary course of Belco's business. Old Westport also entered into commodity price risk management agreements with ENA prior to the Merger. Pursuant to the terms of these agreements Belco paid ENA a net amount of approximately $32 million in fiscal year 2000 and approximately $45 million in 2001. Old Westport and Westport received a net amount of $1.6 million in 2001 from ENA.

        On November 29, 2001, we terminated our commodity derivative contracts with ENA. We exercised our rights pursuant to the early termination provisions of such contracts as a result of ENA's bankruptcy filing and related events. We believe that we had the legal right to terminate these agreements, but ENA may challenge our termination in bankruptcy court. Applying the mark-to-market and setoff methodology of our contracts with ENA, we have calculated that we owed ENA a net amount of $204,000 for all derivative transactions that were outstanding under our ENA contracts. Although we believe this methodology was correct, it is possible that ENA will challenge our calculations and claim larger amounts are owed.

        We have also terminated our production sales contracts with ENA and its affiliates, except for an ongoing month-to-month sales arrangement with EOTT Energy Partners, L.P., a publicly traded entity owned in part by Enron Corp. EOTT currently supports its payment obligations to us by posting letters of credit. We continue to monitor EOTT's credit condition closely and will take appropriate action should it deteriorate. We believe that our exposure to potential loss for payment on production delivered to Enron affiliates is less than $1.0 million.

    Exploration is a high-risk activity. The seismic data and other advanced technologies we use are expensive and cannot eliminate exploration risks.

        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, there is no assurance that such oil and natural gas can be economically produced or satisfactorily marketed. There can be no assurance that new wells we drill will be productive or that we will 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 conditions, title problems, weather conditions, compliance with environmental and other governmental requirements and shortages or delays in the delivery of equipment and services.

        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.

    Failure to replace reserves may negatively affect our business.

        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, while our revenues may increase if oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

    Reserve estimates are inherently uncertain. Any material inaccuracies in our reserve estimates or assumptions underlying our reserve estimates, such as the discount rate used, could cause the quantities and net present value of our reserves to be overstated.

        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 set forth 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;



•

assumptions regarding future operating costs;



•

estimates of future severance and excise taxes;



•

assumptions regarding capital expenditures; and



•

estimates regarding 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 United States Securities and Exchange Commission, or 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.

    Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we have.

        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 advancements and introductions of new products and services using new technologies. We face intense competition from major and independent oil and natural gas companies in each of the following areas:

•

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.

    We are subject to complex laws and regulations, including environmental and safety regulations, that can adversely affect the cost, manner or feasibility of doing business.

        Our operations and facilities are subject to certain Federal, state 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. Although we believe that we are in substantial compliance with all applicable laws and regulations, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not 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;



•

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.

        We could also experience significant delays in operations on our properties, inability to develop particular properties, or significantly increased costs of operations 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.

    We cannot control activities on properties we do not operate. Inability to fund our capital expenditures may result in reduction or forfeiture of our interests in some of our non-operated projects.

        Other companies operate approximately 30% 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 not willing 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 business involves many operating risks that may result in substantial losses. Insurance may be unavailable or inadequate to protect us against these risks.

        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;



•

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.

    We are vulnerable to risks associated with operating in the Gulf of Mexico.

        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 intend to conduct 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.

    We depend upon our management team and our operations require us to attract and retain experienced technical personnel.

        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 members of our management team could have an adverse effect on our business. 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.

    The marketability of our production depends upon factors over which we may have no control.

        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 own a significant amount of our common stock, giving them a controlling influence over corporate transactions and other matters.

        Our principal stockholders, including Westport Energy LLC, ERI Investments, Inc., an affiliate of Equitable Resources Corp., and the Belfer Group, a group of former Belco stockholders, together beneficially own approximately 68.4% of our outstanding common stock. Accordingly, these stockholders, acting together through a shareholders agreement, based on their current share ownership, are able to control the outcome of the election of directors as well as, if they choose to act together, the adoption or amendment of provisions in our articles of incorporation or bylaws and the approval of mergers and other significant corporate transactions. These factors may also delay or prevent a change in our management or voting control.

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:

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

        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 or in close proximity to an area of known production targeting existing reservoirs.

        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 either in search of a new and as yet undiscovered accumulation of oil or natural gas, or with the intent to greatly extend the limits of a pool already partly developed.

        Gross Acres.  The total acres in which we have a working interest.

        Gross Producing Wells.  The total number of producing wells in which we own any amount of 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.

        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.

        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.

        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.  Gross acres multiplied by the percentage working interest owned by us.

        Net Present Value.  The present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated lease operating expense, production taxes 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, or Federal income taxes and discounted using an annual discount rate of 10%.

        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.

        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.

        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 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.

        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.

        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.

        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.

ITEM 2. PROPERTIES

Properties — Principal Areas of Operations

        Our operations are concentrated in the following divisions: Northern, which includes properties in the Rocky Mountains, principally in North Dakota and Wyoming; Southern, which includes properties principally in Oklahoma, Texas and Louisiana; and Gulf of Mexico, which includes our offshore properties. We operate approximately 70% 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 credit agreement and other financing activities. Set forth below is summary information concerning average daily production during the fourth quarter of 2001 and estimated reserves and a pre-tax SEC net present value of estimated proved reserves discounted at 10%, as of December 31, 2001 in our divisions.

    Northern Division

        The Northern Division conducts operations in the Rocky Mountain region which includes the Williston, Powder River, Big Horn and Green River Basins. The Division represented 25% of our net present value of estimated proved reserves as of December 31, 2001 and contributed 28% of our fourth quarter 2001 production. We have interests in 731,788 developed and 1,419,208 undeveloped gross acres in the region and in 1,862 gross (approximately 522 net) producing wells.

        Our strategy in the Northern Division is to develop lower-risk opportunities, exploit infill, horizontal and secondary/tertiary recovery opportunities on existing properties and make tactical acquisitions to enhance current operations.

        On March 1, 2002 we completed the purchase of producing oil and gas properties located in the Williston Basin in North Dakota and Montana for approximately $38.7 million. We estimate the total proved reserves for these properties as of December 31, 2001 to be approximately 53.1 Bcfe, of which approximately 90% is oil. The reserves are not included in the table above and these estimates have not been audited by our independent petroleum engineering firm. We will operate over 70% of these properties, which have an average lifting cost of $0.51 per Mcfe. We estimate that net production from these properties will average approximately 13.9 Mmcfe/d in 2002.

        North Dakota. Our two most active projects in North Dakota are in the South Fryburg Tyler area and the Wiley field.

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South Fryburg Tyler Area.  The South Fryburg Tyler area continues to be one of our most active drilling programs. We continue development within the South Fryburg Tyler Unit, where we are the operator. We are also involved in exploration and development drilling in the Mission Canyon formation on a contiguous acreage block southeast of the Unit. Within the South Fryburg Tyler Unit, we expanded the Tyler sand production with development drilling in 2001. On our acreage block adjoining the Unit to the southeast, where we own over 76,000 gross acres, our drilling program targets zones within the Mission Canyon formation. We have participated in 26 horizontal wells on this acreage, 19 of which were drilled in 2001. The 26 wells had initial production rates of approximately 190 bbl/d. In 2002, we expect to participate in an additional 4 to 8 wells on this block.



•

Wiley Field.  We operate this waterflood with a 54% working interest. In 2000, we initiated a horizontal drilling program with five wells and in 2001 drilled 17 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, gross daily production has increased from approximately 600 bbl/d in April 2000 to over 2,400 bbl/d at the end of 2001. Over the next 12 months, we plan to drill 10 to 15 additional wells in this area while continuing to increase water injection capacity.

        Wyoming. Our three primary areas of focus in Wyoming are the Big Horn Basin, the Powder River Basin and the Greater Green River area. The Merger added in excess of 1.1 million gross acres of exploratory acreage in the Big Horn, Wind River and Greater Green River gas basins of Wyoming. We plan to drill 15 to 20 exploration wells in these areas over the next 12 to 24 months. The wells will target multiple formations and successful projects hold the potential for multi-well development programs.

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Big Horn Basin.  The Gooseberry field is our most significant property in the 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 more than doubled the production from approximately 535 bbl/d to over 1,100 bbl/d in December 2001. This has been accomplished through the acquisition of proprietary 3-D seismic data, drilling of delineation wells, installation of the two waterfloods and the addition of shallower producing zones. During the next 12 months, we plan to drill from two to three additional wells and to expand water injection capacity. In January 2002 we placed a larger pipeline in service to accommodate the increasing production from the unit.



•

Powder River Basin.  We currently own more than 27,000 net undeveloped acres in the Powder River Basin, which we believe are prospective for coalbed methane drilling. In 2000 and 2001, we participated in the drilling of 178 wells, all of which were successful. We operate 84 of these wells. In 2002, we expect to participate in another 130 to 160 wells.



•

Greater Green River Area.  One of the primary operating locations within the Greater Green River area is the Moxa Arch Trend, where we drilled 16 wells in 2001, 14 of which were successful. This area represents a multi-year program where we have identified more than 100 potential drilling locations on our acreage. Wells target the Frontier and Dakota formations at depths that range from approximately 10,000 to 12,500 feet. Production from Moxa Arch wells,

particularly from the Frontier formation, tends to be long-lived, with 25 to 30 year reserve life potential.

    Southern Division

        The Southern Division conducts operations in the Permian Basin, Mid-Continent and onshore Gulf Coast regions. This division represented 43% of the net present value of our estimated proved reserves as of December 31, 2001 and contributed 41% of our fourth quarter 2001 production. We have interests in 578,252 developed and 165,939 undeveloped gross acres and in 3,900 gross (approximately 1,603 net) producing wells.

        Permian Basin. The Southern Division's principal Permian Basin properties are the Andrews Unit, Howard Glasscock Field and the Shafter Lake San Andres Unit.

•

Andrews Unit.  The Andrews Unit, acquired as part of the Merger, produces from the Wolfcamp/Penn formation at approximately 8,600 feet. We have a 98.6% working interest in this 3,230-acre Unit. Water injection began in late 1996 with the first response occurring in late 1998. During 2000 and 2001, we expanded the waterflood program by drilling additional wells, converting wells to injection, and performing workovers on existing wells. As a result, Unit production continues to increase from an 855 bbl/d average in 2000 to 911 bbl/d average in 2001. We plan to drill two wells and convert two wells to injectors in 2002. We believe that production from this waterflood Unit can be further enhanced with the use of CO₂ flooding or other tertiary recovery methods.



•

Howard Glasscock Field.  We continue to exploit our 100% working interest in the Howard Glasscock Field. Based on the results from adjacent successful waterfloods, we believe that additional potential exists through the installation of new and expansion of existing waterfloods on our leases. In May 2001, we initiated a drilling program for 27 injection and development wells to expand waterfloods on two of our leases. Water injection commenced in first quarter 2002. Additionally, we have identified a number of opportunities for recompletion and well deepenings.



•

Shafter Lake San Andres Unit.  The Shafter Lake San Andres Unit, also acquired as part of the Merger, 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 2002, we plan to drill eight wells on 10-acre spacing. Operators of nearby San Andres fields have successfully drilled to 10-acre spacing before CO₂ injection. We believe the potential exists for CO₂ flooding as the field matures.

        Mid-Continent. The Southern Division's 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 in third party operated wells in Oklahoma and in our operated wells in Kansas. The most significant waterflood unit in Oklahoma is the Calumet Cottage Grove Unit, which we acquired as part of the Merger. We operate this secondary recovery Unit consisting of 11,400 acres in central Oklahoma. Production is from the Pennsylvanian Cottage Grove formation at 8,100 feet. We have a 44.1% working interest in this Unit. In 2001, a total of seven wells were drilled, all of which were successful and six of which were drilled prior to the Merger. We plan to drill four to six additional wells in 2002.

        Onshore Gulf Coast. The Southern Division's Gulf Coast operations are primarily focused in the Austin Chalk/Georgetown trend of east-central Texas and in Northern Louisiana where we are active in two fields, the Elm Grove Field and the North Louisiana Field Complex.

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Austin Chalk/Georgetown Trend.  The trend is a fractured carbonate formation that has been highly conducive to the application of horizontal drilling technology. The Austin Chalk formation

is encountered in this field at depths ranging between approximately 7,000 and 17,000 feet. The Georgetown formation, approximately 300 to 500 feet below the base of the Austin Chalk, has been a secondary objective in the field. We control approximately 50,000 gross (13,000 net) undeveloped acres and 114,000 gross (43,000 net) developed acres in this area. In 2001, we participated in the drilling of five Georgetown wells prior to the Merger and one Austin Chalk well after the Merger. All were successful. In 2002 we plan to re-enter six wells to drill Georgetown horizontal sections.

•

Elm Grove Field.  This field was drilled to extend the Cotton Valley production downdip from the mature Caspiana field. In addition to the Cotton Valley, shallower secondary objectives include the Hosston and Rodessa intervals. Through the Merger we acquired an approximately 37% non-operating working interest in the field. In 2001 a total of 42 wells were drilled, 17 of which were drilled after the Merger. All of the wells were successful. Gross production in the field has increased from 34 Mmcfe/d in January 2001 to 54 Mmcfe/d in December 2001. In 2002, we plan to drill 25 to 30 wells.



•

North Louisiana Field Complex.  We acquired this interest in late 1998 and have identified over 100 development locations in its four fields—Ada, Sibley, West Bryceland and Sailes. The 2,000 foot thick Hosston interval contains over 20 separate producing zones. In 2001, we drilled 34 wells, all of which were successful. We anticipate drilling between 35 and 45 wells in this region in each of the next two years.

    Gulf of Mexico Division

        The Gulf of Mexico Division represented 32% of the net present value of our estimated proved reserves as of December 31, 2001 and contributed 31% of our fourth quarter 2001 production. We have interests in 303,804 developed and 357,059 undeveloped gross acres in the Gulf of Mexico and in 158 gross (approximately 47 net) producing wells.

        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 16 exploratory wells in the Gulf of Mexico in 2001, 11 of which were successful. We have under license 3-D seismic data covering over 18,000 square miles (approximately 2,300 blocks) and 2-D seismic data covering 150,000 linear miles within the Gulf of Mexico.

        West Cameron Blocks 180/198. The West Cameron Blocks 180/198 complex consists of all or a portion of seven offshore blocks, including 30,000 gross developed and 5,000 gross undeveloped acres. This field was never owned by an independent producer prior to its purchase by Old Westport in October 1997. The complex is located 30 miles offshore in 52 feet of water. It has produced approximately 1.7 Tcf of natural gas and 10 Mmbbl of oil from over 20 separate producing zones since its discovery. Since acquiring this field, we have increased gross production from approximately 26 Mmcfe/d to 63 Mmcfe/d at year-end 2001. At the time of the acquisition, estimated proved reserves net to our interest were 77 Bcfe. As of December 31, 2001, we had 84 Bcfe of estimated proved reserves in the complex.

        In the first quarter of 2001, we commenced production on three development wells drilled in 2000, and in the third quarter of 2001 we commenced production on three development wells drilled in the first half of 2001. We also drilled a successful exploration well in the complex in 2001. The complex holds additional drilling opportunities.

        West Cameron Blocks 613/614. In 1999, we discovered this field, located approximately 120 miles offshore in 290 feet of water. We drilled a second exploration well on an adjoining block in the third quarter of 2000. We operate the field with a working interest of 50% and installed facilities and commenced production in December 2000. At year-end, the wells were producing at 22 Mmcfe/d (9 Mmcfe/d net).

        West Cameron Block 370. We discovered this field, located approximately 60 miles offshore in 78 feet of water, in the fourth quarter of 2000. We operate the field with a 60% working interest. Following the discovery well we drilled three additional wells, installed a platform and commenced production in the third quarter of 2001. At year-end, the wells were producing at 30 Mmcfe/d (15 Mmcfe/d net).

        East Cameron Block 369. We discovered this field in the first quarter of 2001 and commenced production from it in December 2001. It is located approximately 132 miles offshore in 350 feet of water. We operate the two-well field with a 60% working interest. At year-end, the wells were producing at 20 Mmcfe/d (10 Mmcfe/d net).

        Vermilion Block 408. This field is located approximately 110 miles offshore in 400 feet of water and was discovered in 1999. We have a 25% non-operated working interest in the field. A second well was drilled in this block in the third quarter of 2000. A third well was in progress at year end 2001. Facilities were installed in late 2001 and production commenced in the first quarter of 2002.

        Mississippi Canyon Block 322. This field is located approximately 35 miles offshore in 750 feet of water and was discovered in the second quarter of 2001. We own a non-operated 25% working interest in the field. A second well was also drilled. Both wells have been completed and production commenced in the first quarter of 2002.

        Recent Discoveries. In 2002, we will continue to exploit the following discoveries in the Gulf of Mexico:

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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. A second well was in progress at year end 2001. In the first quarter of 2002, we farmed into an adjoining block and an exploratory well is currently drilling. We expect a platform to be installed and production to be commenced in the second half of 2002.



•

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 operate the field with a 52% working interest. We plan to install a platform and commence production in the third quarter of 2002.



•

South Timbalier 316.  We discovered this field located approximately 66 miles offshore in 300 feet of water, in the fourth quarter of 2001. We operate the field with a 40% working interest. Three wells have been drilled. We expect to install a platform and commence production in the second half of 2003.

        Other Exploration Activity. During 2002, we anticipate drilling eight to eleven exploration prospects.

Proved Reserves

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

(1)

The difference in net present value from December 31, 2000 to December 31, 2001 resulted almost entirely from (i) the addition of 502.7 Bcfe of proved reserves acquired in connection with the Merger, (ii) the addition of 92 Bcfe as discoveries and extensions, (iii) the downward revision of 33 Bcfe due to revisions of previous estimates and (iv) the decrease in commodity prices used to determine net present value (from $26.83 to $19.78 per bbl of oil and from $9.52 to $2.72 per Mmbtu of natural gas).

(2)

The difference in net present value from December 31, 1999 to December 31, 2000 resulted almost entirely from (i) the addition of 134 Bcfe of proved reserves acquired in connection with the merger between Westport Oil and Gas and EPGC, (ii) the addition of 52 Bcfe as discoveries and extensions and (iii) the increase in commodity prices used to determine net present value (from $25.60 to $26.83 per bbl of oil and from $2.30 to $9.52 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%.

        Estimated quantities of oil and natural gas reserves and the present value thereof as of December 31, 2001 are based upon a reserve report prepared by the Company's engineering staff, 87% of the net present value of which was audited by the independent petroleum engineering firm of Ryder Scott Company, L.P. Estimated quantities of oil and natural gas reserves and the present value thereof as of December 31, 2000 are based upon reserve reports prepared by the independent petroleum engineering firms of Ryder Scott Company, L.P., Netherland Sewell and Associates, Inc. and internal estimates. The Ryder Scott and Netherland Sewell reports covered approximately 85% of the net present value of the reserves and the net present value thereof.

        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 tables represent 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 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, 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 exclude our share of overhead charges. 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.

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:

(1)

Production of natural gas liquids was not meaningful for 1999.

(2)

Does not include the effects of hedging transactions.

Producing Wells

        The following table sets forth information at December 31, 2001 relating to the producing wells in which we owned a working interest as of that date. We also held royalty interests in 1,726 producing wells as of that date. Wells are classified as oil or natural gas wells according to their predominant production stream.

Acreage

        The following table sets forth information at December 31, 2001 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.

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 produce a reasonable rate of return.

        As of December 31, 2001, four additional exploration and seven development wells were in progress.

ITEM 3. LEGAL PROCEEDINGS

        From time to time, we may be a party to various legal proceedings. We are not currently party to any material pending legal proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        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.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

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 the Merger, Belco common stock was listed and traded on the NYSE under the symbol "BOG."

        On August 21, 2001, the effective date of the Merger, Old Westport was merged with and into Belco, with Belco surviving and changing its name to Westport Resources Corporation. The Merger was accounted for as a purchase transaction for financial accounting purposes. Because former Old Westport stockholders now own a majority of the outstanding Westport common stock as a result of the Merger, the Merger is accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco.

        The following table sets forth the high and low closing trading prices per share of Old Westport, Belco and Westport common stock on the NYSE, for the periods indicated:

(1)

Stock price information for periods prior to August 21, 2001, the effective date of the Merger, are for shares of Belco common stock listed and traded on the NYSE under the symbol "BOG." August 20, 2001 was the last full trading day on which shares of Belco common stock were traded prior to the Merger.

(2)

Old Westport commenced its initial public offering of common stock on October 19, 2000 at a price of $15.00 per share. Fourth Quarter 2000 data is from October 20, the first day Old Westport's common stock was traded on the NYSE (under the symbol "WRC") through December 31, 2000. August 20, 2001 was the last full trading day on which shares of Old Westport common stock were traded prior to the Merger.

(3)

The Merger became effective on August 21, 2001. In accordance with the agreement governing the Merger, each outstanding share of Belco common stock was exchanged for 0.4125 of a share of Westport common stock and each outstanding share of Old Westport stock was exchanged for one share of Westport common stock.

Price Range of Preferred Stock

        Our 6¹/2% convertible preferred stock is listed on the NYSE under the symbol "WRC_P." Prior to the Merger, Belco 6¹/2% convertible preferred stock was listed and traded on the NYSE under the symbol "BOG_P." The following table sets forth the high and low closing trading prices per share of Belco and Westport 6¹/2% convertible preferred stock on the NYSE, for the periods indicated:

(1)

Stock price information for periods prior to August 21, 2001, the effective date of the Merger, are for shares of Belco 6¹/2% convertible preferred stock listed and traded on the NYSE under the symbol "BOG_P." August 20, 2001 was the last full trading day on which shares of Belco 6¹/2% convertible preferred stock were traded prior to the Merger.

(2)

The Merger became effective on August 21, 2001. In accordance with the agreement governing the Merger, each outstanding share of Belco 6¹/2% convertible preferred stock was exchanged for one share of Westport 6¹/2% convertible preferred stock and became convertible into 0.465795 of a share of Westport common stock.

        As of March 1, 2002, the closing price of our 6¹/2% convertible preferred stock was $19.00 per share, there were 2,930,000 shares of our 6¹/2% convertible preferred stock outstanding, convertible into 1,364,779 shares of our common stock at a rate of 0.465795 per share.

Dividend Policy

        We have never declared or paid any cash dividends on our common stock. We anticipate that we will retain all future earnings and other cash resources for investment in our business. Accordingly, we do not intend to declare or pay cash dividends on our common stock in the foreseeable future. Payment of any future dividends on our common stock will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our ability to declare and pay any dividends on our capital stock, including any outstanding preferred stock, may be limited or prohibited under the terms of our credit facility and the indentures governing our senior subordinated debt obligations.

        Because reported first quarter 2001 net income was insufficient to permit Belco to declare a dividend on its 6¹/2% convertible preferred stock under the terms of Belco's indenture for Belco's 10¹/2% Senior Subordinated Notes due 2006, Belco's board of directors did not declare a preferred dividend for the preferred stock dividend due June 15, 2001. Since the Merger, Westport has declared and paid all required dividends on its 6¹/2% convertible preferred stock, including dividends in arrears.

Recent Sales Of Unregistered Securities

        None.

ITEM 6. SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated financial data for Westport as of the dates and for the periods indicated. The financial data for the five years ended December 31, 2001 were derived from our Consolidated Financial Statements. Future results may differ substantially from historical results because of changes in oil and natural gas prices, increases or decreases in production or other factors, many of which are beyond our control. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," which includes a discussion of factors materially affecting the comparability of the information presented, and our financial statements and the notes thereto included elsewhere in this report.

(1)

Includes compensation expenses of $3.4 million recorded as a result of a one-time repurchase of employee stock options in March 2000 in connection with the merger between Westport Oil and Gas and EPGC.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Critical Accounting Policies And Estimates

        Our discussion and analysis of Westport's financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements. In response to SEC Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements:

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Revenue Recognition. We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers.



•

Successful Efforts Accounting. We account for our oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisition, successful exploratory wells and all development wells are capitalized. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells and oil and natural gas production costs. All of our oil and natural gas properties are located within the continental United States, the Gulf of Mexico and Canada.



•

Proved Reserve Estimates. Estimates of our proved reserves included in this report are prepared in accordance with generally accepted accounting principals, or GAAP, and SEC guidelines. The accuracy of a reserve estimate is a function of:



•

the quality and quantity of available data;



•

the interpretation of that data;



•

the accuracy of various mandated economic assumptions; and



•

the judgment of the persons preparing the estimate.

Our proved reserve information included in this report is based on estimates we prepared. Estimates prepared by others may be higher or lower than our estimates.

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

Our stockholders should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we record depletion expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. In addition, the decline in proved reserve estimates may impact the outcome of our assessment of our oil and gas producing properties for impairment.

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Impairment of Proved Oil and Gas Properties. We review our long-lived proved properties to be held and used whenever management judges that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon management's outlook of future commodity prices and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment on a field-by-field basis, which is the lowest level at which depletion of proved properties is calculated.



•

Impairment of Unproved Oil and Gas Properties. Management periodically assesses individually significant unproved oil and gas properties for impairment, on a project-by-project basis. Management's assessment of the results of exploration activities, commodity price outlooks,

planned future sales or expiration of all or a portion of such projects impact the amount and timing of impairment provisions.

•

Commodity Derivative Instruments and Hedging Activities. We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize price swaps, futures contracts or collars, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices we receive. On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.

Overview

        Westport is an independent energy company engaged in oil and natural gas exploitation, acquisition and exploration activities primarily in the United States. Our reserves and production operations are concentrated in the following diversified divisions: Northern (Rocky Mountains); Southern (Permian Basin, Mid-Continent and Gulf Coast); and Gulf of Mexico (offshore). We focus on maintaining a balanced portfolio of lower-risk, long-life onshore reserves and higher-margin offshore reserves to provide a diversified cash flow foundation for our exploitation, acquisition and exploration activities.

        Our results of operations are significantly impacted by the prices of oil and natural gas, which are volatile. In 2001, oil and natural gas prices decreased compared to prices in 2000. Oil and natural gas prices declined from $9.52 per Mcf and $26.83 per bbl at the beginning of 2001 to $2.72 per Mcf and $19.78 per bbl at December 31, 2001. The prices we receive for our oil vary from NYMEX prices based on the location and quality of the crude oil. The prices we receive for our natural gas are based on Henry Hub prices reduced by transportation and processing fees.

        Oil and natural gas production costs are composed of lease operating expense and production taxes. Lease operating expense consists of pumpers' salaries, utilities, maintenance and other costs necessary to operate our producing properties. In general, lease operating expense per unit of production is lower on our offshore properties and does not fluctuate proportionately with our production. Production taxes are assessed by applicable taxing authorities as a percentage of revenues. However, properties located in Federal waters offshore are generally not subject to production taxes. Transportation costs are comprised of costs paid to a carrier to deliver oil or natural gas to a specified delivery point. In some cases we receive a payment from the purchases of our oil and natural gas which is net of gas transportation costs and in other instances we pay the costs of transportation.

        Exploration expense consists of geological and geophysical costs, delay rentals and the cost of unsuccessful exploratory wells. Delay rentals are typically fixed in nature in the short term. However, other exploration costs are generally discretionary and exploration activity levels are determined by a number of factors, including oil and natural gas prices, availability of funds, quantity and character of investment projects, availability of service providers and competition.

        Depletion of capitalized costs of producing oil and natural gas properties is computed using the units-of-production method based upon proved reserves. For purposes of computing depletion, proved reserves are redetermined twice each year. Because the economic life of each producing well depends upon the assumed price for production, fluctuations in oil and natural gas prices impact the level of proved reserves. Higher prices generally have the effect of increasing reserves, which reduces depletion, while lower prices generally have the effect of decreasing reserves, which increases depletion.

        We assess our proved properties on a field-by-field basis for impairment, in accordance with the provisions of Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long Lived Assets and for Long Lived Assets to be Disposed of," whenever events or circumstances indicate that the capitalized costs of oil and natural gas properties may not be recoverable. When making such assessments, we compare the expected undiscounted future net revenues on a field-by-field basis with the related net capitalized costs at the end of each period. When the net capitalized costs exceed the undiscounted future net revenues, the cost of the property is written down to "fair value," which is determined using discounted future net revenues based on escalated prices. Impairments for the years ended December 31, 2001, 2000 and 1999, were calculated based on the following prices: oil prices per barrel of $20.84, $24.70 and $20.84, respectively; and natural gas prices per Mcf of $2.75, $4.48 and $2.36, respectively. Oil and natural gas prices were both escalated annually at 2.5% in 2000 and 1999. Natural gas prices for 2001 were increased from $2.75 per Mcf in 2002 to $3.05 per Mcf in 2003 and then escalated at 2.5% thereafter. Estimates of declining production were based on internal estimates of which 87% of the net present value was audited by independent reserve engineers and estimated operating costs and severance taxes were based on past experience. Operating and future development costs were escalated annually at 2.5% in 2001, 2000 and 1999. Reserve categories used in the impairment analysis for all periods considered are categories of proven reserves and probable and possible reserves, which were risk adjusted based on our drilling plans and history of successfully developing those types of reserves. We periodically assess our unproved properties to determine if any such properties have been impaired. Such assessment is based on, among other things, the fair value of properties located in the same area as the unproved property and our intent to pursue additional exploration opportunities on such property.

        Stock compensation expense consists of noncash charges resulting from the application of the provisions of FASB Interpretation No. 44 to certain stock options granted to employees, issuance of restricted stock to certain employees and a one time expense related to the repurchase of employee stock options in March 2000.

        General and administrative expenses consist primarily of salaries and related benefits, office rent, legal fees, consultants, systems costs and other administrative costs incurred in our Denver, Dallas and Houston offices. While we expect such costs to increase with our growth, we expect such increases to be proportionately smaller than our production growth.

Mergers

        On August 21, 2001, the stockholders of Belco approved the Agreement and Plan of Merger, dated as of June 8, 2001, between Belco and Westport. Pursuant to the merger agreement, Old Westport was merged with and into Belco, with Belco surviving and changing its name to Westport Resources Corporation. The Merger was accounted for as a purchase transaction for financial accounting purposes. Because former Old Westport stockholders now own a majority of the outstanding Westport common stock as a result of the Merger, the Merger is accounted for as a reverse acquisition in which Old Westport is the purchaser of Belco.

        Old Westport was formed by the merger on April 7, 2000 of Westport Oil and Gas with EPGC. 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.

Results of Operations

        As indicated above, the merger between Belco and Old Westport was accounted for using purchase accounting with Old Westport as the surviving accounting entity. We began consolidating the results of Belco with the results of Old Westport as of the August 21, 2001 closing date. The merger between EPGC and Westport Oil and Gas was accounted for using purchase accounting with Westport Oil and Gas as the surviving accounting entity. Old Westport began consolidating the results of EPGC with the results of Westport Oil and Gas as of the April 7, 2000 closing date.

        The discussion below includes a comparison of our consolidated results of operations for the years ended December 31, 2001, 2000 and 1999.

        Revenues.  Oil and natural gas revenues for 2001 increased by $72.6 million, or 30%, from $244.7 million in 2000 to $317.3 million in 2001. Production from the acquired Belco properties accounted for $49.6 million of the increase. Revenue increased $37.1 million from recent discoveries in the Gulf of Mexico. The increases were partially offset by decreases of 22% and 15% in realized oil and natural gas prices, respectively. Production volumes increased 32.3 Bcfe from 55.8 Bcfe in 2000 to 88.1 Bcfe in 2001 (acquired Belco and EPGC properties accounted for 19.2 Bcfe and 0.7 Bcfe of the increase, respectively). Production volumes also increased 10.7 Bcfe from recent discoveries in the Gulf of Mexico, 0.6 Bcfe from coalbed methane development in the Powder River Basin area, 0.8 Bcfe from the horizontal drilling program in the Wiley field, and 0.6 Bcfe from the acquired interest in the Ward Estes field in August 2000. Increases were partially offset by declines in existing properties. Hedging transactions had the effect of increasing oil and natural gas revenues by $2.1 million in 2001, or $0.2 per Mcfe, and reducing oil and natural gas revenues by $24.6 million in 2000, or $0.44 per Mcfe.

        Oil and natural gas revenues for 2000 increased by $161.3 million, or 193%, from $83.4 million in 1999 to $244.7 million in 2000. Production from the acquired EPGC properties accounted for $95.3 million of the increase and the remaining increase resulted from increases of 70% and 92% in realized oil and natural gas prices, respectively. The increase of 22,709 Mmcfe in production volumes from 33,113 Mmcfe in 1999 to 55,822 Mmcfe in 2000 was primarily due to 21,260 Mmcfe from the acquired EPGC properties. Hedging transactions had the effect of reducing oil and natural gas revenues by $24.6 million and $7.9 million, or $0.44 and $0.24 per Mcfe, for the years ended December 31, 2000 and 1999, respectively.

        Commodity Price Risk Management Activities, or CPRM, Activities.  For 2001, we recorded a net gain of $14.3 million in the non-hedge change in fair value of derivatives compared to a net loss of $0.7 million for 2000. A net gain of $15.3 million was recorded in 2001 for non-hedge settlements of derivatives. The net gains in 2001 and the net loss in 2000 relate to settlements of derivatives and changes in fair value on derivatives that under SFAS No. 133 do not qualify for hedge accounting. Westport Oil and Gas did not have any derivatives that qualified for hedge accounting for 1999.

        Gain (Loss) on Sale of Operating Assets.  For 2001, we recorded a loss on sale of operating assets of $0.1 million compared to gains of $3.1 million in 2000 and $3.6 million in 1999 primarily from the sale of offshore properties.

        Lease Operating Expense.  Lease operating expense for 2001 increased by $20.9 million, or 61%, from $34.4 million in 2000 to $55.3 million in 2001. Lease operating expenses from the acquired EPGC properties and Belco properties accounted for $1.3 million and $11.4 million, respectively, of the increase. Recent discoveries in the Gulf of Mexico, an increased level of workovers in several of our properties and a general increase in the cost of oil field services and materials accounted for the remainder. On a per Mcfe basis, lease operating expense remained relatively constant at $0.62 in 2000 and $0.63 in 2001.

        Lease operating expense for 2000 increased by $11.5 million, or 50%, from $22.9 million in 1999 to $34.4 million in 2000. Lease operating expenses from the acquired EPGC properties accounted for $6.5 million of the increase. On a per Mcfe basis, lease operating expense decreased from $0.69 to $0.62, primarily due to the lower lease operating expense associated with the acquired EPGC properties.

        Production Taxes.  Production taxes for 2001 increased by $2.8 million, or 26%, from $10.6 million in 2000 to $13.4 million, in 2001. Acquired Belco properties accounted for $3.7 million of the increase in production taxes. The increase from the acquired Belco properties is partially offset by a decrease in revenue from onshore properties as a result of a decrease in realized oil and natural gas prices. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes remained relatively constant at 4.3% in 2000 and 4.2% in 2001.

        Production taxes for 2000 increased by $4.9 million, or 85%, from $5.7 million in 1999 to $10.6 million in 2000. The increase in production taxes is primarily attributable to an increase in the average realized price of oil and natural gas. As a percent of oil and natural gas revenues (excluding the effects of hedges), production taxes decreased from 6.9% to 4.3%. The decrease in production taxes as a percent of revenue is primarily the result of the EPGC merger, which increased the number of offshore properties that are not subject to production taxes.

        Transportation Costs.  Transportation costs for 2001 increased by $2.2 million, or 70%, from $3.0 million in 2000 to $5.2 million in 2001. The increase was primarily due to additional offshore and coalbed methane wells that started producing in the latter part of 2000 and early 2001, which incur higher costs to transport the natural gas.

        Transportation costs for 2000 increased by $1.3 million, or 76%, from $1.7 million in 1999 to $3.0 million in 2000. Transportation costs from the acquired EPGC properties accounted for $0.4 million of the increase. The remaining increase was due to additional offshore natural gas wells and coalbed methane wells that started producing in 2000.

        Exploration Costs.  Exploration costs for 2001 increased by $18.5 million, or 145%, from $12.8 million in 2000 to $31.3 million in 2001. Dry hole costs increased $13.1 million as a result of six unsuccessful exploratory wells drilled in the Gulf of Mexico during 2001. For 2000 there were five unsuccessful exploratory offshore wells and three unsuccessful exploratory onshore wells. Purchases of Gulf of Mexico seismic data increased $4.8 million during 2001 compared to 2000. Exploration costs increased $0.6 million from the acquired Belco properties.

        Exploration costs for 2000 increased by $5.5 million, or 75%, from $7.3 million in 1999 to $12.8 million in 2000. Exploration costs consisted of $6.0 million of dry hole costs, $5.6 million of geological and geophysical costs and $1.2 million of delay rentals. The increase was primarily due to $4.0 million in additional dry hole costs as a result of five unsuccessful offshore exploratory wells and three unsuccessful onshore exploratory wells drilled during 2000. Geological and geophysical costs increased $1.0 million due to increased offshore activity in 2000. Delay rentals accounted for $0.5 million of the increase as a result of acquiring offshore leases in the EPGC merger.

        Depletion, Depreciation and Amortization, or DD&A, Expense.  DD&A expense increased $59.2 million in 2001, from $64.9 million in 2000 to $124.1 million in 2001. Depletion related to the acquired EPGC properties and Belco properties caused DD&A expense to increase $6.4 million and $31.7 million, respectively. Recent discoveries in the Gulf of Mexico caused DD&A expense to increase $14.8 million. An increase of $2.1 million was primarily due to additions in oil and natural gas properties in northern Louisiana in 2001. The remaining increase was primarily due to the additions of oil and natural gas properties during 2001. These increases were the primary factors that caused DD&A expense to increase on a per Mcfe basis from $1.16 in 2000 to $1.41 in 2001.

        DD&A expense increased $39.7 million during 2000 from $25.2 million in 2000 to $64.9 million in 2001. Depletion related to the acquired EPGC properties caused DD&A expense to increase $36.8 million. The remaining increase was due to the additions in oil and natural gas properties during 2000. The average DD&A rate increased from $0.76 per Mcfe during 1999 to $1.16 per Mcfe during 2000, a 53% increase in the DD&A rates primarily due to the acquired offshore EPGC properties.

        Impairment of Proved Properties.  During 2001, 2000 and 1999, we recognized proved property impairments of $9.4 million, $2.9 million and $3.1 million, respectively. Impairments recorded in 2001 were as follows: $4.9 million based on the results of unsuccessful development drilling in the Rocky Mountains, $1.5 million resulting from depressed oil and natural gas prices in the Rocky Mountains and Mid-Continent, $0.9 million based on the results of unsuccessful development drilling in the Gulf of Mexico and $2.1 million resulting from depressed natural gas prices in the Gulf of Mexico. Impairments recorded in 2000 were mainly the result of a decline in oil and natural gas reserve value due to reserve volume reductions in underperforming fields in Wyoming, offshore and Louisiana. The impairment recorded in 1999 was the result of a decrease in risk adjusted probable reserves for the Ward Estes lease located in West Texas, which were subsequently assigned to the operator of the lease in exchange for existing producing property equipment and infrastructure owned by the operator.

        Impairment of Unproved Properties.  In 2001, we recognized unproved property impairments of $7.0 million on offshore leases, as a result of an assessment of the exploration opportunities existing on such properties. In 2000, we recognized unproved property impairments of $5.1 million, as a result of an assessment of the exploration opportunities existing on such properties. The $5.1 million consisted of $2.5 million for leases held in North Dakota, $1.5 million for leases held offshore and $1.1 million for various leases held in Kansas, Wyoming and Louisiana. In 1999, we recognized unproved property impairments of $2.3 million of which $1.3 million was associated with a prospect off the coast of Argentina and the remaining $1.0 million was for various leases held in North Dakota and Wyoming.

        Stock Compensation Expense.  In 2001, we recorded $0.7 million in stock compensation expense consisting of $0.4 million as a result of applying the provisions of FASB Interpretation No. 44 and $0.3 million in expense related to the issuance of restricted stock. In 2000, we recognized $5.5 million of stock compensation expense due to a $3.4 million one-time stock compensation expense related to the repurchase of employee stock options and $2.1 million related to provisions of FASB Interpretation No. 44. There was no stock compensation expense recorded in 1999.

        General and Administrative, or G&A, Expense.  G&A expense increased $10.2 million in 2001, or 134%, from $7.5 million in 2000 to $17.7 million in 2001. In connection with the EPGC merger additional employees were hired in the Houston office which accounted for a $3.0 million increase in G&A expense. The Merger accounted for $4.2 million of the increase. A majority of the remaining increase was due to payroll costs resulting from an increase in staff in 2001 reflecting expanded size and scope of our operations as a result of our reporting obligations under the Exchange Act. On an Mcfe basis, G&A expense in 2001 was $0.20 compared to $0.14 in 2000.

        G&A expense increased $2.2 million, or 42%, during 2000, from $5.3 million in 1999 to $7.5 million in 2000. In connection with the EPGC merger additional employees were hired in the Houston office, which accounted for a $3.4 million increase in G&A expense. Offsetting the increase in G&A expense was a $0.6 million increase in overhead recoveries from additional drilling in 2000 and $0.5 million additional costs incurred in 1999 related to closing an office acquired in an acquisition. On an Mcfe basis, G&A expense decreased 13% from $0.16 during 1999 to $0.14 during 2000.

        Other Income (Expense).  Other expense for 2001 was ($6.4 million) compared to ($8.3 million) for 2000. Interest expense increased $3.5 million in 2001, as a result of the increase in the debt balance relating to the Merger. Other income increased $5.4 million as compared to 2000 primarily due to an increase in interest income of $0.4 million and changes in fair values of $5.0 million on interest rate swap contracts that were not designated as hedges for accounting purposes.

        Other income (expense) for 2000 was ($8.3 million) compared to ($8.7 million) for 1999. The variance was primarily due to interest expense which increased $0.5 million from $9.2 million in 1999 to $9.7 million in 2000 as a result of $50 million in additional borrowings relating to the EPGC merger. The increase in interest expense was offset by an increase in interest income and other of $0.9 million primarily due to an increase in average cash balance during 2000.

        Income Taxes.  We recorded income tax expense of $28.6 million ($26.6 million deferred and $2.0 million current) for 2001 and $23.7 million ($23.0 million deferred and $0.7 million current) for 2000. The difference between the income tax expense for those periods and the amounts that would be calculated by applying statutory income tax rates to income before income taxes is due primarily to the utilization of credits generated from applying enhanced recovery methods in both periods.

        We recorded income tax expense of $23.7 million for 2000 and no income tax expense or benefit for 1999 resulting from a loss incurred in 1999. The difference between the income tax expense (benefit) for those periods and the amounts that would be calculated by applying statutory income tax rates to income before income taxes is due primarily to the credits from applying enhanced recovery methods in 2000 and a deferred tax valuation allowance recorded in 1999.

        Net Income.  Net income for 2001 was $49.8 million compared to net income of $43.5 million for 2000. The variance was primarily attributable to increases in revenues of $126.4 million and decrease in other expense of $2.0 million offset by increases of $117.2 million in operating expenses and $4.9 million in income tax expense. On a per share basis net income declined to $1.11 per basic share, $1.09 fully diluted from $1.54 per basic share, $1.52 fully diluted due to an increase of 13.7 million shares outstanding.

        Net income for 2000 was $43.5 million compared to a net loss of $3.1 million for 1999. The variance was primarily attributable to an increase in revenues of $143.3 million, partially offset by increases of $73.3 million in operating expenses and $23.7 million in income tax expense. On a per share basis net loss was $0.21 per basic and diluted share in 1999, compared to net income of $1.54 per basic share and $1.52 per diluted share in 2000.

Liquidity and Capital Resources

        Our principal uses of capital have been for the exploitation, acquisition and exploration of oil and natural gas properties.

        Cash flow from operating activities was $195.3 million for 2001 compared to $143.4 million for 2000. Operating cash flow in 2001 increased compared to 2000 due to a 58% increase in production as a result of the mergers with EPGC and Belco, recent discoveries in the Gulf of Mexico, and additional production from coalbed methane development from the Wiley and Ward Estes fields. Cash flow from operating activities increased $122.1 million from $21.3 million for 1999 to $143.4 million for 2000 due to a 77% increase in commodity prices and as a result of the merger with EPGC.

        Cash flow used in investing activities was $188.7 million for 2001 compared to $140.2 million for 2000. Investing activities for 2001 include $187.9 million used for exploitation and exploration activities and $6.3 million used for acquisitions, offset by proceeds from sales of properties of $5.5 million. Investing activities for 2000 included $102.2 million for exploitation and exploration activities and $43.9 million for acquisitions ($42.4 million related to the merger with EPGC), offset by proceeds from sales of properties of $6.3 million. Cash flow used in investing activities was $140.2 million for 2000 compared to cash flow generated in 1999 of $18.0 million. Cash generated in 1999 was due in part to $32.0 million of proceeds from sales of oil and natural gas properties, offset by $14.0 million in additions to oil and natural gas properties.

        Net cash generated in financing activities was $0.8 million for 2001 compared to $2.6 million cash used in 2000. Financing activities for 2001 consisted of $577.6 million in repayment of long-term debt, new financing fees of $10.2 million, stock repurchase of $0.4 million and preferred stock dividend of $1.6 million offset by $590.0 million in borrowings and $0.6 million from the issuance of common stock. Financing activities for 2000 reflected borrowings of $50.0 million utilized to consummate the merger with EPGC and $104.1 million from the issuance of common stock offset by repayments of long-term debt of $156.6 million. Net cash used in financing activities was $2.6 million for 2000 compared to net cash used in 1999 of $29.9 million. Cash was used in 1999 for repayments of long-term debt of $46.3 million offset by proceeds of $16.4 million from the issuance of common stock.

Financing Activity

        The following summarizes our contractual obligations at December 31, 2001 and the effect such obligations are expected to have on our liquidity and cash flow in future periods.

Revolving Credit Facility

        We entered into a new credit facility, which we refer to as the Revolving Credit Facility, with a syndicate of banks upon closing of the Merger. The Revolving Credit Facility, as amended on November 5, 2001, provides for a maximum committed amount of $500 million and a borrowing base of approximately $400 million as of December 31, 2001. The facility matures on July 1, 2005. Advances under the Revolving Credit Facility are in the form of either a base rate loan or a Eurodollar loan.

        The interest on a base rate loan is a fluctuating rate based upon the highest of:

•

the rate of interest announced by JP Morgan Chase Bank, formerly known as The Chase Manhattan Bank, as its prime rate;



•

the secondary market rate for three month certificates of deposits plus 1%; and



•

the Federal funds effective rate plus 0.5%;

in each case plus a margin of 0% to 0.125% based upon the ratio of total debt to EBITDAX.

        The interest on a Eurodollar loan is a fluctuating rate based upon the rate at which Eurodollar deposits in the London interbank market are quoted plus a margin of 1.25% to 1.50% based upon the ratio of total debt to EBITDAX.

        As of December 31, 2001, we had borrowings of $35.0 million (with an average interest rate of 3.25%) and letters of credit issued of approximately $3.8 million outstanding under the Revolving Credit Facility, and available unused borrowing capacity of approximately $361.2 million.

Redemption of 10¹/2% Senior Subordinated Notes due 2006

        On September 20, 2001, we redeemed all of our outstanding 10¹/2% Senior Subordinated Notes due 2006 at a price of $1,052.50 per note plus accrued interest. The notes were originally issued by Coda Energy and assumed in connection with the Merger, and they were redeemed pursuant to the optional redemption provision of the related indenture at 105.25% of the principal amount of each note plus accrued interest, for a total amount of approximately $120.1 million, consisting of $114.7 million in principal and $5.4 million in accrued interest. The redemption was funded by borrowings under the Revolving Credit Facility and available cash. No gain or loss was recognized in connection with the redemption as the fair value of the 10¹/2% Senior Subordinated Notes recorded in connection with the Merger equaled the redemption cost.

8⁷/8% Senior Subordinated Notes due 2007

        In connection with the Merger, we assumed $147 million face amount, $149 million fair value, of Belco's 8⁷/8% Senior Subordinated Notes due 2007. On November 1, 2001, approximately $24.3 million face amount of these notes was tendered to us pursuant to the change of control provisions of the related indenture. The tender price was equal to 101% of the principal amount of each note plus accrued and unpaid interest as of October 29, 2001. Including the premium and accrued interest, the total amount paid was $24.8 million. We used borrowings under our Revolving Credit Facility to fund the repayment. No gain or loss was recorded in connection with the redemption as the fair value of the 8⁷/8% Senior Subordinated Notes recorded in connection with the Merger equaled the redemption cost.

8¹/4% Senior Subordinated Notes due 2011

        On November 5, 2001, we completed the private placement of $275 million of 8¹/4% Senior Subordinated Notes due 2011 pursuant to SEC rule 144A. Proceeds of approximately $268 million, net of underwriting discounts and offering costs, were used to reduce outstanding indebtedness under the Revolving Credit Facility. On March 14, 2002 we completed the exchange of these notes for new notes with substantially identical terms, except that the new notes are generally freely tradeable.

Stock Repurchase

        On September 21, 2001, the board of directors authorized management to repurchase up to $30 million of our common stock. Under this authorization, we have repurchased 30,000 shares at an average price of $13.61 per share including broker commissions.

Capital Expenditures

        We anticipate that our capital expenditures for 2002 will be approximately $170 million. Our capital expenditures for 2001 were $187.9 million, not including acquisitions. We anticipate that our primary cash requirements for 2002 will include funding acquisitions, funding development projects and general working capital needs. We will continue to seek opportunities for acquisitions of proved reserves with substantial exploitation and exploration potential. The size and timing of capital requirements for acquisitions is inherently unpredictable and we therefore do not budget for them. We expect to fund our capital expenditure activities, which include acquisition, development of and exploration on our oil and natural gas properties through cash flow from operations and available capacity under our Revolving Credit Facility.

        We believe that borrowings under the Revolving Credit Facility, projected operating cash flows and cash on hand will be sufficient to meet the requirements of our business. However, future cash flows are subject to a number of variables including the level of production and oil and natural gas prices. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to:

•

drilling results;



•

product prices;



•

industry conditions and outlook; and



•

future acquisition of properties.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        We periodically enter into commodity price risk management, or CPRM, transactions to manage our exposure to oil and gas price volatility. CPRM transactions may take the form of futures contracts, swaps or options. All CPRM data is presented in accordance with requirements of SFAS No. 133, which we adopted on January 1, 2001. Accordingly, unrealized gains and losses related to the change in fair market value of derivative contracts that qualify and are designated as cash flow hedges are recorded as other comprehensive income or loss and such amounts are reclassified to oil and natural gas sales revenues as the associated production occurs. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of CPRM activities.

        For 2001, we recorded increases in operating revenues from non-hedge CPRM settlements in the amount of $15.3 million, which includes $3.6 million of cash settlements and non-hedge change in fair value of derivatives of $14.3 million. For 2000, we recorded a decrease in operating revenues from non-hedge change in fair value of derivatives of $0.7 million.

        For 2001, we recorded hedging settlement gains in the amount of $2.1 million, which include cash losses of $4.5 million and for 2000 and 1999 we recorded hedging settlement losses of $24.6 million and $7.9 million, respectively.

        Prior to the Merger, Belco entered into a substantial portion of its natural gas and crude oil commodity swap agreements and option agreements with Enron North America Corp., or ENA, formerly known as Enron Capital & Trade Resources Corp., a wholly owned subsidiary of Enron Corp. Mr. Robert A. Belfer, one of our directors, is a member of the Board of Directors of Enron Corp. and was the CEO of Belco at the time these transactions were entered into. These agreements were entered into in the ordinary course of business of Belco and on terms that we believe were no less favorable to Belco than the terms of similar arrangements with third parties. Old Westport also entered into commodity price risk management agreements with ENA prior to the Merger. Pursuant to the terms of these agreements Belco paid ENA a net amount of approximately $32 million in fiscal year 2000 and approximately $45 million in 2001. Old Westport and Westport received a net amount of $1.6 million in 2001 from ENA.

        On November 29, 2001, we terminated our commodity derivative contracts with Enron North America Corp., or ENA, formerly known as Enron Capital & Trade Resources Corp., a wholly-owned subsidiary of Enron Corp. We exercised our rights pursuant to the early termination provisions of such contracts as a result of ENA's bankruptcy filing and related events. We believe that we had the legal right to terminate these agreements, but ENA may challenge our termination in bankruptcy court. Applying the mark-to-market and setoff methodology of our contracts with ENA, we have calculated that we owed ENA a net $204,000 for all hedging transactions outstanding under our ENA contracts. Although we believe this methodology was correct, it is possible that ENA will challenge our calculations and claim larger amounts are owed.

        As of March 12, 2002, we have approximately 3.5 million barrels of oil and 17.5 Bcf of natural gas subject to CPRM contracts for 2002. The 2002 contracts have weighted average floor prices of $22.00 per barrel and $2.90 per Mmbtu, with weighted average ceiling prices of $24.68 per barrel and $3.14 per Mmbtu, respectively. We have approximately 0.9 million barrels of oil and 2.2 Bcf of natural gas subject to CPRM contracts for 2003. The contracts for 2003 are at weighted average floor prices of $21.45 per barrel and $3.00 per Mmbtu and weighted average ceiling prices of $23.08 per barrel and $6.50 per Mmbtu, respectively. These contracts represent our hedge and non-hedge positions.

        The tables below provide details about the volumes and prices of all open CPRM commitments, hedge and non-hedge, as of March 11, 2002: