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

FORM 10-K

Commission File Number 0-9204

EXCO RESOURCES, INC.
(Exact name of Registrant as specified in its charter)

        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 twelve (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 ninety (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 of this Form 10-K. o

        Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). YES ý    NO o

        The number of shares of Common Stock, par value $.02 per share, of the Registrant outstanding on February 28, 2003, was 7,029,518 (excludes 248,434 treasury shares). The aggregate market value of the voting and non-voting common equity held by non-affiliates (all directors and executive officers are presumed to be affiliates) of the Registrant on June 28, 2002, was approximately $87.5 million based on the average of the closing bid and ask prices per share of the Common Stock on such date.

DOCUMENTS INCORPORATED BY REFERENCE
None

TABLE OF CONTENTS

EXCO RESOURCES, INC.

PART I

ITEM 1.    BUSINESS

General

        EXCO Resources, Inc. is an independent energy company engaged in the acquisition, development and exploitation of oil and natural gas properties. Our primary areas of operations are onshore in Texas, Louisiana, Colorado, Mississippi and Alberta, Canada.

        Since our present management team purchased a significant ownership interest in us in December 1997, we have achieved substantial growth through a strategy of acquiring proved oil and natural gas properties with development and exploitation potential. Between December 1997 and December 2002, we have completed 71 acquisitions for total net consideration of approximately $276 million, including 26 acquisitions for aggregate net consideration of approximately $55.8 million since January 1, 2002. Overall, our acquisitions have been made at an average cost of approximately $0.74 per Mcfe of proved reserves using our estimate of proved reserves as of the time of the acquisition. We now own interests in a number of established oil and natural gas producing basins that we intend to use as a platform for further growth. In addition, we believe that our properties provide us with significant growth potential from development and exploitation activities.

        For this report, we converted Canadian dollars to U.S. dollars for balance sheet items including cash, oil and natural gas properties, and bank debt using the exchange rate at the end of the applicable period. The exchange rates of the Canadian dollar to the U.S. dollar were $0.628 and $0.636 at December 31, 2001 and 2002, respectively. For income statement items such as revenue, production costs, general and administrative costs, and interest, we converted Canadian dollars to U.S. dollars using the weighted average exchange rate across the applicable period. The weighted average exchange rates of the Canadian dollar to the U.S. dollar for the years 2001 and 2002 were $0.644 and $0.637, respectively. See Note 8 of the notes to our consolidated financial statements included in this annual report for certain information regarding our geographic operating areas.

Business Strategy

        We intend to become a leading independent oil and natural gas acquisition, exploitation and production company. We plan to achieve asset, revenue and cash flow growth as a result of the acquisition and further development of producing oil and natural gas properties by implementing the following business strategies:

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Acquire and Enhance Producing Oil and Natural Gas Properties. We plan to take advantage of opportunities that currently exist in the United States and Canada to acquire producing oil and natural gas properties. We continue to focus our acquisition activities onshore in the mid-continent region of the United States and in Alberta, Canada to complement our existing properties and operations. We continue to review potential acquisitions in other regions of the United States and Canada if we believe they represent an opportunity for exploration, exploitation and development. We believe that numerous opportunities exist for us to acquire additional energy assets and to enhance the value of these assets through improved operating practices and by developing reserve potential.



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Emphasize Exploitation and Development Activities. We continue to exploit our existing oil and natural gas properties and we continue to conduct development evaluation and drilling on our oil and natural gas properties. We intend to concentrate on enhancement opportunities from activities such as infill drilling, recompletions, secondary recovery projects, repairs and

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equipment changes. We may participate, from time to time, in a limited number of exploratory wells.

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Corporate Efficiencies. We plan to further maximize our corporate efficiencies through the development and operation of a larger asset base with the potential to limit increases in overhead in the future while operating an expanded asset base.



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Financial Management. We will continue to analyze our existing capital structure and financing requirements for future acquisitions and development to maintain appropriate levels of debt and equity.



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Technology. We plan to increase exploitation efforts, focusing on established geological trends where we can employ geological, geophysical and engineering expertise. We utilize 3-D seismic and advanced drilling technologies when appropriate.

        In 2002, we evaluated approximately 166 acquisition opportunities with an aggregate estimated market value of over $3.3 billion. We made offers on properties totaling more than $1.4 billion and successfully completed the purchase of approximately $55.8 million of oil and natural gas properties and related assets. Offers varied in amounts from less than $10,000 to $450 million. We intend to pursue large acquisitions that will have a significant impact on our growth and smaller projects that have the potential for high levels of profitability. We prefer to acquire properties with shallow production, which offer lower geologic and mechanical risk of operations. In evaluating prospective acquisitions, we generally focus on estimates of future cash flows, rates of return and net present values expected to be generated by the acquired properties.

Developments During 2002

We acquired additional oil and natural gas properties in Alberta, Canada.

        On April 29, 2002, Addison Energy Inc., our Canadian subsidiary, acquired oil and natural gas properties located in the Medicine River, Garrington, Gull Lake and Sylvan Lake areas in Alberta, Canada. The effective date of this transaction was January 1, 2002. As of January 1, 2002, estimated total proved reserves net to our interest included approximately 1.6 million Bbls of oil and NGLs, and 19.5 Bcf of natural gas. The purchase price was approximately $25.8 million or CDN $40.5 million ($24.7 million or CDN $36.3 million after contractual adjustments), funded with borrowings under our U.S. and Canadian credit agreements.

We acquired oil and natural gas properties in the DJ Basin of Colorado.

        On November 1, 2002, we acquired oil and natural gas properties located in the DJ Basin in Colorado. The effective date of the transaction was October 1, 2002. As of October 1, 2002, estimated total proved reserves net to our interest included approximately 2.1 million Bbls of oil and NGLs, and 13.5 Bcf of natural gas from 111 gross (103 net) wells. Net daily production in September 2002 was approximately 630 Bbls of oil and NGLs, and 3.7 Mmcf of natural gas. The purchase price was approximately $22.0 million ($21.1 million after contractual adjustments), funded with borrowings of $19.7 million under our U.S. credit agreement and $1.4 million from surplus cash.

We had a loss of well control event while drilling the Leon #3.

        We commenced drilling the Leon #3 well, in Pecos County, Texas, on February 16, 2002, which was completed as a producing natural gas well on September 8, 2002. The well was drilled and is being operated by another oil and natural gas company. While drilling operations were being conducted at 16,150 feet, a natural gas kick was taken and an underground blowout occurred. The well control problems resulted in a temporary loss of the wellbore back to 10,500 feet due to drill pipe being stuck in the hole. Fishing and other operations were eventually successful in freeing the drill pipe and the

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operator was able to recover the wellbore back to 16,150 feet. The well was subsequently completed at that depth and was placed on production. Our working interest in the well is 30.3%. We believe that the cost incurred for the well control event was covered under our well control insurance policy and claims have been submitted for these costs to our insurance carrier. The costs have not yet been reviewed by the insurance carrier. We have recorded as an accounts receivable approximately $684,000 at December 31, 2002, which represents our estimate of the insurance proceeds to be received by us.

        The Leon #3 well was drilled as a replacement well to the Leon #2, which we operated. A portion of the cost to drill the Leon #3 will be reimbursed to us by our insurance carrier. The Leon #2 suffered a loss of well control event on October 31, 2001, while drilling at 15,878 feet. The loss of well control event resulted in pressure of approximately 6,700 pounds per square inch at the surface, at which time casing burst down hole. This resulted in the uncontrolled flow of natural gas at the surface and later an underground blowout. The well was eventually brought under control with help from well control specialists and was plugged on November 27, 2001. The total cost of the Leon #2 loss of well control event was, including a portion of the cost to drill the Leon #3, $5.6 million ($1.7 million net to our interest). We received $606,000 in insurance proceeds, net to our working interest, during 2002 and we have an accounts receivable of $1.1 million recorded at December 31, 2002, which represents our estimate of additional insurance proceeds to be received by us. This claim has been fully reviewed by the insurance carrier and we collected the $1.1 million in February 2003.

We had a loss of well control event while conducting workover operations on the Miami Corp. #35.

        The Miami Corp. #35 well, in Cameron Parish, Louisiana, was not productive at the time we acquired it in 2000 due to downhole wellbore problems. In July 2002, we began workover operations in an attempt to return the well to production. On October 1, 2002, a loss of well control event occurred resulting in the release of approximately 20 Mmcf per day of natural gas and 2,800 barrels per day of formation water. No injuries or fires resulted from the loss of well control event. We contracted with well control specialists to assist with well control operations. Temporary production facilities were installed on the well and, as a result, a total of 325 Mmcf (244 Mmcf net to our interest) of natural gas was sold from the well between October 13, 2002, and November 25, 2002. The well was brought under control through conventional procedures on December 10, 2002. We continued to conduct workover operations on the well in an attempt to return the well to production. After being unable to recover downhole equipment that was stuck in the wellbore, in January 2003 we decided to temporarily abandon the well. We are evaluating several options including whether or not to sidetrack a portion of the wellbore, sell or transfer all or a portion of our interest to a third party, or to plug and abandon the well. The costs incurred for the loss of well control event and subsequent operations are estimated to be $3.2 million ($2.9 million net to our interest). We believe the cost incurred for the well control event was covered under our well control insurance policy and claims have been submitted for these costs to our insurance carrier. The costs have not yet been reviewed by the insurance carrier. We have recorded as an accounts receivable of $2.9 million at December 31, 2002, which represents our estimate of the insurance proceeds to be received by us.

We do not currently have well control insurance for our United States operations.

        Our well control insurance policy, which covered both our United States and Canadian operations, expired during 2002 and our insurance carrier declined to renew our policy. We have obtained well control coverage for our Canadian drilling and workover activities effective as of February 12, 2003. As a result of the claims we have made on our well control insurance policy related to the Leon #2, the Leon #3 and the Miami Corp. #35, as well as general market conditions for insurance, we have been unable to obtain new well control insurance coverage for our United States operations on terms acceptable to us. We have delayed projects that we believe contain operational risks and we may continue to delay or postpone projects in the United States in the future if we are unable to obtain

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well control insurance for our United States operations on acceptable terms. The project delays could reduce our estimated production for 2003. We further expect that, if we are able to obtain such insurance for our United States operations, the rates used to determine the premiums will be substantially higher and that we will have to accept a higher level of risk through either higher deductibles or co-insurance clauses than provided in our previous policy.

We received an acquisition proposal from Douglas H. Miller, our chairman and chief executive officer, and we have entered into a merger agreement.

        We have entered into a definitive agreement for the sale of the company to EXCO Holdings Inc., a company formed for that purpose by our chairman and chief executive officer, Douglas H. Miller, and his buyout group. The agreement provides that holders of our common stock, other than EXCO Holdings and its subsidiary, will receive cash of $18.00 per share and our holders of 5% convertible preferred stock will receive cash of $18.2625 per share if the transaction closes on or before June 15, 2003 and $18.00 per share thereafter. The 5% convertible preferred stock price difference is attributable solely to the unpaid accrued and unaccrued dividends for the 5% convertible preferred stock. A majority of the equity capital will be provided by Cerberus Capital Management, L.P. Cerberus Capital Management, L.P. is a New York based long-term investment fund manager with capital under management in excess of $8.5 billion.

        In August 2002, Mr. Miller made a proposal to acquire us for $17.00 cash per common share and $17.00 cash per preferred share, adjusted for dividends payable before closing. Our board of directors thereafter formed a special committee of the board of directors, which hired Merrill Lynch & Co. to evaluate the proposal and assist the special committee in considering alternatives. During the course of this process, the price proposed by Mr. Miller was negotiated to the improved price reflected in the definitive agreement. Because a majority of our directors are participating in the acquisition, pursuant to Texas corporation law the agreement was submitted to our shareholders for approval without a recommendation of the full board, but based on the recommendation of the special committee. The special committee unanimously recommended that our shareholders approve the agreement and the board has approved its submission to the shareholders.

        The transaction is subject to approval of our shareholders and customary closing conditions. The vote of holders of two-thirds of the outstanding shares of common stock, two-thirds of the outstanding shares of 5% convertible preferred stock and two-thirds of the outstanding shares of common stock and 5% convertible preferred stock voting as a single class is required to approve the transaction. We intend to hold a special meeting of the shareholders as soon as practicable. Completion of the transaction is expected late second quarter or early in the third quarter of 2003.

        In conjunction with our special meeting of the shareholders, we will be mailing to shareholders following Securities and Exchange Commission, or SEC, clearance a proxy statement, which will more fully describe the terms of the transaction and contain other information required by the SEC with regard to the transaction and the purchaser group. We have filed with the SEC a Current Report on Form 8-K, dated March 12, 2003, which includes a copy of the Agreement and Plan of Merger that has been executed by the parties. Investors should refer to this document for the complete terms of the merger transaction.

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        If Mr. Miller or the Buyout Group were to acquire all or a substantial majority of our outstanding shares of our common stock and 5% convertible preferred stock held by other shareholders, our common stock and 5% convertible preferred stock could be de-listed from trading on the NASDAQ National Market or any other exchange or inter-dealer quotation system. If Mr. Miller or the Buyout Group were to acquire all or a substantial majority of the outstanding shares of common stock and 5% convertible preferred stock held by other shareholders, the common stock and the 5% convertible preferred stock could become eligible for termination of registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934.

Litigation.

        On August 7, 2002, litigation was filed in connection with Mr. Miller's proposed offer. The litigation was filed in the 160^th State District Court in Dallas County, Texas and is captioned Weiser v. EXCO Resources, Inc. et al., Cause No. 02-7065. The complaint was purportedly filed on behalf of our public shareholders and alleges that our current directors breached fiduciary duties owed to our shareholders in connection with Mr. Miller's offer. We are named as a defendant in the litigation. The litigation seeks declaratory and injunctive relief to enjoin our ability to engage in such a transaction with Mr. Miller and the recovery of any compensatory damages that would allegedly be sustained as a result of the transaction. We believe that the allegations contained in the complaint are without merit, and plan to vigorously contest and defend against the litigation.

        On August 12, 2002, litigation was filed in the 162^nd State District Court in Dallas County, Texas and is captioned Birnbaum v. EXCO Resources, Inc., et al, Cause No. 02-07396-I. The complaint was purportedly filed on behalf of our public shareholders and alleges that our current directors breached fiduciary duties owed to our shareholders in connection with Mr. Miller's offer. We are named as a defendant in the litigation. The litigation seeks declaratory and injunctive relief to enjoin our ability to engage in such a transaction with Mr. Miller and the recovery of any compensatory damages that would allegedly be sustained as a result of the transaction. We believe that the allegations contained in the complaint are without merit, and plan to vigorously contest and defend against the litigation.

        On October 25, 2002, the Weiser and Birnhaum cases were consolidated in the 160^th District Court. The proceedings have been stayed by the agreement of the parties until Mr. Miller files an offer to purchase us with the SEC or until the setting of a shareholder meeting to approve a merger.

Developments Since December 31, 2002

We entered into additional hedge agreements.

        On January 17, 2003, we entered into four agreements to hedge additional natural gas volumes on a portion of our expected production for 2004. On January 29, 2003 and February 5, 2003, we entered into two agreements to hedge additional oil volumes on a portion of our expected production for 2004. The counterparties to these agreements were BNP Paribas and Bank One, financial lending institutions and members of our U.S. and Canadian bank groups. For more information concerning the additional hedging contracts, please review "Item 7A.—Quantitative and Qualitative Disclosures about Market Risk".

We have made additional acquisitions and dispositions of properties.

        Since December 31, 2002, we have completed two oil and natural gas property acquisitions, one in Canada and one in the United States. Estimated total proved reserves net to our interest from these acquisitions included approximately 196,000 Bbls of oil and NGLs, and 3.7 Bcf of natural gas from 14 gross (5.8 net) wells. Net daily production from these properties is approximately 38 Bbls of oil and NGLs, and 742 Mcf of natural gas. The total purchase price for the acquisitions was approximately $5.5 million funded with borrowings under our Canadian credit agreement and from surplus cash.

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        We also have two additional oil and natural gas property acquisitions pending in Canada that we expect to close in April 2003. As of April 1, 2003, estimated total proved reserves net to our interest from these acquisitions is expected to be approximately 139,000 Bbls of oil and NGLs, and 2.8 Bcf of natural gas. Net daily production in January 2003 from these properties was approximately 45 Bbls of oil and NGLs, and 630 Mcf of natural gas. The total purchase price for the acquisitions is approximately $4.1 million, which we expect to fund with borrowings under our Canadian credit agreement and from surplus cash.

        During January 2003, we sold two oil and natural gas properties in the United States. As of January 1, 2003, estimated total proved reserves net to our interest from these properties included approximately 391,000 Bbls of oil and NGLs, and 108,000 Mcf of natural gas from 8 gross (4.6 net) wells. Net daily production in December 2002 from these properties was approximately 256 Bbls of oil and NGLs, and 92 Mcf of natural gas. The total sales proceeds we received were approximately $1.9 million.

        We also have two oil and natural gas property dispositions pending in the United States, subject to normal closing conditions. As of January 1, 2003, estimated total proved reserves net to our interest from these properties included approximately 174,000 Bbls of oil and NGLs, and 84,000 Mcf of natural gas. Net daily production in December 2002 from these properties was approximately 50 Bbls of oil and NGLs, and 22 Mcf of natural gas. The total sales proceeds we expect to receive from the sale of these properties are approximately $1.1 million.

Investment Considerations and Risk Factors

        The risk factors noted in this section and other factors noted throughout this annual report, including those risks identified in "Item 7.—Management's Discussion and Analysis of Financial Condition and Results of Operations," describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this annual report.

Our revenue depends on oil and natural gas prices, which fluctuate.

        Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are also beyond our control. In addition, natural gas prices in Canada and for production from the DJ Basin in Colorado have been and may continue to be subject to lower market prices primarily due to higher transportation costs and capacity restraints. Factors that affect the prices we receive for our oil and natural gas include:

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the level of domestic production;



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the availability of imported oil and natural gas;



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actions taken by foreign oil and natural gas producing nations;



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the cost and availability of transportation systems with adequate capacity;



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the cost and availability of other competitive fuels;



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fluctuating and seasonal demand for oil and natural gas;



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conservation and the extent of governmental regulation of production;



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weather;

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foreign and domestic government relations; and



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overall economic conditions.

        Our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms depends substantially upon oil and natural gas prices.

Hedging our production may cause us to forego additional future profits.

        To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into hedging arrangements for a portion of our oil and natural gas production. The hedges that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Hedging arrangements may expose us to the risk of financial loss in some circumstances, including the following:

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the counterparty to the hedging contract may default on its contractual obligations;



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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received; or



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market prices may exceed the prices at which we are hedged, resulting in our need to make significant cash payments.

        Our hedging activities could have the effect of reducing our revenues which, in turn, could have an adverse effect on our financial condition. As of December 31, 2002, the unrealized loss on our hedges was $7.1 million. As of February 28, 2003, our hedged volumes, based upon proved developed producing reserves at December 31, 2002, represent approximately 55%-65% of our forecasted oil production and 65%-75% of our forecasted natural gas production during 2003, and approximately 65%-70% of our forecasted oil production and 45%-50% of our forecasted natural gas production during 2004. These hedging arrangements may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. For more information about our hedging risk, please review "Item 7A.—Quantitative and Qualitative Disclosures about Market Risk".

We may be unable to acquire or develop additional reserves.

        As is generally the case in the oil and natural gas industry, our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number of properties for sale. If we are unable to conduct successful development activities or acquire properties containing proved reserves, our total proved reserves will generally decline as a result of production. Also, our production will generally decline. If our production declines then our reserves will decline unless an increase in oil and natural gas prices offsets the decline. In addition, if our reserves and production decline then the amount we are able to borrow under our credit agreements will also decline. We cannot assure you that we will be able to locate additional reserves, that we will drill economically productive wells or that we will acquire properties containing proved reserves.

We cannot assure you that we will be successful in managing our growth.

        We have completed several large acquisitions and the pursuit of additional acquisitions is a key part of our strategy. Our growth could strain our financial, technical, operational and administrative resources. Failure to manage our growth successfully could adversely affect our operations and net revenues through increased operating costs and revenues that do not meet our expectations. We cannot

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assure you that we can successfully integrate acquired oil and natural gas properties into our operations or achieve desired profitability.

We may encounter marketing obstacles.

        Our ability to market our oil and natural gas production will depend upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities. With the exception of a few small gathering systems, we do not currently operate our own pipelines or transportation facilities. As a result, we are dependent upon third parties to transport our products. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation and Canadian regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

Our Canadian operations may be adversely affected by currency fluctuations and economic and political developments.

        We have significant oil and natural gas operations in Canada. Our Canadian operations are subject to the risk of fluctuations in the relative value of the Canadian and U.S. dollars. We have not hedged any currency risk exposure associated with our Canadian operations in prior periods. We are required to recognize foreign currency translation gains or losses related to our Canadian operations in our consolidated financial statements. Our Canadian operations may be adversely affected by political and economic developments, royalty and tax increases and other laws or policies in Canada, as well as U.S. policies affecting trade, taxation and investment in Canada.

Our Canadian properties and operations are subject to foreign regulations.

        The oil and natural gas industry in Canada is subject to extensive legislation and regulation governing its operations. This legislation and regulation, enacted by various levels of government, impacts a number of areas, including royalties, land tenure, exploration, development, production, refining, transportation, marketing, environmental protection, exports, taxes, labor standards and health and safety standards. In addition, extensive legislation and regulation exists with respect to pricing and taxation of oil and natural gas and related products. Canadian governmental legislation and regulation may have a material effect on our operating results and may have a material adverse effect on our results of operations and our financial condition.

We may not identify all risks associated with the acquisition of oil and natural gas properties.

        Generally, it is not feasible for us to review in detail every individual property involved in an acquisition. Our business strategy focuses on acquisitions of producing oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental hazards and other liabilities and other similar factors. Ordinarily, our review efforts are focused on the higher-valued properties. However, even a detailed review of these properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Even if we were able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective

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contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, we cannot assure you that the indemnity will be fully enforceable.

We have incurred significant debt that we may be unable to repay.

        As of December 31, 2002, we have aggregate debt outstanding of approximately $97.9 million under our U.S. and Canadian credit agreements. This level of indebtedness could:

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increase our vulnerability to general adverse economic and industry conditions, especially declines in oil and natural gas prices;



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limit our ability to fund future acquisitions, capital expenditures and other general corporate requirements;



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require us to dedicate a material portion of our cash flow from operations to payments on our indebtedness;



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force us to sell assets to reduce our indebtedness;



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limit our flexibility in planning for, or reacting to, changes in our business and industry; or



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limit our ability to, among other things, borrow additional funds, sell assets and pay dividends.

Restrictive debt covenants limit our ability to finance our operations, fund our capital needs and engage in other business activities that may be in our interest.

        Our U.S. and Canadian credit agreements contain significant covenants that, among other things, restrict our ability to:

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dispose of assets;



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incur additional indebtedness;



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repay other indebtedness;



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pay dividends;



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enter into specified investments or acquisitions;



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repurchase or redeem capital stock;



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merge or consolidate;



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engage in specified transactions with subsidiaries and affiliates; or



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other corporate activities.

        Also, our credit agreements require us to maintain compliance with specified financial ratios. Our ability to comply with these ratios may be affected by events beyond our control. A breach of any of these covenants or our inability to comply with the required financial ratios could result in a default under our credit agreements.

We may be unable to obtain additional financing to implement our growth strategy.

        The growth of our business will require substantial capital on a continuing basis. Because we have pledged substantially all of our assets as collateral under our U.S. and Canadian credit agreements, it may be difficult for us in the foreseeable future to obtain financing on an unsecured basis or to obtain additional secured financing other than purchase money indebtedness. If we are unable to obtain additional capital on satisfactory terms and conditions, we may lose opportunities to acquire oil and

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natural gas properties and businesses. Our failure to obtain any required additional financing may have a material adverse effect on our growth, cash flow and earnings.

We may be unable to overcome risks associated with our drilling activity.

        Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. The costs of drilling and completing wells is often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. While we use advanced technology in our operations, this technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible.

Acquisition, development and exploitation activities are associated with many uncertainties that could adversely affect our business, financial condition and results of operations.

        Our future success will depend on the success of our acquisition, development and exploitation activities. Our decisions to purchase, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

We cannot control the development of the properties we own but do not operate.

        As of December 31, 2002, we do not operate wells that represent approximately 17% of the present value of estimated future net revenues of our proved reserves. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

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the timing and amount of capital expenditures;



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the operators' expertise and financial resources;



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the approval of other participants in drilling wells; and



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the selection of suitable technology.

        If drilling and development activities are not conducted on these properties, we may not be able to increase our production or offset normal production declines.

Our estimates of oil, natural gas and NGL reserves involve inherent uncertainty.

        Numerous uncertainties are inherent in estimating quantities of proved oil, natural gas and NGL reserves, including many factors beyond our control. This annual report contains estimates of our proved oil, natural gas and NGL reserves and the PV-10 generated by the proved oil, natural gas and NGL reserves. These estimates are based upon reports of our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC, as to constant oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated proved reserves. The process of estimating oil, natural gas and NGL reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and future net revenue. Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves may vary substantially from

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those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value of reserves described in this annual report. In addition, our reserves may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas prices and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes of our reserves.

We are exposed to operating hazards and uninsured risks.

        Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

•

fire, explosions and blowouts;



•

pipe failure;



•

abnormally pressured formations; and



•

environmental accidents such as oil spills, gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

        These events may result in substantial losses to us from:

•

injury or loss of life;



•

severe damage to or destruction of property, natural resources and equipment;



•

pollution or other environmental damage;



•

clean-up responsibilities;



•

regulatory investigation;



•

penalties and suspension of operations; or



•

attorney's fees and other expenses incurred in the prosecution or defense of litigation.

        As is customary in our industry, we maintain insurance against some, but not all, of these risks. We cannot assure you that our insurance will be adequate to cover these losses or liabilities. Further, with the turmoil in the commercial insurance industry as a result of the events of September 11, 2001, we cannot predict the continued availability of insurance at commercially acceptable premium levels or at all. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events may have a material adverse effect on our financial condition and operations.

        Our well control insurance policy, which covered both our United States and Canadian operations expired in August 2002, and our insurance carrier declined to renew our policy. We have obtained well control coverage for our Canadian drilling and workover activities effective as of February 12, 2003. As a result of the claims we have made on our well control insurance policy related to the Miami Corp. #35, the Leon #2 and the drilling of the Leon #3, which was a replacement well for the Leon #2, as well as general market conditions for insurance, we have been unable to obtain new well control insurance coverage for our United States operations on terms acceptable to us. We have delayed projects that we believe contain operational risks and we may continue to delay or postpone projects in the United States in the future if we are unable to obtain well control insurance for our United States operations on acceptable terms. The project delays could reduce our estimated production for 2003. We further expect that, if we are able to obtain such insurance for our United States operations, that the rates used to determine the premium will be substantially higher than our prior policy and that we will have to accept a higher level of risk through either higher deductibles or co-insurance clauses than provided in our previous policy.

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        The producing wells that we own an interest in have, from time to time, experienced reduced or terminated production. These curtailments may result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions and weather conditions. These curtailments may last from a few days to many months.

Our business exposes us to liability and extensive regulation on environmental matters.

        Our operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations not only expose us to liability for our own negligence, but may also expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken.

Our business depends on a limited number of key personnel.

        We are substantially dependent upon the skills of two key individuals within our management, Mr. Douglas H. Miller and Mr. T. W. Eubank. Both individuals have experience in acquiring, financing and restructuring oil and natural gas companies. They both previously served as senior management at Coda Energy, Inc., where they successfully implemented a strategy similar to our current strategy. We do not have employment agreements with these individuals or maintain key man insurance. The loss of the services of either one of these individuals could hinder our ability to successfully implement our business strategy.

We may have additional write-downs of our asset values.

        We recorded pre-tax, non-cash ceiling test write-downs during 2001 of $28.7 million from our United States full cost pool and $20.9 million from our Canadian full cost pool. During the second quarter of 2002, we had an additional pre-tax, non-cash ceiling test write-down of $17.5 million from our Canadian full cost pool. Depending upon oil and natural gas prices in the future, we may be further required to write-down the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. Additional write-downs would negatively affect our earnings and net worth, and could result in a violation of covenants under our credit agreements.

We may not be permitted to pay cash dividends on our 5% convertible preferred stock in some circumstances. We could also be prevented in some circumstances from paying dividends on our common shares.

        The terms of our existing credit agreements restrict our ability to pay cash dividends. Our ability to pay cash dividends will depend on criteria set forth in our credit agreements. If there is a default under our credit agreements, we will not be able to pay dividends on the shares of 5% convertible preferred stock. Even if our credit agreements permit us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to satisfy our liabilities as they become due. We cannot assure you that we will have any surplus.

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Our 5% convertible preferred stock is subordinated to all our existing indebtedness and other liabilities and will not limit our ability to incur future indebtedness that will rank senior to our 5% convertible preferred stock.

        Our 5% convertible preferred stock is subordinated to all of our indebtedness with respect to the payment of interest and amounts distributable upon our dissolution, liquidation or winding-up. The terms of our 5% convertible preferred stock do not limit the amount of indebtedness or other obligations that we may incur. Any indebtedness under our existing credit agreements will rank senior to our 5% convertible preferred stock.

Sales, or the availability for sale, of substantial amounts of our common stock could adversely affect the value of our 5% convertible preferred stock.

        Sales of substantial amounts of common stock in the public market, and the availability of shares for future sale, including shares of our common stock issuable upon the conversion of shares of our 5% convertible preferred stock or upon exercise of outstanding options and warrants or other rights to acquire shares of our common stock, could adversely affect the prevailing market price of our common stock. This would adversely affect the value of our 5% convertible preferred stock and could impair our future ability to raise capital through an offering of our equity securities.

Our stock price may be volatile due to small public float.

        Because the number of shares of our common stock that trades on a daily basis is relatively small, the sale of a substantial number of shares of our common stock, or conversion of another security into a substantial number of shares of our common stock, may adversely affect the market price of our common stock.

Our articles of incorporation may prevent a takeover attempt that you may favor.

        Provisions in our articles of incorporation may delay, defer or prevent a tender offer or takeover attempt that you may consider to be in the best interest of our shareholders, including attempts that might result in a premium to be paid over the market price for the stock held by our shareholders. Our articles of incorporation permit our board to issue up to 5,010,131 additional shares of preferred stock and to establish, by resolution, one or more series of preferred stock and the powers, designations, preferences and participating, optional or other special rights of each series of preferred stock. The preferred stock may be issued on terms that are unfavorable to the holders of our common stock, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our liquidation and the designation of conversion rights that entitle holders of our preferred stock to convert their shares into our common stock on terms that are dilutive to holders of our common stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult.

Our Oil, Natural Gas and NGL Reserves

        The term "proved reserves" refers to the estimated quantities of oil, natural gas and NGLs that we may be able to recover in the future from known reservoirs. "Proved developed reserves" are proved reserves that are recoverable from known oil or natural gas reservoirs with existing equipment and operating methods. "Proved undeveloped reserves" are proved reserves requiring a relatively large development expense to make them recoverable from existing wells, or are proved reserves located in our undeveloped acreage.

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        We have not filed any estimates or included estimates in reports to any other federal authority or agency other than with the SEC since January 1, 2002. The following table summarizes our proved reserves at the dates shown, and was prepared according to the rules and regulations of the SEC:

(1)

The standardized measure represents the present value (using an annual discount rate of 10%) of estimated future net revenues from the production of proved reserves, after giving effect to income taxes.

        The reserve estimates presented as of December 31, 2000, 2001 and 2002, have been prepared by Lee Keeling and Associates, Inc., independent petroleum engineers, Tulsa, Oklahoma, and are a part of their report on our oil and natural gas properties. Estimates of oil, natural gas and NGL reserves are projections based on engineering data and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These reports should not be construed as the current market value of our estimated proved reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See also Note 13 of the notes to our consolidated financial statements included in this

14

annual report for additional information regarding our oil, natural gas and NGL reserves, including the present value of future net revenues and the standardized measure.

        The following table sets forth our proved reserves and PV-10 by area as of December 31, 2002:

Our Production, Prices and Expenses

        The following table summarizes for the periods indicated, our revenues (including hedge settlements), net production of oil, natural gas and NGLs sold, the average sales price per unit of oil, natural gas and NGLs, and costs and expenses associated with the production of oil, natural gas and NGLs:

15

Our Interest in Productive Wells

        The following table quantifies our productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells on December 31, 2002. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refers to the total number of physical wells that we hold any working interest in, regardless of our percentage interest. A net well is not a physical well, but is actually a concept that reflects the actual total working interests we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

(1)

As of December 31, 2002, we owned interests in 13 gross wells with multiple completions.

        As of December 31, 2002, we were the operator of 744 gross (587.9 net) wells, which represented approximately 83% of the present value of estimated future net revenues (as of December 31, 2002) of our proved reserves.

Our Drilling Activities

        We intend to concentrate our drilling activity on lower risk, development-type properties. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well and the estimated recoverable reserves attributable to each well.

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        The following table summarizes our approximate gross and net interests in the development wells drilled during the years indicated and refers to the number of wells completed at any time during the year, regardless of when drilling was initiated:

(1)

Information is for United States only. We acquired our Canadian operations in April 2001.

        During the three year period ended December 31, 2002, we did not participate in the drilling of any exploratory wells. The drilling activities during 2002 in the United States referenced in the above table were conducted in Texas, Oklahoma, Louisiana and Kansas. The drilling activities during 2002 in Canada referenced in the above table were conducted in Alberta. On December 31, 2002, we did not have any drilling wells in progress in the U.S. On December 31, 2002, in Canada, we owned a 100% working interest in a well being drilled in the Lacombe area of Alberta. As of February 28, 2003, we had no wells drilling in the United States. In Alberta, Canada, we owned a 100% working interest in a well being drilled in the Pine Creek area as of February 28, 2003.

Summary of Our Development and Exploitation Projects

        We are currently pursuing an active development and exploitation strategy. For the year 2003 we have budgeted up to $34.7 million for development drilling, recompletions, production facilities and other exploitation related projects to implement this strategy.

        Set forth below are highlights of our other current and planned activities.

Vinegarone Field.

        The Vinegarone Field is a natural gas field located in Val Verde County, Texas. We hold working interests ranging from less than 2% to 100% in 24 producing wells, of which we operate 21 wells. The wells produce from the Strawn and Swanson formations at depths from 10,000 to 10,500 feet. We currently plan to drill three wells and perform recompletion and/or commingling projects on four currently producing wells during 2003.

Gomez Field.

        The Gomez Field is a natural gas field located in Pecos County, Texas. We hold working interests ranging from less than 1% to 73%. We operate five of the nine producing wells in which we have an interest. Production is primarily from three different zones: the Wolfcamp formation at approximately 15,800 feet; the Devonian formation at approximately 17,700 feet; and, the Ellenberger formation at approximately 22,000 feet. We completed the Leon #3 well to the Wolfcamp formation in September 2002. We have no development plans in this field during 2003.

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Black Lake Field.

        The Black Lake Field is a natural gas field located in Natchitoches Parish, Louisiana. We hold a 79.4% working interest and operate all 23 producing wells in this 16,936 acre unitized field. The wells produce from the Petit Lime formation at a depth of approximately 8,000 feet. We plan to drill one horizontal well and perform artificial lift projects on eight wells in this field during 2003.

Wattenberg Field.

        The Wattenberg field is a natural gas field located in Weld County, Colorado. We acquired these properties during 2002. We hold working interests ranging from less than 3% to 100% in 111 producing wells, of which we operate 108 wells. The wells produce primarily from the Codell formation at a depth of approximately 7,000 feet. We currently plan to perform workover operations on 18 wells in this field during 2003.

Tiger Field.

        The Tiger Field is an oil and natural gas field located in Jones and Perry Counties, Mississippi. We hold an 88.3% working interest in this field. We operate four wells that produce from the Hosston and Cotton Valley formations at depths from 14,300 to 15,400 feet. We plan to drill an infill well and perform workover operations on four wells during 2003.

Pecos Slope Field.

        The Pecos Slope Field is a natural gas field located in Chaves County, New Mexico. We have working interests ranging from 12.5% to 100% in 29 wells, 23 of which we operate. Production is from the Abo formation at depths from 3,700 to 4,500 feet. We plan to drill two infill wells during 2003.

Garrington Field.

        The Garrington Field is located in Alberta, Canada and produces oil and natural gas from Cretaceous and Mississippian formations at an average depth of 8,000 feet. We have an average working interest of 71% in 85 producing wells, 70 of which we operate. We plan to complete 19 exploitation projects in the Garrington Field during 2003, which include recompletions, lift optimizations and facility expansions. We also plan to drill three wells in this field during 2003.

Pine Creek Field.

        The Pine Creek Field is an oil and natural gas field located in Alberta, Canada. We hold an average working interest of 87% in 35 producing wells, of which we operate 33. Pine Creek produces from Cretaceous formations at depths from 6,000 to 9,000 feet. We have identified three development locations to be drilled and eight exploitation projects to be performed in this field during 2003.

Caroline Field.

        The Caroline Field produces oil and natural gas from Cretaceous formations at an average depth of 9,000 feet. It is located in Alberta, Canada and is adjacent to our Garrington Field. We have an average working interest of 84% in 32 producing wells, all of which we operate. We plan to complete four exploitation projects in 2003.

Westward Ho Field.

        The Westward Ho Field is located in Alberta, Canada and produces oil and natural gas from Cretaceous and Mississippian formations at an average depth of 8,000 feet. It is also located adjacent to the Garrington Field. We have an average 64% working interest in 49 producing wells and operate

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40 of those wells. We plan to drill three wells and complete 15 exploitation projects in the Westward Ho Field during 2003.

Lacombe Field.

        The Lacombe Field, located in Alberta, Canada, produces natural gas from Cretaceous formations at depths from 800 to 5,500 feet. We operate seven of eight wells in this field. We have an average working interest of 88%. We have identified six development locations to be drilled and seven exploitation projects to be performed during 2003.

Our Developed and Undeveloped Acreage

        Developed acreage are those acres spaced or assignable to producing wells. Undeveloped acreage are those acres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains proved reserves. The following table sets forth our developed and undeveloped acreage at December 31, 2002:

        The primary terms of our oil and natural gas leases expire at various dates, generally ranging from one to five years. Almost all of our undeveloped acreage is "held by production," which means that these leases are active as long as we produce oil or natural gas from the acreage. Upon ceasing production, these leases will expire.

Sales of Producing Properties and Undeveloped Acreage

        We evaluate our portfolio of properties on an ongoing basis to determine the economic viability of the properties and whether these properties enhance our objectives. During the course of normal business, we may dispose of producing properties and undeveloped acreage if we believe that it is in our best interest.

        In 2002, we sold our interest in several producing oil and natural gas properties and a surplus natural gas processing plant in the United States for $3.7 million and a natural gas gathering system in Canada for $1.4 million. In 2001, we sold our interest in several producing oil and natural gas properties, including selected royalty and overriding royalty interests for $1.4 million. In 2000, we sold a portion of our interest in one group of producing oil and natural gas properties in Louisiana for $417,000, and a group of royalty interests in producing oil and natural gas properties located in various states for $491,000.

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Our Products, Markets and Revenues

United States.

        We produce oil, natural gas and NGLs. We do not refine or process the oil we produce. With the exception of our Black Lake Field in Louisiana, we do not refine or process a significant portion of the natural gas or NGLs we produce. At the Black Lake Field we operate a natural gas processing plant that is 100% dedicated to production from the field.

        We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on New York Mercantile Exchange (NYMEX) pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

        We sell the majority of our natural gas under short-term contracts using market sensitive pricing. Our sales contracts are of a type common within the industry, and we frequently negotiate a separate contract for each property. We sell our natural gas to transmission and utility companies that have pipelines in the vicinity of our producing properties, to companies that will construct pipelines to our properties or, to third party natural gas marketing companies.

        We sell our NGLs under both short-term and long-term contracts. We sell the NGLs to refiners and processors in the vicinity of our producing properties. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Typically, the prices we receive for NGLs are based on the Oil Price Information Service (OPIS) index, less transportation and fractionating fees.

        The availability of a ready market for oil, natural gas and NGLs and the prices of oil, natural gas and NGLs are dependent upon a number of factors that are beyond our control. These factors include, among other things:

•

the level of domestic production and economic activity generally;



•

the availability of imported oil and natural gas;



•

actions taken by foreign oil producing nations;



•

the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;



•

the cost and availability of other competitive fuels, fluctuating and seasonal demand for oil, natural gas and refined products; and



•

the extent of governmental regulation and taxation (under both present and future legislation) of the production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels.

        Accordingly, in view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of the oil, natural gas or NGLs from any producing well in which we have or may acquire an interest.

        We cannot assure you that we will be able to market all the oil, natural gas or NGLs we produce. If our oil, natural gas or NGLs can be marketed, we cannot assure you that we can negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties, and the estimates of recoverable oil, natural

20

gas and NGLs contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

        We engage in oil and natural gas production activities in areas where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated.

Canada.

        The majority of our Canadian oil is ultimately sold to Plains Marketing Canada, L.P. at market sensitive prices less applicable tariffs, trucking and quality adjustments.

        At December 31, 2002, we were selling approximately 17,000 Mmbtus of our Canadian natural gas per day to two different purchasers at market sensitive prices. The remainder of our Canadian natural gas is sold to various purchasers at market sensitive prices.

        Our NGLs are sold primarily to two different buyers under contracts which provide for index pricing less transportation and fractionation fees.

Revenues.

        The following table sets forth the amount of our oil, natural gas and NGL sales (including hedge settlements) and the percent of these sales to total oil, natural gas and NGL revenues for the periods indicated (in thousands):

(1)

Information is for United States only. We acquired our Canadian operations in April 2001.

Our Principal Customers

        During 2002, sales of oil to Plains All American, Inc. and affiliates and sales of natural gas to Engage Energy America, LLC accounted for 21.6% and 14.5%, respectively, of our total oil and natural gas revenues. During 2001, sales of oil to Plains All American, Inc. and affiliates and sales of natural gas to Western Gas Resources, Inc. accounted for 14.5% and 11.8%, respectively, of our total oil and natural gas revenues. If we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser's

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service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser. During 2002, several large wholesale purchasers of natural gas experienced significant downgrades in their credit ratings. As a result, many of these companies have either significantly reduced their level of natural gas purchases or have discontinued their purchases of natural gas. Although we do not believe that we have yet been significantly impacted by these changes, the loss of these large natural gas purchasers could have a detrimental effect on the natural gas market in general and on our ability to find purchasers for our natural gas. We typically do not require letters of credit or other forms of credit enhancement from our purchasers.

We Encounter Strong Competition

        The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

        We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.

        Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We cannot assure you that we will be successful in acquiring any of these properties.

We are Affected by Various Laws and Regulations

U.S. Regulations

        The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control. These factors include state and federal regulation of oil and natural gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities, and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an over-supply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and gas plants also are subject to the jurisdiction of various federal, state and local agencies.

        Our sales of natural gas are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis.

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        Our sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are regulated by the FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable rate-making methodology for interstate oil pipelines to fulfill the requirements of Title VII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates. The FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC's pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

        With respect to transportation of natural gas on or across the Outer Continental Shelf (OCS), the FERC requires, as a part of its regulation under the Outer Continental Shelf Lands Act (OCSLA), that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers. Although to date the FERC has imposed light-handed regulation on offshore gathering facilities, it has the authority to exercise jurisdiction under the OCSLA over these type of gathering facilities, if necessary, to require non-discriminatory access by shippers to service. For those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms and conditions applicable to this transportation are regulated by FERC under the NGA and NGPA, as well as the OCSLA. With respect to the transportation oil and condensate on or across the OCS, the FERC requires, as part of its regulation under the OCSLA, that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers. Accordingly, the FERC has the authority to exercise jurisdiction under the OCSLA, if necessary, to require non-discriminatory access by shippers to service.

        In the event we conduct operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (BLM) or Minerals Management Service (MMS) or other appropriate federal or state agencies.

        Our OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. Under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. On March 15, 2000, the MMS issued a final rule effective June 1, 2000, that amended its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amended the valuation procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value and relying instead on arm's length sales prices and spot market prices as market value indicators. Because we generally sell our production to third parties and therefore pay royalties on production from federal leases, we do not anticipate that this final rule will have any substantial impact on us.

        The Mineral Leasing Act of 1920 (the Mineral Act) prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen of a country that denies "similar or like privileges" to citizens of the United States. Such restrictions on citizens of a "non-reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal

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countries, there are presently no such designations in effect. We own interests in federal onshore oil and natural gas leases. It is possible that some of our shareholders may be citizens of foreign countries, and at some time in the future might be determined to be non-reciprocal under the Mineral Act.

        The pipelines we use to gather and transport our oil and natural gas may be subject to regulation by the Department of Transportation (DOT) under the Hazardous Liquids Pipeline Safety Act of 1979, as amended (HLPSA). The HLPSA governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Where applicable, the HLPSA requires us and other pipeline operators to comply with regulations issued pursuant to HLPSA that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.

        The Pipeline Safety Act of 1992 (the Pipeline Safety Act) amends the HLPSA in several important respects. The Pipeline Safety Act requires the Research and Special Programs Administration (RSPA) of DOT to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and records to RSPA. It also authorizes RSPA to require certain pipeline modifications as well as operational and maintenance changes. We believe our pipelines are in substantial compliance with the HLPSA and the Pipeline Safety Act where such regulations are applicable. However, we could incur significant expenses if new or additional safety measures are required.

U.S. Federal Taxation.

        The federal government may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.

U.S. Environmental Regulation.

        The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, is subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to federal environmental laws and regulations, including, but not limited to:

•

the Oil Pollution Act of 1990 (OPA);



•

the Clean Water Act (CWA);



•

the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA);



•

the Resource Conservation and Recovery Act (RCRA);



•

the Clean Air Act (CAA); and



•

the Safe Drinking Water Act (SDWA).

        Our domestic activities are also controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities, limit or prohibit other activities because of protected areas or species, can impose certain substantial liabilities for the

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cleanup of pollution, impose certain reporting requirements, and can require substantial expenditures for compliance.

        Under OPA and CWA, our release of oil and hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands, and offshore areas could result in our being held responsible for: (1) the costs of remediating a release, (2) administrative and civil penalties or criminal fines, or (3) OPA specified damages such as loss of use, and for natural resource damages. The extent of liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines.

        CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third party disposal facilities where wastes from operations were sent. Although CERCLA, as amended, currently exempts petroleum, (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA and similar state statutes. We cannot assure you that the exemption will be preserved in any future amendments of the act.

        RCRA and comparable state and local programs impose requirements on the management, including treatment, storage and disposal of both hazardous and nonhazardous solid wastes. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We generate hazardous and nonhazardous solid waste in our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling and production operations, as "hazardous wastes" under RCRA, which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. Adoption of these proposals could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact on our operations.

        Oil and natural gas exploration and production, and possibly other activities, have been conducted at the majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances require remediation. In some instances we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that potential costs would not result in material expenditures.

        If in the course of our routine oil and natural gas operations surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for waste handling, remediation and third party actions for damages. Moreover, we are able to directly control the

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operations of only the wells that we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be attributable to us and may create legal liabilities for us.

        We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed and interpreted, we are unable to predict the ultimate cost of compliance. We are unable to assure you that more stringent laws and regulations protecting the environment will not be adopted or that we will not incur material expenses in complying with environmental laws and regulations in the future. If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities on us may have a material adverse effect on our financial condition and results of operations.

OSHA and other regulations.

        We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Canadian Laws and Regulations

General.

        The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. The provincial government of Alberta has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, the prevention of waste and other matters. Although it is not expected that these controls and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size, the controls and regulations should be considered carefully by investors in the oil and natural gas industry. Outlined below are some of the principal aspects of legislation and regulations governing the oil and natural gas industry. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing—Oil.

        In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The prices we receive depend, in part, on oil type and quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance and other contractual terms. Oil exports from Canada may be made pursuant to export contracts with terms not exceeding one year, in the case of light crude, and not exceeding two years, in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board (NEB). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB, which requires governmental approval.

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Pricing and Marketing—Natural Gas.

        In Canada, the price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiations between buyers and sellers. The price we receive depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the supply/demand balance and other contractual terms. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 cubic meters per day), must be made pursuant to a NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity, requires an exporter to obtain an export license from the NEB, which requires governmental approval.

        The provincial government of Alberta also regulates the volume of natural gas which may be removed from Alberta for consumption elsewhere, based on such factors as reserve availability, transportation arrangements and market considerations.

Pipeline Capacity.

        Although pipeline expansions are ongoing, the lack of firm natural gas pipeline capacity continues to affect the ability to produce and market natural gas production. The prorating of capacity on the interprovincial pipeline systems may also affect the ability to export oil.

The North American Free Trade Agreements.

        On January 1, 1994, the North American Free Trade Agreement, NAFTA, among the governments of Canada, the U.S. and Mexico became effective. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed, provided that any export restrictions do not:

•

reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period);



•

impose an export price higher than the domestic price; and



•

disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

Land Tenure.

        Oil and natural gas located in the western provinces is owned predominately by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms and conditions set forth in provincial legislation which may include requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are generally granted by lease on such terms and conditions as may be negotiated.

Royalties and Incentives.

        In addition to federal regulation, each province in Canada has legislation and regulations that govern land tenure, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on

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production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, the type of product being produced, well productivity, geographical location and field discovery date.

        From time to time the federal and provincial governments in Canada have established incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. The trend in recent years has been for provincial governments to allow such programs to expire without renewal, and consequently few such programs are currently operative.

        On October 13, 1992, the provincial government of Alberta implemented major changes in its royalty structure and created incentives for exploring and developing oil and natural gas reserves. The incentives created include: (1) a one year royalty holiday on new oil discovered on or after October 1, 1992; (2) incentives by way of royalty holidays and reduced royalties on reactivated, low productivity, vertical re-entry and horizontal wells; (3) introduction of separate par pricing for light/medium and heavy oil; and (4) a modification of the royalty formula structure through the implementation of the Third Tier Royalty with a base rate of 2% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

        In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new gas, and between 15% and 35%, in the case of old gas, depending upon a prescribed or corporate average reference price.

        In Alberta, certain producers of oil or natural gas are also entitled to a credit against the royalties payable to the Alberta Crown by virtue of the Alberta royalty tax credit program (ARTC). The ARTC program is based on a price-sensitive formula, and the ARTC rate varies between 75%, at prices for oil below CDN $100 per cubic meter, and 25%, at prices above CDN $210 per cubic meter. The ARTC rate is applied to a maximum of CDN $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from companies claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The ARTC rate is established quarterly based on the average "par price," as determined by the Alberta Resource Development Department for the previous quarterly period.

        Oil and natural gas royalty holidays for specific wells and royalty reduction reduce the amount of Crown royalties paid by us to the provincial governments. The ARTC provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties.

Canadian Environmental Regulation.

        The oil and natural gas industry is currently subject to environment regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and natural gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. As well, applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant

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expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage.

        In Alberta, environmental compliance is governed by the Alberta Environmental Protection and Enhancement Act, AEPEA. In addition to replacing a variety of older statutes which related to environmental matters, the AEPEA imposes certain new environmental responsibilities on oil and natural gas operators in Alberta and in certain instances also imposes greater penalties for violations.

        We will be taking such steps as required to ensure compliance with the AEPEA and similar legislation in other jurisdictions in which it operates. We believe that we are in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

Title to Our Properties

        When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local mineral records. We do conduct title investigations and, in most cases, obtain a title opinion of local counsel before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

        Our properties are generally burdened by:

•

customary royalty and overriding royalty interests;



•

liens incident to operating agreements; and



•

liens for current taxes and other burdens and minor encumbrances, easements and restrictions.

We believe that none of these burdens either materially detract from the value of our properties or materially interfere with property used in the operation of our business. Substantially all of our properties are pledged as collateral under our U.S. and Canadian credit facility.

Our Employees

        As of December 31, 2002, we employed 119 persons (90 in the United States and 29 in Canada) of which 29 were involved in field operations and 90 were engaged in technical, office or administrative activities. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be good. We also utilize the services of independent consultants on a contract basis.

Our Officers

        Douglas H. Miller, 55, became our Chairman and Chief Executive Officer in December 1997. Mr. Miller was Chairman of the Board and Chief Executive Officer of Coda Energy, Inc., an independent oil and natural gas company, from October 1989 until November 1997 and served as a director of Coda from 1987 until November 1997.

        T. W. Eubank, 60, became our President, Treasurer and a director in December 1997. Mr. Eubank was a consultant to various private companies from February 1996 to December 1997. Mr. Eubank served as President of Coda from March 1985 until February 1996. He was a director of Coda from 1981 until February 1996.

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        J. Douglas Ramsey, Ph.D., 42, became our Chief Financial Officer and a Vice President in December 1997. Dr. Ramsey has been one of our directors since March 1998. Dr. Ramsey most recently was Financial Planning Manager of Coda and worked in various capacities for Coda from 1992 until 1997. Dr. Ramsey also taught finance at Southern Methodist University.

        Charles R. Evans, 49, joined us in February 1998, became a Vice President in March 1998, and was named our Chief Operating Officer in December 2000. Mr. Evans graduated from Oklahoma University with a B.S. degree in Petroleum Engineering in 1976. After working for Sun Oil Co., he joined TXO Production Corp. in 1979 and was appointed Vice President of Engineering and Evaluation in 1989. In 1990, he was named Vice President of Engineering and Project Development for Delhi Gas Pipeline Corporation, a natural gas gathering, processing and marketing company. Mr. Evans served as Director—Environmental Affairs and Safety for Delhi until December 1997.

        Richard E. Miller, 49, became our General Counsel, General Land Manager and Secretary of EXCO in December 1997 and became a Vice President in July 2000. Mr. Miller was a senior partner and head of the Energy Section of Gardere & Wynne, L.L.P., a Dallas based law firm, from December 1991 to September 1994. Mr. Miller practiced law as a sole practitioner from September 1994 to December 1997.

        J. David Choisser, CPA, 52, joined us in October 2001 and became our Chief Accounting Officer in November 2001, and a Vice President in February 2002. He began his career in 1972 with Deloitte Haskins & Sells (now Deloitte & Touche). During the past 25 years, he has served in various financial and accounting management capacities with several energy and energy-related companies, including Delhi Gas Pipeline Corporation, Coda Energy, Inc., Belco Oil & Gas Corp., and The Meridian Resource Corporation. He most recently served as Vice President—Finance of Noble Denton & Associates, Inc., an offshore engineering and marine consulting company.

        W. Andy Bracken, CPA, 38, joined us in October 1998 and became our Controller in April 2000. Mr. Bracken was a trust and operational internal auditor for Bank One, Louisiana, N.A. from April 1991 to April 1996 and NationsBank, N.A. from April 1996 to April 1997. He then served as an accounting manager for Bank One, Texas, N.A. from April 1997 to October 1998.

        Richard L. Hodges, 51, became one of our Vice Presidents in October 2000. He began his career with Texaco Inc. and has served in various land management capacities with several independent oil and gas companies during the past 27 years. He served as Vice President of Land for Central Resources, Inc. until the acquisition by EXCO of the Central properties in September 2000.

        John D. Jacobi, 49, became one of our Vice Presidents in February 1999. In 1991, he co-founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas producer, and served as its President until January 1997. He served as the Vice President and Treasurer of Jacobi-Johnson from January 1997 until May 8, 1998, when the company was sold to EXCO.

        Daniel A. Johnson, 51, became one of our Vice Presidents in February 1999. In 1991, he co-founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas producer. He served as its President from January 1997 until the company was sold to EXCO on May 8, 1998.

        James M. Perkins, Jr., 60, joined us as one of our Vice Presidents in February 2002. He has 38 years of experience in the oil and gas industry with major integrated oil companies, including ARCO and Texaco, and several independents, including Lyco Energy, Dorchester Exploration and General American Oil Company of Texas. He served these companies in various land management and executive positions.

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Glossary of Selected Oil and Natural Gas Terms

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

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

        "Bcf." One billion cubic feet of natural gas.

        "Bcfe."    One billion cubic feet equivalent calculated by converting 1 Bbl of oil or NGLs to 6 Mcf of natural gas.

        "infill drilling." Drilling of a well between known producing wells to better exploit the reservoir.

        "Mcf." One thousand cubic feet of natural gas.

        "Mcfe." One thousand cubic feet equivalent calculated by converting 1 Bbl of oil or NGLs to 6 Mcf of natural gas.

        "Mbbl." One thousand stock tank barrels.

        "Mmcf." One million cubic feet of natural gas.

        "NGLs." The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

        "overriding royalty interest." An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

        "present value of estimated future net revenues" or "PV-10."    The present value of estimated future net revenues is an estimate of future net revenues from a property at December 31, 2002, at its acquisition date, or as otherwise indicated, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil, natural gas and NGL prices and operating costs at December 31, 2002, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not in accordance with generally accepted accounting principles, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions.

        "royalty interest."    An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Available Information

        We do not currently maintain an active Internet website. Accordingly, we do not make our filings with the SEC available on or through a website. We will provide paper copies of our filings (excluding exhibits) free of charge upon request. Please mail your request to: EXCO Resources, Inc., 6500 Greenville Avenue, Suite 600, LB 17, Dallas, TX 75206, Attention: Investor Relations. You may also call us at (214) 368-2084 and ask to speak to investor relations.

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ITEM 2.    PROPERTIES

General

        We lease approximately 18,500 square feet of office space in Dallas, Texas, 7,450 square feet in Denver, Colorado, and 19,000 square feet in Calgary, Alberta for our corporate offices. The leases expire December 31, 2005, May 31, 2004, and August 31, 2007, respectively, and require monthly rental payments of approximately $23,700, $12,400, and $28,700, respectively. We also have small offices in Eastland, Texas, Tyler, Texas and Tulsa, Oklahoma.

Other

        We have described our oil and natural gas properties, oil, natural gas and NGL reserves, acreage, wells, production and drilling activity in "Item 1. Business" beginning on page 1 of this annual report.

ITEM 3.    LEGAL PROCEEDINGS

        We are a defendant in various lawsuits. We do not believe that any outcome of such lawsuits or other issues would have a material adverse effect on our financial position.

        On August 7, 2002, litigation was filed in connection with Mr. Miller's proposed offer. The litigation was filed in the 160^th State District Court in Dallas County, Texas, and is captioned Weiser v. EXCO Resources, Inc., et al., Cause No. 02-7065. The complaint was purportedly filed on behalf of our public shareholders and alleges that our current directors breached fiduciary duties owed to our shareholders in connection with Mr. Miller's offer. We are named as a defendant in the litigation. The litigation seeks declaratory and injunctive relief to enjoin our ability to engage in such a transaction with Mr. Miller and the recovery of any compensatory damages that would allegedly be sustained as a result of the transaction. We believe that the allegations contained in the complaint are without merit, and plan to vigorously contest and defend against the litigation.

        On August 12, 2002, litigation was filed in the 162^nd State District Court in Dallas County, Texas, and is captioned Birnbaum v. EXCO Resources, Inc., et al, Cause No. 02-07396-I. The complaint was purportedly filed on behalf of our public shareholders and alleges that our current directors breached fiduciary duties owed to our shareholders in connection with Mr. Miller's offer. We are named as a defendant in the litigation. The litigation seeks declaratory and injunctive relief to enjoin our ability to engage in such a transaction with Mr. Miller and the recovery of any compensatory damages that would allegedly be sustained as a result of the transaction. We believe that the allegations contained in the complaint are without merit, and plan to vigorously contest and defend against the litigation.

        On October 25, 2002, the Weiser and Birnbaum cases were consolidated in the 160^th District Court. The proceedings have been stayed by the agreement of the parties until Mr. Miller files an offer to purchase us with the SEC or until the setting of a shareholder meeting to approve a merger.

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

        During the last three months of the year ended December 31, 2002, we did not submit any matter to a vote by our shareholders through the solicitation of proxies or otherwise.

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PART II

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

Market Information for Our Common Stock

        Our common stock is quoted on the Nasdaq National Market System (Nasdaq NMS) under the symbol "EXCO." The following table sets forth the high and low bid prices from January 1, 2001 through December 31, 2002, based upon quotations periodically published on the Nasdaq NMS. All price quotations represent prices between dealers, without accounting for retail mark-ups, mark-downs or commissions, and may not represent actual transactions.

        The bid price for our common stock was $17.56 on March 18, 2003.

Our Shareholders

        According to our transfer agent, Continental Stock Transfer & Trust Company, there were approximately 725 holders of record of our common stock on February 28, 2003 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders).

Our Dividend Policy

        We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock. Our credit agreements do not prohibit us from paying dividends on our 5% convertible preferred stock. We anticipate that any income generated in the foreseeable future that is in excess of our dividend payments on our 5% convertible preferred stock will be retained for the development and expansion of our business. Our future dividend policy is subject to the discretion of the board of directors and will depend upon a number of factors, including future earnings, debt service, capital requirements, restrictions in our credit agreements, business conditions, our financial condition and other factors that our board of directors deems relevant.

Our Equity Compensation Plans Information

        For information on our equity compensation plans, please see "Item 11. Executive Compensation."

ITEM 6.    SELECTED FINANCIAL DATA

        The following table presents our selected historical financial data. You should read this financial data in conjunction with our "Management's Discussion and Analysis of Financial Condition and Results of Operations," our consolidated financial statements, the notes to our consolidated financial statements and the other financial information, included in this annual report. This information does not replace the consolidated financial statements. In our opinion, the data we have presented reflects all adjustments we consider necessary for a fair presentation of the results for the periods. We have completed numerous acquisitions since 1997 that materially impact the comparability of this data between periods.

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