10-K

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

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2002
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from                                    to

Commission File Number 0-9204

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

Texas (State or other jurisdiction of incorporation or organization)	74-1492779 (I.R.S. Employer Identification No.)
6500 Greenville Avenue, Suite 600, LB 17 Dallas, Texas (Address of principal executive offices)	75206 (Zip Code)
(Registrant's telephone number, including area code)	(214) 368-2084
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Common Stock, Par Value $.02 Per Share 5% Convertible Preferred Stock, Par Value $.01 Per Share (Title of class)

        Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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

			Page
PART I			1
	Item 1.	Business	1
	Item 2.	Properties	32
	Item 3.	Legal Proceedings	32
	Item 4.	Submission of Matters to a Vote of Security Holders	32
PART II			33
	Item 5.	Market for the Registrant's Common Equity and Related Shareholder Matters	33
	Item 6.	Selected Financial Data	33
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	35
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	51
	Item 8.	Financial Statements and Supplementary Data	56
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
PART III			93
	Item 10.	Directors and Executive Officers of the Registrant	93
	Item 11.	Executive Compensation	95
	Item 12.	Security Ownership of Certain Beneficial Owners and Management	96
	Item 13.	Certain Relationships and Related Transactions	101
	Item 14.	Controls and Procedures	102
PART IV			103
	Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	103

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:

•

the timing and amount of capital expenditures;



•

the operators' expertise and financial resources;



•

the approval of other participants in drilling wells; and



•

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

10

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:

			As of December 31,
			2000		2001						2002
			United States		United States		Canada		Total		United States		Canada		Total
Oil (Mbbls)
	Developed			8,148		7,555		3,414		10,969		9,067		5,425		14,492
	Undeveloped			4,230		3,498		386		3,884		3,214		329		3,543
		Total		12,378		11,053		3,800		14,853		12,281		5,754		18,035
Natural Gas (Mmcf)
	Developed			66,497		87,868		65,230		153,098		115,222		92,512		207,734
	Undeveloped			27,947		22,388		8,174		30,562		26,376		15,183		41,559
		Total		94,444		110,256		73,404		183,660		141,598		107,695		249,293
Natural Gas Liquids (Mbbls)
	Developed			465		774		2,470		3,244		985		3,432		4,417
	Undeveloped			—		13		359		372		112		562		674
		Total		465		787		2,829		3,616		1,097		3,994		5,091
Total (Mmcfe)				171,502		181,296		113,178		294,474		221,866		166,183		388,049
Prices utilized:
	Oil (per Bbl)		$	24.82	$	17.67	$	18.02	$	17.76	$	29.74	$	29.16	$	29.56
	Natural gas (per Mcf)			9.26		2.22		2.24		2.23		4.27		3.91		4.12
	NGLs (per Bbl)			21.50		14.25		15.33		15.09		20.71		22.30		21.96
Pre-tax Present Value, discounted at 10% (PV-10) (in thousands)
	Developed		$	288,864	$	92,150	$	76,127	$	168,277	$	219,399	$	218,013	$	437,412
	Undeveloped			107,536		13,540		7,338		20,878		64,433		28,178		92,611
		Total	$	396,400	$	105,690	$	83,465	$	189,155	$	283,832	$	246,191	$	530,023
Standardized Measure (in thousands) (1)			$	282,436	$	83,085	$	60,444	$	143,529	$	152,923	$	157,417	$	310,340

(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:

			Total Proved Reserves (Bcfe)	PV-10		Percent of PV-10
			(In thousands)
United States:
	Permian Basin		83	$	102,896	20	%
	Gulf Coast		52		76,450	14	%
	Rockies		37		40,304	8	%
	Mid-Continent		26		33,692	6	%
	East Texas/North Louisiana		24		30,490	6	%
		Total U.S.	222		283,832	54	%
Canada:
	Alberta		166		246,191	46	%
		Total U.S. and Canada	388	$	530,023	100	%

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:

			Year Ended December 31,
			2000		2001						2002
			United States		United States		Canada		Total		United States		Canada		Total
			(In thousands, except production and per unit amounts)
Sales:
	Oil:
		Revenue	$	11,846	$	21,633	$	1,739	$	23,372	$	16,330	$	9,661	$	25,991
		Production sold (Mbbls)		433		887		80		967		869		399		1,268
		Average sales price per Bbl	$	27.39	$	24.40	$	21.71	$	24.17	$	18.78	$	24.23	$	20.50
	Natural Gas:
		Revenue	$	14,830	$	29,558	$	5,394	$	34,952	$	16,697	$	18,077	$	34,774
		Production sold (Mmcf)		3,982		6,243		2,086		8,329		6,878		6,565		13,443
		Average sales price per Mcf	$	3.72	$	4.73	$	2.59	$	4.20	$	2.43	$	2.75	$	2.59
	Natural Gas Liquids:
		Revenue	$	2,193	$	1,826	$	1,087	$	2,913	$	1,227	$	4,454	$	5,681
		Production sold (Mbbls)		89		96		68		164		74		242		316
		Average sales price per Bbl	$	24.60	$	18.96	$	15.92	$	17.70	$	16.66	$	18.38	$	17.98
Costs and Expenses:
		Average production cost per Mcfe	$	1.32	$	1.76	$	0.85	$	1.59	$	1.52	$	0.98	$	1.27
		General and administrative expense per Mcfe	$	0.28	$	0.34	$	0.23	$	0.32	$	0.54	$	0.40	$	0.48
		Depreciation, depletion and amortization per Mcfe	$	0.69	$	0.80	$	1.50	$	0.94	$	0.76	$	0.87	$	0.81

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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.

			Gross Wells (1)			Net Wells
			Oil	Gas	Total	Oil	Gas	Total
United States:
	Colorado		28	111	139	9.0	102.7	111.7
	Kansas		117	41	158	50.7	20.6	71.3
	Louisiana		21	18	39	14.9	13.7	28.6
	Mississippi		36	0	36	30.0	0.0	30.0
	Nebraska		43	4	47	18.3	1.7	20.0
	New Mexico		82	79	161	3.1	32.8	35.9
	Oklahoma		50	36	86	41.6	7.8	49.4
	Texas		878	170	1,048	162.6	87.0	249.6
	Wyoming		72	9	81	15.1	5.2	20.3
		Total	1,327	468	1,795	345.3	271.5	616.8
Canada:
	Alberta		226	211	437	97.0	157.4	254.4
		Total	1,553	679	2,232	442.3	428.9	871.2

(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:

			Development Wells
			Gross			Net
			Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2000 (1)			11	—	11	3.9	—	3.9
Year ended December 31, 2001
	United States		32	4	36	17.0	1.0	18.0
	Canada		9	1	10	8.6	1.0	9.6
		Total	41	5	46	25.6	2.0	27.6
Year ended December 31, 2002
	United States		9	1	10	5.4	.3	5.7
	Canada		12	1	13	7.5	1.0	8.5
		Total	21	2	23	12.9	1.3	14.2

(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.

17

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:

			Developed Acreage		Undeveloped Acreage
			Gross	Net	Gross	Net
United States:
	Colorado		13,342	8,556	2,680	1,497
	Kansas		22,084	10,965	4,400	194
	Louisiana		26,903	14,678	10,527	7,546
	Mississippi		8,300	3,300	4,546	3,573
	Montana		7,894	339	—	—
	Nebraska		21,491	6,762	8,918	2,429
	New Mexico		27,163	10,562	8,835	4,752
	Oklahoma		14,192	4,671	1,563	793
	Texas		78,089	32,795	30,947	16,467
	Wyoming		8,390	2,788	5,780	2,741
		Total	227,848	95,416	78,196	39,992
Canada:
	Alberta		147,338	103,540	89,510	65,553
		Total	375,186	198,956	167,706	105,545

        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):

											Percent of Sales to Total Oil, Natural Gas and NGL Revenues
									Total Oil, Natural Gas and NGL Sales
Period Ended			Oil Sales		Natural Gas Sales		NGL Sales				Oil		Natural Gas		NGLs
Year ended December 31, 2000 (1)			$	11,846	$	14,830	$	2,193	$	28,869	41	%	51	%	8	%
Year ended December 31, 2001
	United States		$	21,633	$	29,558	$	1,826	$	53,017	41	%	56	%	3	%
	Canada			1,739		5,394		1,087		8,220	21	%	66	%	13	%
		Total	$	23,372	$	34,952	$	2,913	$	61,237	38	%	57	%	5	%
Year ended December 31, 2002
	United States		$	16,330	$	16,697	$	1,227	$	34,254	48	%	49	%	3	%
	Canada			9,661		18,077		4,454		32,192	30	%	56	%	14	%
		Total	$	25,991	$	34,774	$	5,681	$	66,446	39	%	52	%	9	%

(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

21

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

23

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

24

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

25

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

27

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

28

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.

30

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.

		High		Low
Year ended December 31, 2001:
	First Quarter	$	20.13	$	15.25
	Second Quarter		21.06		18.19
	Third Quarter		17.10		14.45
	Fourth Quarter		16.72		13.26
Year ended December 31, 2002:
	First Quarter	$	16.75	$	14.94
	Second Quarter		17.40		14.79
	Third Quarter		16.61		14.60
	Fourth Quarter		17.46		16.35

        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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			Year Ended December 31,
			1998			1999			2000			2001			2002
			(In thousands, except per share amounts)
Statement of Operations Data:
Revenues:
	Oil and natural gas		$	1,385		$	5,294		$	28,869		$	61,237		$	66,446
	Other			690			2,008			1,252			5,567			6,654
	Gain on disposition of properties, equipment and other assets			—			5,102			538			136			3
		Total revenues		2,075			12,404			30,659			66,940			73,103
Costs and expenses:
	Oil and natural gas production			786			2,375			9,484			23,914			29,223
	Depreciation, depletion and amortization			465			1,446			4,949			14,244			18,558
	General and administrative			1,231			1,934			2,003			4,806			10,968
	Interest expense			104			17			1,369			3,133			3,408
	Impairment of oil and natural gas properties			—			—			—			49,575			17,459
	Impairment of marketable securities			—			—			—			—			1,136
	Uncollectible value of Enron hedges			—			—			—			10,669			—
		Total costs and expenses		2,586			5,772			17,805			106,341			80,752
Income (loss) before income taxes and minority interest				(511	)		6,632			12,854			(39,401	)		(7,649	)
Minority interest in limited partnership				—			(7	)		—			—			—
Income (loss) before income taxes				(511	)		6,639			12,854			(39,401	)		(7,649	)
Income tax expense (benefit)				—			2,139			4,400			(54	)		(6,682	)
Income (loss) before extraordinary items				(511	)		4,500			8,454			(39,347	)		(967	)
Fee income from early extinguishment of debt, net of tax				—			165			—			—			—
Net income (loss)				(511	)		4,665			8,454			(39,347	)		(967	)
Dividends on preferred stock				—			—			—			2,653			5,256
Earnings (loss) on common stock			$	(511	)	$	4,665		$	8,454		$	(42,000	)	$	(6,223	)
Basic earnings (loss) per share			$	(.18	)	$	.69		$	1.23		$	(5.96	)	$	(0.88	)
Diluted income (loss) per share			$	(.18	)	$	.69		$	1.18		$	(5.96	)	$	(0.88	)
Weighted average common and common equivalent shares outstanding:
	Basic			2,871			6,698			6,835			7,046			7,061
	Diluted			2,871			6,714			7,122			7,046			7,061
Statement of Cash Flows Data:
Net cash provided by (used in):
	Operating activities		$	(127	)	$	(8,620	)	$	27,297		$	25,916		$	31,660
	Investing activities			(14,060	)		(2,862	)		(66,519	)		(133,771	)		(76,937	)
	Financing activities			35,184			(39	)		37,450			102,130			45,928
Other Financial Data:
EBITDA (1)			$	58		$	8,267		$	19,172		$	34,074		$	25,485

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	December 31,
	1998		1999		2000		2001		2002
	(In thousands)
Balance Sheet Data:
Current assets	$	22,157	$	31,599	$	20,262	$	21,121	$	26,198
Oil and natural gas properties, net		7,554		18,674		80,355		164,835		209,951
Total assets		36,888		50,932		102,372		191,056		241,174
Current liabilities		648		10,017		8,655		13,322		33,193
Long-term debt, less current maturities		—		—		42,488		44,994		97,943
Stockholders' equity		36,240		40,880		49,791		120,379		99,884
Total liabilities and stockholders' equity		36,888		50,932		102,372		191,056		241,174

(1)

EBITDA is defined as net income, plus interest expense, income taxes, and depreciation, depletion and amortization expenses. For 2002, it also adds back $17.5 million for impairments of oil and natural gas properties and deducts $6.3 million of other income from hedge ineffectiveness and from derivatives for which hedge accounting was terminated. For 2001, it also adds back $60.2 million for impairments of oil and natural gas properties and the uncollectible value of Enron hedges and deducts $4.1 million of other income from hedge ineffectiveness and from derivatives for which hedge accounting was terminated. EBITDA is a financial measure commonly used in our industry and should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of our profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income and may vary among companies, the EBITDA presented above may not be comparable to similarly titled measures of other companies.

        The following table reconciles, by year, the differences between our net income or loss as reported on our consolidated statements of operations and our reported EBITDA.

	Year Ended December 31,
	1998			1999		2000		2001			2002
	(In thousands)
Net income (loss) as reported on consolidated statement of operations	$	(511	)	$	4,665	$	8,454	$	(39,347	)	$	(967	)
Add back/(deduct):
Depreciation, depletion and amortization		465			1,446		4,949		14,244			18,558
Interest expense		104			17		1,369		3,133			3,408
Impairment of oil and natural gas properties		—			—		—		49,575			17,459
Uncollectible value of Enron hedges		—			—		—		10,669			—
Income from hedge ineffectiveness and terminated hedges		—			—		—		(4,146	)		(6,291	)
Income tax expense (benefit)		—			2,139		4,400		(54	)		(6,682	)
EBITDA	$	58		$	8,267	$	19,172	$	34,074		$	25,485

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

Forward-Looking Statements.

        The statements contained in this report regarding our future financial and operating performance and results, business strategy, market prices, future hedging activities, plans and forecasts under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business," and other statements that are not historical facts are forward-looking statements, as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. We have based these forward-looking statements on our current assumptions, exceptions and projections about future events.

        We use the words "may," "will," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget," or other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial conditions, and/or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking

35

statements. These statements also involve risks and uncertainties that could cause our actual results to materially differ from our expectations in this report, including, but not limited to:

•

estimates of reserves;



•

market factors;



•

market prices (including regional basis differentials) of oil and natural gas;



•

results of future drilling;



•

marketing activity;



•

future production and costs;



•

and other factors discussed in this report and in our other SEC filings.

        We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this annual report.

        Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Critical Accounting Policies

        In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified the most critical accounting principles that our financial status depends upon. We determined the critical principles by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our proved reserve estimates, derivatives accounting, functional currency assessment, deferred tax asset valuations and our choice of accounting method for oil and natural gas properties.

        We prepared our consolidated financial statements for inclusion in this report in accordance with accounting principles that are generally accepted in the United States (GAAP). GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.

Proved reserve estimates.

        Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:

•

the quality and quantity of available data;



•

the interpretation of that data;

36

•

the accuracy of various mandated economic assumptions; and



•

the judgment of the persons preparing the estimate.

        Our proved reserve information included in this report is based on estimates prepared by our independent petroleum engineers.

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

        You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Further, a discount rate of 10% may not be an accurate assumption of future interest rates.

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

Accounting for derivatives.

        We engage in price risk management activities to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition activities. We have a policy of hedging oil and natural gas prices whenever such prices are in excess of prices anticipated in our operating budget and profit plan through the use of swap agreements. These derivatives are not held for trading purposes.

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

        Effective as of November 30, 2001, we ceased hedge accounting for our hedge transactions then in place due to the bankruptcy filing of the counterparty to our swap agreements (see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk").

Assessments of functional currencies.

        We determine the functional currencies of our subsidiaries by assessing the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. We have determined that the Canadian dollar is the functional currency of our international operations in Canada. Our assessment of functional currencies can have a significant impact on our periodic results of operations and on our financial position.

37

Deferred tax asset valuations.

        We periodically assess the probability of recovering recorded deferred tax assets based on our assessment of future earnings outlooks by tax jurisdiction. These estimates are inherently imprecise because we make many assumptions in the assessment process. For the years ended December 31, 2001 and 2002, our net deferred tax asset in the U.S. of $7.6 million and $3.5 million, respectfully, have been fully reserved as it continues to be uncertain whether we will be able to utilize our net deferred tax asset. We are in a net deferred tax liability position in Canada, and, accordingly, no valuation allowance has been provided. Going forward, we will continue to evaluate the need for a valuation allowance in the U.S. based on various factors, including operating performance, the future outlook of oil and natural gas prices and the nature of the components of the deferred tax asset.

Accounting for oil and natural gas properties.

        The accounting for and disclosure of oil and natural gas producing activities requires that we choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties.

        We use the full cost method of accounting, which involves capitalizing all acquisitions, exploration, exploitation and development costs. Once we incur costs, they are recorded in the full cost pool or in unevaluated properties. Unevaluated property costs are not subject to depletion. We review our unevaluated costs on an ongoing basis, and we expect these costs to be evaluated in one to three years and transferred to the full cost pool during that time.

        We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total amount of proved reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs that are attributable to our acquisition, exploration, exploitation and development activities.

        To the extent that total capitalized oil and natural gas property costs (net of related deferred income taxes and accumulated depreciation, depletion and amortization) exceed the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects, plus the lower of cost or fair value of unproved properties, excess costs are charged to operations. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date even if oil or natural gas prices increase. We could be required to write down our oil and natural gas properties if there is a decline in oil or natural gas prices, or downward adjustments are made to our estimates of proved reserves. During 2001 and 2002, we recognized impairment charges of $20.9 million and $17.5 million, respectively, with respect to our properties located in Canada, and in 2001, we recognized an impairment charge of $28.7 million, with respect to our properties located in the United States. These charges were the result of low prices for oil and natural gas at September 30, 2001, December 31, 2001 and June 30, 2002.

Recently Issued Accounting Standards

        In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We will adopt the new rules on asset retirement obligations on January 1, 2003, for both our U.S. and Canadian properties. Application of the new rules is expected to result in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.2 million, recognition of an asset retirement obligation liability of approximately $10.2 million, a reduction in deferred income tax liability of approximately $700,000, and a cumulative effect of adoption that will increase net income and stockholders' equity by approximately $1.7 million.

38

Our Results of Operations

        The following tables present production and average unit prices and costs for the periods and, beginning in 2001, when we first acquired Canadian assets, the relevant geographic segments:

			Year Ended December 31,
			2000	2001	2002
Production:
	Oil (Mbbls)
		U.S.	433	887	869
		Canada	—	80	399
		Total	433	967	1,268
	Natural gas (Mmcf)
		U.S.	3,982	6,243	6,878
		Canada	—	2,086	6,565
		Total	3,982	8,329	13,443
	Natural gas liquids (Mbbls)
		U.S.	89	96	74
		Canada	—	68	242
		Total	89	164	316
	Mmcfe
		U.S.	7,114	12,141	12,536
		Canada	—	2,974	10,411
		Total	7,114	15,115	22,947

			Year Ended December 31,
			2000		2001		2002
Average Sales Price (including hedge settlements):
	Oil (per Bbl)
		U.S. (1)	$	27.39	$	24.40	$	18.78
		Canada	$	—	$	21.71	$	24.23
		Total (2)	$	27.39	$	24.17	$	20.50
	Natural gas (per Mcf)
		U.S. (3)	$	3.72	$	4.73	$	2.43
		Canada	$	—	$	2.59	$	2.75
		Total (4)	$	3.72	$	4.20	$	2.59
	Natural gas liquids (per Bbl)
		U.S.	$	24.60	$	18.96	$	16.66
		Canada	$	—	$	15.92	$	18.38
		Total	$	24.60	$	17.70	$	17.98
	Total oil and natural gas revenues (per Mcfe)
		U.S.	$	4.06	$	4.37	$	2.73
		Canada	$	—	$	2.76	$	3.09
		Total	$	4.06	$	4.05	$	2.90

(1)

Reflects the impact on the U.S. average oil price of monthly hedge settlements for the years ended December 31, 2000, 2001 and 2002 of $1.85 decrease, $0.86 increase and $4.97 decrease, respectively.

(2)

Reflects the impact on the total average oil price of monthly hedge settlements for the years ended December 31, 2000, 2001 and 2002 of $1.85 decrease, $0.79 increase and $3.40 decrease, respectively.

39

(3)

Reflects the impact on the U.S. average natural gas price of monthly hedge settlements for the years ended December 31, 2000, 2001 and 2002 of $0.09 decrease, $0.87 increase and $0.49 decrease, respectively.

(4)

Reflects the impact on the total average natural gas price of monthly hedge settlements for the years ended December 31, 2000, 2001 and 2002 of $0.09 decrease, $0.65 increase and $0.25 decrease, respectively.

			Year Ended December 31,
			2000		2001		2002
Expenses (per Mcfe):
	Oil and natural gas production
		U.S.	$	1.05	$	1.43	$	1.20
		Canada	$	—	$	0.81	$	0.94
		Total	$	1.05	$	1.32	$	1.08
	Production and ad valorem taxes
		U.S.	$	0.27	$	0.33	$	0.32
		Canada	$	—	$	0.04	$	0.04
		Total	$	0.27	$	0.27	$	0.19
	General and administrative
		U.S.	$	0.28	$	0.34	$	0.54
		Canada	$	—	$	0.23	$	0.40
		Total	$	0.28	$	0.32	$	0.48
	Depreciation, depletion and amortization
		U.S.	$	0.69	$	0.80	$	0.76
		Canada	$	—	$	1.50	$	0.87
		Total	$	0.69	$	0.94	$	0.81

Comparison of Years Ended December 31, 2001 and 2002.

        Revenues.    Our revenues from the sale of oil, natural gas and NGLs for the year ended December 31, 2002, increased by $5.2 million, or nearly 9%, to $66.4 million from $61.2 million for 2001. This increase in revenues is primarily attributable to increased production resulting from acquisitions made during the years ended 2001 and 2002. Our production of oil, natural gas and NGLs increased by 301,000 Bbls, 5.1 Bcf, and 152,000 Bbls, respectively, for the year ended December 31, 2002, compared to the year ended December 31, 2001. These increases are primarily attributable to our acquisitions of Addison Energy Inc., completed in late April 2001, the PrimeWest properties, completed in December 2001, the Medicine River properties, completed in April 2002, and the DJ Basin properties completed in November 2002. Production from these acquisitions during 2002 was 295,000 Bbls of oil, 3.5 Bcf of natural gas, and 139,000 Bbls of NGLs.

        The increase in revenue resulting from increased production was partially offset by lower prices received for oil, natural gas and NGLs. Our average oil, natural gas and NGL prices include the effects of quality, gathering and transportation costs as well as the effect of monthly oil and natural gas hedge settlements. Our average oil price received during the year ended December 31, 2002, was $20.50 per Bbl as compared to $24.17 per Bbl for 2001, which decreased revenue by $3.6 million. Our average natural gas price received during the year ended December 31, 2002, was $2.59 per Mcf as compared to $4.20 per Mcf for 2001, which decreased revenue by $13.4 million. Our average NGL price received during the year ended December 31, 2002, was $17.98 per Bbl as compared to $17.70 per Bbl for 2001, which increased revenue by less than $100,000.

        Our other income for the year ended December 31, 2002, was $6.6 million as compared to $5.7 million for 2001. This income primarily consisted of income from derivative ineffectiveness and terminated hedges, interest income, salt water disposal income and well supervision fees. The increase in other income was primarily attributable to $6.1 million in non-cash income from derivative

40

ineffectiveness and terminated hedges during the year ended December 31, 2002, compared to $4.8 million in non-cash income from derivative ineffectiveness and terminated hedges for 2001.

        Costs and Expenses.    Our total costs and expenses for the year ended December 31, 2002, decreased by $25.5 million to $80.8 million from $106.3 million for 2001. This decrease was mainly attributable to non-cash ceiling test write-downs of $49.6 million and the write-off of $10.7 million of derivative assets during 2001, compared to a ceiling test write-down of $17.5 million during 2002. The write-off of $10.7 million in 2001 represented 80% of the value of the Enron derivative asset as of November 30, 2001. This decrease was partially offset by increased expenses due to our acquisition of Addison Energy Inc., and our acquisition of the STB Energy, PrimeWest, Medicine River, and DJ Basin properties, and $1.1 million in impairment charges related to the value of marketable securities. We acquired the marketable securities in two companies prior to initiating discussions of potential business combinations with these companies.

        Our oil and natural gas production costs for the year ended December 31, 2002, increased $5.0 million, or 25%, to $24.8 million from $19.8 million for 2001. Our acquisition of the PrimeWest, Medicine River and the DJ Basin properties increased oil and natural gas production costs by $4.8 million. Oil and natural gas production costs on a unit of production basis decreased $0.24 per Mcfe to $1.08 per Mcfe for the year ended December 31, 2002, from $1.32 per Mcfe during 2001. The decrease in oil and natural gas production costs was primarily a result of the lower costs, on a unit of production basis, of our Canadian properties. Production and ad valorem taxes for the year ended December 31, 2002, increased by $274,000, or 6.6%, to $4.4 million from $4.1 million for 2001. Production and ad valorem taxes are generally based upon the price received for production and are not affected by monthly oil and natural gas hedge settlements. The increase in production and ad valorem taxes is primarily attributable to higher ad valorem taxes paid in Canada. There are no production taxes paid in Canada.

        Our depreciation, depletion and amortization costs for the year ended December 31, 2002, increased by $4.4 million, or 30%, to $18.6 million from $14.2 million for the same period in 2001, as a result of our acquisitions of Addison Energy Inc. and the PrimeWest, Medicine River and the DJ Basin properties. Depletion expense on production from these properties was approximately $5.2 million. This increase was partially offset by lower depletion rates due to non-cash ceiling test write-downs taken in the third and fourth quarters in 2001, and in the second quarter in 2002.

        Our general and administrative costs for the year ended December 31, 2002, increased by $6.2 million, or 128%, to nearly $11.0 million from $4.8 million for 2001. The increase in general and administrative costs was primarily attributable to our increased staffing needs as a result of our acquisitions of Addison Energy Inc. and the STB Energy, PrimeWest and Medicine River properties. Additionally, general and administrative costs increased as a result of legal costs incurred in pursuing our bankruptcy claim against Enron North America Corp. ($474,000); stock option compensation expense related to the Addison stock option plan ($1.4 million); and, costs incurred for financial and legal advisors we retained to evaluate the offer made by our chairman to purchase all of the outstanding shares of our stock that he does not already own ($659,000).

        Our interest expense for the year ended December 31, 2002, increased to $3.4 million from $3.1 million for 2001. This increase was primarily caused by higher average outstanding borrowings and higher interest rates during the year ended December 31, 2002, when compared to 2001. Our weighted average interest rate for the year ended December 31, 2002, was 4.38% compared to 3.95% for 2001.

        Under full cost accounting rules, we must compare the amount in our full cost pools (separate pools exist for the United States and Canada) to a ceiling test limit. In calculating future net revenues for the ceiling test limit, current prices and costs are generally held constant indefinitely. As a result of lower prices for Canadian natural gas at September 30, 2002, we had a pre-tax, non-cash write-down of our oil and natural gas properties of $17.5 million ($9.7 million after-tax) from our Canadian full cost

41

pool. As a result of low oil and natural gas prices at September 30, 2001 and December 31, 2001, we had pre-tax, non-cash ceiling test write-downs of our oil and natural gas properties during the year ended December 31, 2001, of $49.6 million of which $28.7 million was from our United States full cost pool and $20.9 million was from our Canadian full cost pool. Due to the volatility of oil and natural gas prices, it is possible that we will incur additional non-cash ceiling test write-downs in the future.

        Periodically, we invest in the marketable securities of other companies prior to initiating discussions of potential business combinations with those companies. At December 31, 2002, the cost of our investments in marketable securities was $2.7 million, which exceeded the market value of these securities on December 31, 2002, by $886,000. We consider these investments to be "available for sale", which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investment is "other than temporary." During the year ended December 31, 2002, we determined that a portion of the decline in the fair value of two of our investments in marketable securities was "other than temporary" and, as a result, we have recognized a non-cash pre-tax impairment expense of $1.1 million. At December 31, 2002, we have a net unrealized gain on marketable securities of $258,000 remaining in other comprehensive income.

        We have recorded a current income tax benefit of $2.7 million in the United States for the year ended December 31, 2002, to reflect a refund of taxes expensed and paid during 2001 and the expected refund of income taxes carried back to prior years for 2001 and 2002 taxable losses, after deducting intangible drilling costs. For the year ended December 31, 2002, we have not recorded any deferred income tax benefits or expense in the U.S., as it continues to be uncertain whether we will be able to utilize our net deferred tax asset. Accordingly, the tax effects of our U.S. generated income was offset by a reduction in our valuation allowance. Because of the deferred tax asset and resulting valuation allowance in the U.S., management expects tax expense on U.S. operations to be reduced in the near future. In Canada we have recorded a deferred tax benefit of $4.0 million. The deferred tax benefit is primarily the result of the non-cash ceiling test write-down on our Canadian full cost pool. We did not have any current income tax expense or benefit in Canada during 2002. We expect to continue to provide for taxes in Canada based upon the level of our Canadian income.

Comparison of Years Ended December 31, 2000 and 2001.

        Revenues.    Our revenues from the sale of oil, natural gas and NGLs for the year ended December 31, 2001, increased by $32.3 million, or 112%, to $61.2 million from $28.9 million for 2000. This increase resulted primarily from production increases of approximately 97,900 Bbls of oil, 2.7 Bcf of natural gas and 68,300 Bbls of NGLs from our acquisition of the STB Energy properties, completed in March 2001, and Addison, completed in April 2001. Additionally, our acquisition of the Central Resources properties, completed in September 2000, was included for the full year in 2001, as compared to four months during 2000.

        The increase in revenues was also attributable to higher natural gas prices that were partially offset by lower oil and NGL prices. Our average oil, natural gas and NGL prices include the effects of quality, gathering and transportation costs as well as the effect of monthly oil and natural gas hedge settlements. Our average oil price received during 2001 was $24.17 per Bbl as compared to $27.39 per Bbl for 2000, which decreased revenue by $1.3 million. Our average natural gas price received during 2001 was $4.20 per Mcf as compared to $3.72 per Mcf for 2000, which increased revenue by $2.1 million. Our average NGLs price received during 2001 was $17.70 per Bbl as compared to $24.60 per Bbl for 2000, which decreased revenue by $615,000.

        Our other income for 2001 was $5.7 million as compared to $1.8 million for 2000. This income primarily consisted of income from derivative ineffectiveness, income from hedges terminated prior to their expiration, interest income, salt water disposal income and well supervision fees. The increase in

42

other income was primarily attributable to $3.5 million from the ineffectiveness of derivative contracts and $1.3 million in income from hedges that we terminated prior to their expiration. See "Item 7A. Quantitative and Qualitative Disclosure About Market Risk" for a discussion of the accounting for terminated hedges in future periods.

        Costs and Expenses.    Our total costs and expenses for 2001 increased by $88.5 million to $106.3 million from $17.8 million for 2000. This increase was mainly attributable to (1) our acquisitions of the Central Resources properties, the STB Energy properties and Addison, (2) the non-cash ceiling test limitation write-downs of $49.6 million, and (3) the write-off of $10.7 million, which represents 80% of the value, as of November 30, 2001, of the Enron derivative assets.

        Our oil and natural gas production costs for 2001 increased by $12.4 million, or 165%, to $19.9 million from $7.5 million for 2000. Our acquisitions of the STB Energy properties and Addison increased oil and natural gas production costs by $3.3 million. Production and ad valorem taxes for 2001 increased by $2.1 million, or 105%, to $4.1 million from $2.0 million last year. Additionally, oil and natural gas production costs and production and ad valorem taxes related to our acquisition of the Central Resources properties were included for the full year, as compared to four months during 2000.

        Our depreciation, depletion and amortization costs for 2001 increased by $9.3 million, or 190%, to $14.2 million from $4.9 million for 2000. Our acquisitions of the STB Energy properties and Addison increased depreciation, depletion and amortization costs by $5.0 million. Additionally, depreciation, depletion and amortization costs related to our acquisition of the Central Resources properties were included for the full year, as compared to four months during 2000.

        Our general and administrative costs for 2001 increased by $2.8 million, or 140%, to $4.8 million from $2.0 million for 2000. The increase in general and administrative costs was primarily attributable to our increased staffing needs as a result of our acquisitions of the Central Resources properties, the STB Energy properties and Addison.

        Our interest expense for 2001 increased to $3.1 million from $1.4 million for 2000. This increase was primarily attributable to relatively high debt levels following the acquisitions of the STB Energy properties and Addison during the first half of 2001. These borrowings were repaid in June from the proceeds of the 5% convertible preferred stock offering.

        We acquired Addison in April 2001, and we also completed significant property acquisitions during the second half of 2000 and during 2001. Oil and natural gas prices trended higher throughout 2000, and were at historically high levels at December 31, 2000. During 2001, oil and natural gas prices decreased throughout most of the year. We evaluate acquisitions utilizing our best estimate of product prices and the amount of capital expenditures and operating expense to be incurred over the life of the reserves. Under full cost accounting rules, we must compare the amount in our full cost pools (separate pools exist for the United States and Canada) to a ceiling test limit. The ceiling test limit is calculated using product prices as of the last day of the fiscal quarter. Capital expenditures and operating expenses are calculated without any escalation for inflation. As a result of lower oil and natural gas prices at the end of both the third and fourth quarters of 2001, we had non-cash write-downs of our oil and natural gas properties of $49.6 million, of which $28.7 million was from our United States full cost pool and $20.9 million was from our Canadian full cost pool. At December 31, 2001, we used a realized oil price of $17.76 per Bbl, natural gas price of $2.23 per Mcf, and an NGLs price of $15.09 per Bbl, as the basis for determining the value of our reserves. We did not use our hedge contracts in determining reserve values.

        In connection with the incurrence of debt related to our acquisition activities and to protect against commodity price fluctuations, our management adopted a policy of hedging oil and natural gas prices through the use of commodity futures, options and swap agreements. During 2000 and through the third quarter of 2001, we entered into several hedging contracts with Enron North America. As a

43

result of the failure of Enron North America to make payments due us in December 2001, we terminated all of our hedging contracts with Enron North America. Prior to this termination, Enron North America and its parent, Enron Corp., filed for bankruptcy under Chapter 11 of the United States Code. We believe, based upon oil and natural gas prices on the date of termination, that we were owed approximately $15.3 million, including settlements already due, but the exact amount will be determined pursuant to the terms of the ISDA Master Agreement. As of November 30, 2001, we had recorded a $13.2 million derivative asset for oil and natural gas hedge derivatives from Enron North America. This amount, calculated in accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities", represents the estimated value of future monthly settlements to be received from the derivatives contracts. As a result of our termination of the derivatives contracts and the bankruptcy of the counterparty, we must record the derivative asset related to the oil and natural gas hedge derivatives from Enron North America at their estimated fair value. There currently exists an informal market for Enron North America's bankruptcy claims. Based upon informal offers that we have received from third parties attempting to purchase these claims, management currently believes the fair value of the derivative asset was approximately $2.8 million. As a result, we have written off to expense $10.7 million of the derivative asset for oil and natural gas hedge derivatives from Enron North America.

        Our effective tax rate in 2000 was 34%. In 2001, the effective rate was less than 1% due to the ceiling test write-downs and write-off of the Enron derivative asset. We could not utilize our net loss in the U.S. because it is uncertain whether we will be able to realize the deferred tax asset resulting from the ceiling test write-downs and the write-off of the Enron derivative asset

        Net Income (Loss).    We had a net loss for 2001 of $39.3 million representing $5.96 per basic share. During 2000, we had a net income of $8.5 million representing $1.23 per basic share and $1.18 per diluted share.

Our Liquidity, Capital Resources and Capital Commitments

General.

        Most of our growth has resulted from recent acquisitions and our development and exploitation program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash flow from operations, bank financing and the sale or issuance of equity securities to fund our operations, conduct development and exploitation activities, and to fund acquisitions. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity securities and borrowings under our credit agreements to raise cash to fund acquisitions. We cannot assure you that funds will be available to us in the future to meet our budgeted capital spending or to fund acquisitions. Furthermore, our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders. If we cannot secure additional funds for our planned development and exploitation activities or for future acquisitions, then we will be required to delay or substantially reduce these activities.

        During the year ended December 31, 2002, we increased our long-term debt by 118% to approximately $97.9 million at December 31, 2002. We generated cash flow from operations before changes in working capital during the year ended December 31, 2002 of approximately $26.3 million and approximately $31.7 million after changes in working capital, which helped fund our acquisition, development and exploitation activities. At December 31, 2002, our cash and cash equivalents balances increased by less than 5% from December 31, 2001. Working capital at December 31, 2002, decreased significantly from December 31, 2001, primarily because of changes in the value of our outstanding

44

hedge positions. Because product prices at December 31, 2002, were higher than at December 31, 2001, the value of our hedges have changed from a net asset to a net liability. We have also entered into new hedge contracts during 2002, for additional volumes to be delivered during 2003 and 2004, that also increased our net oil and natural gas hedge derivative liabilities.

        Prices for oil and natural gas have been volatile since December 31, 2002. The following table reflects the NYMEX closing price for the month indicated:

Month	Oil			Natural Gas
December 2002	$	31.20		$	4.79
January 2003	$	32.70		$	5.03
February 2003	$	35.73		$	5.50
March 2003		n/a	(1)	$	9.28

(1)

The March 2003 oil contract has not yet closed. The average price for the month through March 25, 2003, was $33.89.

        As a result of this volatility in prices, we have made cash payments of approximately $1.3 million for oil hedge settlements for January and February 2003 and approximately $6.0 million for natural gas hedge settlements for January, February and March 2003. These payments should be completely or partially offset by higher prices realized on the sale of oil and natural gas production. Additionally, the unrealized loss in the market value of our hedges as of February 28, 2003, based on quotes from our counterparties, has increased to approximately $27.6 million.

Acquisitions and Capital Expenditures.

        During the year ended December 31, 2002, we spent approximately $55.8 million on oil and natural gas property acquisitions. On April 29, 2002, Addison, our Canadian subsidiary, purchased oil and natural gas assets for approximately $25.8 million or CDN $40.5 million ($24.7 million or CDN $36.3 million after contractual adjustments). The transaction was funded with borrowings under our U.S. and Canadian credit agreements. On November 1, 2002, we purchased oil and natural gas properties located in the DJ Basin in Colorado for approximately $22.0 million ($21.1 million after contractual adjustments). The transaction was funded with $19.7 million of bank debt from our U.S. credit agreement and $1.4 million from surplus cash.

        We have planned development and exploitation activities for our major operating areas. We have budgeted up to $34.7 million for our development and exploitation activities in 2003, of which $12.3 million is for the United States and $22.4 million is for Canada. None of these planned capital expenditures are contractually required. In addition, we are continuing to evaluate oil and natural gas properties for future acquisitions. A variety of factors will determine the amount we ultimately spend during 2003 on acquisitions, development and exploitation activities, including prevailing prices for oil and natural gas, our expectations as to future pricing, the level of cash flow from operations, and the availability of additional debt and/or equity capital. If oil and natural gas prices drop significantly for an extended period of time, we may reduce our anticipated capital expenditure budget for 2003. We strive to maintain our indebtedness at moderate levels in order to provide sufficient financial flexibility to take advantage of future acquisition opportunities.

        See "Item 1.—Business—Investment Considerations and Risk Factors—We are exposed to operating hazards and uninsured risks" for a discussion of our inability to obtain well control insurance for our United States operations under terms we consider to be economical and the impact that this has had and may continue to have on our development and exploitation activities. We currently plan on spending the $12.3 million that has been budgeted for development and exploitation activities in the United States even if we do not obtain any well control insurance for our United States operations.

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        We expect to continue to utilize cash from operations, proceeds from the sale of oil and natural gas properties and funds available under our credit agreements to fund our acquisitions, capital expenditures and working capital during 2003. We believe that our capital resources from existing cash balances, cash flow from operating activities, and borrowing capacity under our credit agreements are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables, including production volumes, oil and natural gas prices and interest rates. If cash flows decline we would be required to reduce our capital expenditure budget, which in turn may affect our production in future periods. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures.

Credit Agreements.

        U.S. Credit Agreement.    Our restated U.S. credit agreement provides for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $82.0 million. Our borrowing base is determined based on a number of factors including commodity prices, however, we use hedges to lessen the impact of volatility in commodity prices. The borrowing base will be redetermined as of May 1, 2003, and each November 1 and May 1 thereafter. At December 31, 2002, we had approximately $34.4 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $47.3 million available for borrowing under our U.S. credit agreement. At February 28, 2003, we had $37.5 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $44.2 million available for borrowing. The U.S. credit agreement contains financial covenants and other restrictions that require us to maintain a minimum consolidated tangible net worth as well as financial ratios. As of December 31, 2002, we were in compliance with the covenants contained in the U.S. credit agreement. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At December 31, 2002, the six month LIBOR rate was 1.38%, which would result in an interest rate of approximately 2.63% on any new indebtedness we may incur under the U.S. credit agreement. At February 28, 2003, our weighted average cost of outstanding U.S. indebtedness was 2.64%.

        In connection with the merger, we have received a commitment letter from our lead bank to amend our U.S. credit agreement that will increase our U.S. borrowing base to $100 million. The U.S. borrowing base will be reduced to $92.5 million 90 days after the effective time of the merger, and will be further reduced by $7.5 million every 90 days thereafter until the next scheduled borrowing base redetermination. The amendment will also provide for an extension of the U.S. credit agreement maturity date. The new maturity date will be the third anniversary of the effective time of the merger. The commitment is subject to certain closing conditions outlined in the commitment letter.

        Canadian Credit Agreement.    Our restated Canadian credit agreement provides for borrowings of up to U.S. $157.5 million under a revolving credit facility with a borrowing base of U.S. $83.0 million. Our borrowing base is determined based on a number of factors including commodity prices, however, we use hedges to lessen the impact of volatility in commodity prices. The borrowing base will be redetermined as of May 1, 2003, and each November 1 and May 1 thereafter. At December 31, 2002, we had approximately U.S. $63.5 million of outstanding indebtedness and approximately U.S. $19.5 million available for borrowing under our Canadian credit agreement. At February 28, 2003, we had approximately U.S. $76.0 million of outstanding indebtedness and approximately U.S. $7.0 million available for borrowing. The Canadian credit agreement contains financial covenants and other restrictions that require us to maintain a minimum consolidated tangible net worth as well as financial ratios. As of December 31, 2002, we were in compliance with the covenants contained in the Canadian credit agreement. Borrowings under the credit agreement are secured by a first lien mortgage providing

46

a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin. At December 31, 2002, the six month Banker's Acceptance rate was 2.88%, which would result in an interest rate of approximately 4.38% on any new indebtedness we incur under the Canadian credit agreement. At February 28, 2003, our weighted average cost of outstanding Canadian indebtedness was 4.44%.

        In connection with the merger, we have received a commitment letter from our lead bank to amend our Canadian credit agreement that will increase our Canadian borrowing base to $100 million. The Canadian borrowing base will be reduced to $92.5 million 90 days after the effective time of the merger, and will be further reduced by $7.5 million every 90 days thereafter until the next scheduled borrowing base redetermination. The amendment will also provide for an extension of the Canadian credit agreement maturity date. The new maturity date will be the third anniversary of the effective time of the merger. The commitment is subject to certain closing conditions outlined in the commitment letter.

        Dividend restrictions.    We have not paid any cash dividends on our common stock, and we 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. If there were a default under our credit agreements, we will not be able to pay dividends on the shares of our 5% convertible preferred stock. Even if our credit agreements permitted us to pay cash dividends, we can make those payments only from our surplus which equals 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 were able to satisfy our liabilities as they become due. We cannot assure you that we will have any surplus.

        Financial covenants and ratios.    The U.S. and the Canadian credit agreements contain financial covenants and other restrictions that require that we:

•

maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;



•

maintain a minimum consolidated tangible net worth of not less than $48.0 million (adjusted upward by 50% of quarterly net income and 75% of the net proceeds from the issuance of any equity securities after April 26, 2001):



•

not permit the ratio of consolidated debt to consolidated total capital to be greater than 65% at the end of each fiscal quarter; and



•

not permit the ratio of indebtedness to earnings before interest expense, state and federal taxes, and depreciation, depletion and amortization expense to be more than 3.0 to 1.0 at the end of each fiscal quarter.

        We were in compliance with financial covenants and other restrictions under our U.S. and Canadian credit agreements at December 31, 2002.

Effects of the 5% Convertible Preferred Stock Offering.

        On June 29, 2001, we sold 5,004,869 shares of 5% convertible preferred stock. We raised approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions). We applied approximately $97.6 million of the offering proceeds to pay-off our bank loans that were incurred for the acquisition of producing oil and natural gas properties and for the acquisition of Addison, and have used the remaining proceeds for general corporate purposes.

        Dividends on our preferred stock, are payable quarterly beginning September 30, 2001, and are payable only in cash. Currently, the requirement for such dividend payments is approximately

47

$1.3 million per quarter. The board declared and we paid preferred stock dividends of $2.7 million during 2001 and $5.3 million during 2002. Each share of our 5% convertible preferred stock is convertible into one share of our common stock on or before June 30, 2003. Each share of 5% convertible preferred stock that has not been converted into our common stock by June 30, 2003, will be automatically converted into one share of our common stock on that date.

Common Stock.

        In conjunction with our purchase of Addison, the Addison managers agreed to purchase shares of our common stock with a portion of the proceeds they received from the sale of their common shares of Addison to us in April 2001. They purchased 24,940 shares in the open market worth $455,144. In addition, as part of the Addison purchase, the Addison managers purchased 49,880 shares for $910,310 directly from us. The resale of these shares is subject to restriction.

        As an incentive to the management and certain key employees of Addison, the board of directors of Addison established the Addison Energy Inc. Stock Option Plan effective June 30, 2002. Addison stock options were issued as of June 30, 2002, under the plan that, if fully exercised, would allow the participants to own in the aggregate 1,000 shares of Addison common stock, approximately 10% of the shares of common stock in Addison on a fully-diluted basis. The Addison stock options are exercisable for a term of five years from the date of the grant. The Addison stock options are subject to vesting. The vesting schedule is as follows:

Vesting Date	Cumulative Percent Vested
Prior to April 26, 2003	None
April 26, 2003	50%
April 26, 2004	75%
April 26, 2005	100%

The exercise price under the Addison stock option plan as of June 30, 2002 was CDN $1,031.61 per share. The price was determined by using a formula as set forth in the Addison stock option agreement. The formula is based upon:

•

The value of Addison's proved reserves;



•

The amount of any working capital surplus or deficiency;



•

Any capital contributions or distributions made after June 30, 2002;



•

Any debt owed to us, owed under the Canadian credit agreement or owed to other third parties;



•

The total exercise price of all outstanding Addison stock options under the plan;



•

The amount of deferred income tax liability incurred after June 30, 2002;



•

A calculated amount to allocate certain general and administrative costs that we incur that also benefit Addison; and



•

The ratio of the average trading price of our common stock divided by $18.25.

        This formula is to be calculated as of December 31 of each year, beginning December 31, 2002, to determine the value of each share of Addison's common stock.

        If an Addison stock option is exercised, we are obligated to purchase the shares of Addison common stock from the employee six months later at the then-current price as calculated using the above formula. Each employee receiving an Addison stock option has entered into an agreement that restricts their ability to sell or transfer any Addison common stock acquired under the Addison stock option plan to any party other than to us.

48

        The Addison stock options will become fully vested and exercisable if any of the following occurs:

•

A person, or a group of people acting together, has the right to cast more than 50% of the votes when electing our directors;



•

Our shareholders approve a merger or other transaction that would result in our shareholders owning less than 50% of the combined entity; or



•

We sell the shares of Addison or substantially all of its assets.

        At the time one of these events occurs, we are to perform the above calculation to determine the value of each share of Addison common stock as of the date of the event. We will then pay in cash the difference between the calculated value per share and the Addison stock option exercise price times the number of shares of Addison common stock that the participant has the right to purchase under the Addison stock option plan.

        The value of a share of Addison common stock was calculated to be CDN $7,013.94 per share as of December 31, 2002.

        During 2002, employees exercised stock options on a total of 90,366 shares of our common stock resulting in proceeds to us of approximately $1.0 million.

        On September 12, 2001, we announced that our board of directors authorized the purchase of a combined total of 1.5 million shares of our common stock and/or 5% convertible preferred stock. During 2001, we purchased 56,000 shares of our common stock at a cost of $761,000. During 2002, we purchased 188,500 shares of our common stock at a cost of $2.8 million. We have suspended the purchase of shares under this buyback program pending the outcome of our Chairman's announced proposal to acquire all of the outstanding shares of our common and 5% convertible preferred stock that he does not already own. Also during 2002, we reissued 7,512 shares of our common stock to our directors as part of our board of directors compensation plan. The value of the reissued shares was $106,000.

        On September 11, 1998 and November 29, 1999, we loaned Douglas H. Miller, our Chairman and Chief Executive Officer, a total of $915,625 to enable him to exercise stock options granted to him under our 1998 stock option plan. Of the outstanding loan balance, $465,625 plus accrued interest was due and payable on November 29, 2002, and $450,000 plus accrued interest was due and payable on September 15, 2004. Mr. Miller paid us all outstanding amounts owed under these loans on November 29, 2002. Under the terms of the Sarbanes-Oxley Act of 2002, we can no longer loan money to our executive officers or amend the terms of any agreements that were in place at the time the law was enacted.

        We have not paid any dividends on our common stock and we do not anticipate paying any cash dividends on our common stock in the foreseeable future.

Hedging Transactions.

        Our production is generally sold at prevailing market prices. However, we periodically enter into hedging transactions for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets. See the discussions in "Item 7A—Quantitative and Qualitative Disclosures About Market Risk."

        Our objective in entering into hedging transactions is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would

49

realize if prices increase. As of December 31, 2002, we had entered into the following contracts to hedge our natural gas and oil production under the following terms:

•

776,000-875,000 Mmbtus of natural gas per month from January 1, 2003 through December 31, 2003;



•

62,600 Bbls of oil per month from January 1, 2003 through December 31, 2003; and



•

20,000 Bbls of oil per month from January 1, 2004 through December 31, 2004.

        In January and February 2003, we entered into additional contracts to hedge our natural gas and oil production under the following terms:

•

468,300-513,300 Mmbtus of natural gas per month from January 1, 2004 through December 31, 2004; and



•

40,333-47,334 Bbls of oil per month from January 1, 2004 through December 31, 2004.

        We may use derivative instruments to manage exposure to commodity prices, foreign currency and interest rate risks. Our objectives for holding derivatives are to minimize risks using the most effective methods to eliminate or reduce the impacts of these exposures.

        We occasionally enter into commodity price swap derivatives to manage price risk for a portion of our oil and natural gas production. Commodity price swap derivative contracts are designated as cash flow hedges. As a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income and are recognized in the statement of income when the associated production occurs and the resulting cash flows are reported as cash flows from operations. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings. To qualify as a cash flow hedge, these swap contracts must be designated as cash flow hedges and changes in their fair value must correlate with changes in the price expected to be received on future production so that our exposure to the effects of commodity price changes is reduced.

Contractual Obligations and Commercial Commitments.

        The following table presents a summary of our contractual obligations at December 31, 2002, with set and determinable payments:

	Payments Due by Period
Contractual Obligations	1 Year or Less		2-3 Years		4-5 Years		After 5 Years		Total
	(In thousands)
Long-term debt	$	—	$	97,943	$	—	$	—	$	97,943
Operating leases		868		1,365		576		—		2,809
Drilling/work commitments		1,289		—		—		—		1,289
Preferred stock dividends		2,620		—		—		—		2,620
Total contractual cash obligations	$	4,777	$	99,308	$	576	$	—	$	104,661

        We also have $310,000 in letters of credit that have been issued to various state regulatory agencies and all of which expire in 2003. See "Item 7A.—Quantitative and Qualitative Disclosures About Market Risk," for discussion of our derivative positions.

50

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices, and interest rates charged on borrowings and earned on cash equivalent investments. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging purposes, not for trading purposes.

Commodity Price Risk.

        Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile.

        In connection with the incurrence of debt related to our acquisition activities and to protect against commodity price fluctuations to achieve a more predictable cash flow, management has adopted a policy of hedging oil and natural gas prices through the use of commodity futures, options and swap agreements. Effective January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activity," which established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. To date, we have only used cash flow hedges related to our anticipated production. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings. Hedge effectiveness is measured quarterly based on the relative fair value between the derivative contract and the hedged item over time. At adoption, we recognized a net derivative liability and a reduction in other comprehensive income of approximately $1.1 million as a cumulative effect of the accounting change for all cash flow hedges. Oil and natural gas revenues include the following from the settlement of cash flow hedges: net losses of $1.1 million for the year ended December 31, 2000; net gains of $6.3 million for the year ended December 31, 2001; and net losses of $7.7 million for the year ended December 31, 2002. During the years ended December 31, 2001 and 2002, we recognized a gain of $3.5 million and a loss of $886,000, respectively, in other income for hedging ineffectiveness.

51

        The following table sets forth our oil and natural gas hedging activities as of February 28, 2003. Our contracts are swap agreements for the sale of oil or natural gas based on NYMEX pricing.

Oil Swaps				Natural Gas Swaps
2003 Contract Period	Volumes (Bbls)	Weighted Average Strike Price		2003 Contract Period	Volumes (Mmbtus)	Weighted Average Strike Price
First Quarter	187,800	$	24.03 per Bbl	First Quarter	2,625,000	$	4.31 per Mmbtu
Second Quarter	187,800	$	24.03 per Bbl	Second Quarter	2,529,000	$	3.92 per Mmbtu
Third Quarter	187,800	$	24.03 per Bbl	Third Quarter	2,406,000	$	3.85 per Mmbtu
Fourth Quarter	187,800	$	24.03 per Bbl	Fourth Quarter	2,328,000	$	3.88 per Mmbtu

2004 Contract Period	Volumes (Bbls)	Weighted Average Strike Price		2004 Contract Period	Volumes (Mmbtus)	Weighted Average Strike Price
First Quarter	202,000	$	25.26 per Bbl	First Quarter	1,539,900	$	4.91 per Mmbtu
Second Quarter	193,750	$	24.62 per Bbl	Second Quarter	1,490,100	$	4.22 per Mmbtu
Third Quarter	187,000	$	24.18 per Bbl	Third Quarter	1,445,100	$	4.13 per Mmbtu
Fourth Quarter	181,000	$	23.93 per Bbl	Fourth Quarter	1,404,900	$	4.30 per Mmbtu

        In accordance with management's policy of hedging oil and natural gas prices, we entered into several swap transactions during 2000 and through September 2001. The counterparty of all of these swap transactions was Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern District of New York. We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001, as a result of the failure of the Enron affiliate to make payments totaling approximately $2.1 million due to us on December 5, 2001, on hedged natural gas volumes and on December 7, 2001, on hedged oil volumes. Based upon oil and natural gas futures prices on December 5, 2001, we believe that we are owed approximately $15.3 million, including settlements already due, but the exact amount will be determined pursuant to the terms of the ISDA Master Agreement.

        In accordance with the provisions of SFAS No. 133, we had recorded, as of November 30, 2001, a $13.2 million derivative asset on our balance sheet. This amount represented the estimated fair value of the future cash flows to us based upon the market price of oil and natural gas at that date. Due to the complex nature of the Enron bankruptcy proceedings and the extensive litigation involving Enron, we do not expect that we will receive any settlement as a result of the bankruptcies for an extended period of time; therefore, at December 31, 2001 and 2002, we have classified the Enron derivative asset as an other long-term asset and reduced the asset balance to approximately $2.8 million, which represents our estimate of the fair market value of our bankruptcy claim against Enron North America. Our estimate of the value of our bankruptcy claim is based upon informal offers that we have received from third parties attempting to purchase such claims as well as management's best estimate of the financial condition of Enron's bankruptcy estate as determined from published reports and court filings related to the bankruptcy. As a result, we charged $10.7 million to expense during 2001.

        As stated above, we terminated the Enron Hedges effective as of December 5, 2001. Under the requirements of SFAS No. 133, we are required to reclassify amounts related to the Enron Hedges that remain in other comprehensive income as of the date of the termination into revenue as the oil and natural gas volumes that were hedged are produced. During the years ended December 31, 2001 and 2002, we reclassified approximately $1.3 million and $7.0 million, respectively, related to the Enron Hedges from other comprehensive income to other income. At December 31, 2002, approximately

52

$2.1 million remained in other comprehensive income related to the Enron Hedges and will be reclassified into revenue as other income as shown in the following table:

	Amount
	(In thousands)
During 2003:
Quarter ending March 31, 2003	$	976
Quarter ending June 30, 2003		631
Quarter ending September 30, 2003		464
Total amount in 2003	$	2,071

        The following table sets forth our oil and natural gas hedges as of December 31, 2002. Our contracts are swap arrangements for the sale of oil and natural gas based upon NYMEX pricing. The market values at December 31, 2002, are estimated and are based on quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at December 31, 2002.

Commodity	Contract Date (1)	Effective Date	Termination Date	Notional Volume/Range Per Month (2)(3)	Aggregate Volume (2)(3)	Strike Price			Market Value at December 31, 2002 (4)
Natural Gas	3/12/2002	1/1/2003	12/31/2003	455,000 Mmbtus	5,460,000 Mmbtus	$	3.50		$	(5,858,928	)
Natural Gas	12/16/2002	1/1/2003	12/31/2003	321,000 Mmbtus - 420,000 Mmbtus	4,428,000 Mmbtus	$	4.61	(5)	$	90,258
Oil	4/5/2002	1/1/2003	12/31/2003	40,000 Bbls	480,000 Bbls	$	22.94		$	(1,893,760	)
Oil	9/5/2002	1/1/2003	12/31/2003	22,600 Bbls	271,200 Bbls	$	25.95		$	(261,730	)
Oil	9/5/2002	1/1/2004	12/31/2004	20,000 Bbls	240,000 Bbls	$	23.96		$	140,001

(1)

The counterparties to these contracts are BNP Paribas and Bank One, financial lending institutions and members of our U.S. and Canadian bank groups.

(2)

Bbls—Barrels.

(3)

Mmbtus—Million British thermal units.

(4)

On December 31, 2002, the average forward NYMEX oil prices for calendar 2003 and 2004, were $26.91 per Bbl and $23.36 per Bbl, respectively, and the average forward NYMEX natural gas price for calendar 2003 was $4.58 per Mmbtu.

(5)

Weighted average.

        A summary of the changes in the fair value of our hedging transactions during 2001 and 2002 follows (in thousands):

Fair value of contracts outstanding as of December 31, 2000	$	(1,068	)
Contracts realized or otherwise settled during the year		(10,687	)
Change in fair value of terminated Enron hedges		(13,192	)
Change in fair values of outstanding hedge positions		25,643
Fair value of contracts outstanding as of December 31, 2001		696
Contracts realized or otherwise settled during the year		8,197
Change in fair value of outstanding hedge positions		(16,677	)
Fair value of contracts outstanding as of December 31, 2002	$	(7,784	)

        At December 31, 2002, there was a net loss of approximately $7.1 million in other comprehensive income related to our oil and natural gas hedges. Based upon contractual volumes and current commodity prices we expect to reclassify $7.2 million as a reduction of oil and natural gas revenues during 2003.

53

        Oil and natural gas revenues for the years ended December 31, 2000, 2001 and 2002, include a net loss of $1.1 million, a net gain of $6.3 million, and a net loss of $7.7 million, respectively, from the settlement of cash flow hedges.

        Realized gains or losses from the settlement of the swaps are recorded in our financial statements as increases or decreases in oil and natural gas revenues. For example, using the oil swaps in place as of December 31, 2002, if the settlement price exceeded the actual weighted average strike price of $24.03, then a reduction in oil revenues would have been recorded for the difference between the settlement price and $24.03 multiplied by the actual notional volume. Conversely, if the settlement price was less than $24.03, then an increase in oil revenues would have been recorded for the difference between the settlement price and $24.03 multiplied by the notional volume. For example, for a notional volume of 62,600 Bbls, if the settlement price was $25.03, then oil revenues would have decreased by $62,600. Conversely, if the settlement price was $23.03, oil revenues would have increased by $62,600.

        We report average oil, natural gas and NGL prices including the effects of quality, gathering and transportation costs as well as the net effect of monthly oil and natural gas hedge settlements. The following table sets forth our oil, natural gas and NGL prices, both realized before monthly hedge settlements and realized including monthly hedge settlements, the net effects of the monthly settlements of our oil and natural gas price hedges on revenue, and effects of the amortization of gains attributable to gains recognized in prior periods from derivative ineffectiveness:

	Year Ended December 31,
	2000			2001		2002
	(In thousands, except per unit amounts)
Average price per Bbl of oil—realized before monthly hedge settlements	$	29.24		$	23.39	$	23.90
Average price per Bbl of oil—realized including monthly hedge settlements		27.39			24.17		20.50
Average price per Bbl of NGLs—realized before monthly hedge settlements		24.60			17.70		17.98
Average price per Bbl of NGLs—realized including monthly hedge settlements		24.60			17.70		17.98
Average price per Mcf of natural gas—realized before monthly hedge settlements		3.81			3.53		2.84
Average price per Mcf of natural gas—realized including monthly hedge settlements		3.72			4.20		2.59
Increase (reduction) in revenue of monthly hedge settlements		(1,141	)		6,273		(7,704	)

Interest Rate Risk.

        At December 31, 2002, our exposure to interest rates related primarily to borrowings under our credit agreements and interest earned on short-term investments. As of December 31, 2002, we were not using any derivatives to manage interest rate risk. Interest is payable on borrowings under the credit agreements based on a floating rate which can be locked-in for periods of up to three months, as more fully described in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources." If short-term interest rates would have averaged 1% higher during the year ended December 31, 2002, our interest expense would have increased by approximately $754,000. This amount was determined by applying the hypothetical interest rate change of 1% to our average outstanding borrowings under the credit agreements during the year ended December 31, 2002.

54

Equity Price Risk.

        Our investments in marketable securities are recorded at market value. We consider these investments to be "available for sale", which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investments is "other than temporary". During the year ended December 31, 2002, we determined that a portion of the decline in two of our investments in marketable securities was "other than temporary" and, as a result, we recognized a non-cash pre-tax impairment expense of $1.1 million. At December 31, 2002, the market value of our investments in marketable securities was $1.8 million. A temporary change in value of 10% would result in a $180,000 change in the market value and a corresponding adjustment to other comprehensive income of $180,000. An "other than temporary" decline in value of 10% would result in a $180,000 reduction in the market value and a corresponding non-cash pre-tax impairment expense of $180,000. As of December 31, 2002, we were not using any derivatives to manage equity price risk.

Foreign Currency Exchange Rate Risk.

        We account for a significant portion of our business in Canadian dollars. We are therefore subject to foreign currency exchange rate risk on cash flows of our Canadian operations that are not denominated in Canadian dollars. Presently, a significant portion of the sales of our Canadian oil and natural gas is denominated in U.S. dollars. Foreign currency exchange gains and/or losses related to these transactions have not been significant. The borrowings under our Canadian credit facility are denominated in Canadian dollars. The asset and liability balances of our Canadian business are translated monthly using current exchange rates, with any resulting unrealized translation gains or losses included in other comprehensive income. The unrealized foreign translation gain for the year ended December 31, 2002, was $708,000. As of December 31, 2002, we were not using any derivatives to manage foreign currency exchange rate risk.

Other Market Risk.

        We discontinued hedge accounting for our Enron derivatives effective November 30, 2001, and recognized a charge of $10.7 million for the impairment of the associated Enron derivative asset. At December 31, 2001 and 2002, we have valued our asset from Enron at $2.8 million, or approximately 20% of the value on the day we terminated our positions. This valuation is based on informal offers we have received for our position with Enron and other market information. We will continue to monitor activities related to Enron and may adjust the value of our derivative in the future based on new developments and market information.

55

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EXCO RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS
Contents

Audited Financial Statements		57
	Report of Independent Accountants	57
	Consolidated Balance Sheets	58
	Consolidated Statements of Operations	59
	Consolidated Statements of Cash Flows	60
	Consolidated Statements of Changes in Stockholders' Equity	61
	Consolidated Statements of Comprehensive Income	62
	Notes to Consolidated Financial Statements	63

56

REPORT OF INDEPENDENT ACCOUNTANTS

The Board of Directors
EXCO Resources, Inc.

        We have audited the accompanying consolidated balance sheets of EXCO Resources, Inc. as of December 31, 2001 and 2002, and the related consolidated statements of operations, cash flows, changes in stockholders' equity, and comprehensive income (loss) for each of the three years in the period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of EXCO Resources, Inc. at December 31, 2001 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States.

        As discussed in Note 1 to the consolidated financial statements, in 2001 EXCO Resources, Inc. adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities".

/s/ ERNST & YOUNG LLP

Dallas, Texas
February 28, 2003
except for Note 13, as to which the date is
March 11, 2003

57

EXCO RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

				December 31,
				2001			2002
				(In thousands, except share data)
Assets
Current assets:
	Cash and cash equivalents			$	1,856		$	1,942
	Accounts receivable:
		Oil and natural gas sales			6,151			12,299
		Joint interest			4,156			1,889
		Interest and other			3,563			7,343
	Oil and natural gas hedge derivatives				696			—
	Marketable securities				2,598			1,823
	Other				2,101			902
			Total current assets		21,121			26,198
Oil and natural gas properties (full cost accounting method):
	Unproved oil and natural gas properties				6,647			4,979
	Proved developed and undeveloped oil and natural gas properties				233,889			314,517
	Accumulated depreciation, depletion and amortization				(75,701	)		(109,545	)
	Oil and natural gas properties, net				164,835			209,951
Office and field equipment, net					966			1,030
Deferred financing costs					1,249			1,100
Oil and natural gas hedge derivatives					—			140
Other assets					2,885			2,755
			Total assets	$	191,056		$	241,174
Liabilities and Stockholders' Equity
Current liabilities:
	Accounts payable and accrued liabilities			$	11,008		$	21,821
	Revenues and royalties payable				2,186			3,353
	Accrued interest payable				128			95
	Oil and natural gas hedge derivatives				—			7,924
			Total current liabilities		13,322			33,193
Long-term debt					44,994			97,943
Deferred abandonment					1,466			2,176
Deferred income taxes					10,895			7,978
Commitments and contingencies					—			—
Stockholders' equity:
	Preferred stock, $.01 par value: Authorized shares—10,000,000 Issued and outstanding shares—5,004,869 at December 31, 2001 and 2002				101,175			101,175
	Common stock, $.02 par value: Authorized shares—25,000,000 Issued and outstanding shares—7,172,587 and 7,262,953 at December 31, 2001 and 2002, respectively				143			145
	Additional paid-in capital				51,138			53,107
	Deferred compensation				—			(705	)
	Notes receivable-employees				(1,117	)		(173	)
	Deficit eliminated in quasi-reorganization				(8,799	)		(8,799	)
	Retained deficit since December 31, 1997				(29,392	)		(35,600	)
	Accumulated other comprehensive income				8,096			(5,704	)
	Treasury stock, at cost: 67,446 and 248,434 shares at December 31, 2001 and 2002, respectively				(865	)		(3,562	)
			Total stockholders' equity		120,379			99,884
			Total liabilities and stockholders' equity	$	191,056		$	241,174

See accompanying notes.

58

EXCO RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

			Year Ended December 31,
			2000		2001			2002
			(In thousands, except per share amounts)
Revenues:
	Oil and natural gas		$	28,869	$	61,237		$	66,446
	Other income			1,252		5,567			6,654
	Gain on disposition of property, equipment and other assets			538		136			3
		Total revenues		30,659		66,940			73,103
Cost and expenses:
	Oil and natural gas production			9,484		23,914			29,223
	Depreciation, depletion and amortization			4,949		14,244			18,558
	General and administrative			2,003		4,806			10,968
	Interest			1,369		3,133			3,408
	Impairment of oil and natural gas properties			—		49,575			17,459
	Impairment of marketable securities			—		—			1,136
	Uncollectible value of Enron hedges			—		10,669			—
		Total cost and expenses		17,805		106,341			80,752
Income (loss) before income taxes				12,854		(39,401	)		(7,649	)
Income tax expense (benefit)				4,400		(54	)		(6,682	)
Net income (loss)				8,454		(39,347	)		(967	)
Dividends on preferred stock				—		2,653			5,256
Earnings (loss) on common stock			$	8,454	$	(42,000	)	$	(6,223	)
Basic earnings (loss) per share			$	1.23	$	(5.96	)	$	(0.88	)
Diluted income (loss) per share			$	1.18	$	(5.96	)	$	(0.88	)
Weighted average number of common and common equivalent shares outstanding:
	Basic			6,835		7,046			7,061
	Diluted			7,122		7,046			7,061

See accompanying notes.

59

EXCO RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Year Ended December 31,
			2000			2001			2002
			(In thousands)
Operating Activities:
Net income (loss)			$	8,454		$	(39,347	)	$	(967	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Depreciation, depletion and amortization			4,949			14,638			18,558
	Impairment of oil and natural gas properties			—			49,575			17,459
	Impairment of marketable securities			—			—			1,136
	Deferred income taxes			1,283			(1,211	)		(4,011	)
	Income from derivative ineffectiveness and terminated hedges			—			(4,147	)		(6,291	)
	Allowance for uncollectible value of Enron hedges			—			10,669			—
	Other, net			(538	)		(136	)		444
Cash flow before changes in working capital				14,148			30,041			26,328
	Effect of changes in:
		Accounts receivable		11,477			(470	)		(7,562	)
		Other current assets		(1,912	)		(2,655	)		1,310
		Accounts payable and other current liabilities		3,584			(1,000	)		11,584
Net cash provided by operating activities				27,297			25,916			31,660
Investing Activities:
Additions to oil and natural gas properties and equipment				(67,534	)		(90,876	)		(81,854	)
Acquisition of Addison Energy Inc.				—			(44,864	)		—
Investment in EXUS Energy, LLC				257			—			—
Other investing activities				(735	)		570			(172	)
Proceeds from disposition of property and equipment				1,493			1,399			5,089
Net cash used in investing activities				(66,519	)		(133,771	)		(76,937	)
Financing Activities:
Proceeds from long-term debt				50,536			165,463			70,356
Payments on long-term debt				(12,994	)		(162,484	)		(17,910	)
Proceeds from issuance of preferred stock				—			101,175			—
Principal and interest on notes receivable—employees				1			615			944
Deferred financing costs				(381	)		(1,731	)		(551	)
Proceeds from exercise of stock options and warrant				288			2,506			1,027
Purchases of treasury stock				—			(761	)		(2,802	)
Issuance of treasury stock				—			—			120
Preferred stock dividends				—			(2,653	)		(5,256	)
Net cash provided by financing activities				37,450			102,130			45,928
Net increase (decrease) in cash				(1,772	)		(5,725	)		651
Effect of exchange rates on cash and cash equivalents				—			(619	)		(565	)
Cash at beginning of year				9,972			8,200			1,856
Cash at end of year			$	8,200		$	1,856		$	1,942
Supplemental Cash Flow Information:
Interest paid			$	1,300		$	2,667		$	3,520
Income taxes paid			$	—		$	6,350		$	—

See accompanying notes.

60

EXCO RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

			5% Preferred Stock			Common Stock
														Notes Receivable- Officers and Employees
			Number of Shares	Amount		Number of Shares	Amount		Additional Paid-In Capital		Deferred Compensation						Deficit Eliminated			Retained Earnings (Deficit)			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity
			(In thousands)
Balance on December 31, 1999			—	$	—	6,805	$	136	$	46,941	$	—		$	(1,552	)	$	(8,799	)	$	4,154		$	—		$	—		$	40,880
	Interest income on notes receivable—officers		—		—	—		—		—		—			(105	)		—			—			—			—			(105	)
	Interest payment on notes receivable—officers		—		—	—		—		—		—			106			—			—			—			—			106
	Exercise of options		—		—	48		1		287		—			—			—			—			—			—			288
	Realization of deferred tax asset		—		—	—		—		72		—			—			—			—			—			—			72
	Realization of stock warrant value		—		—	—		—		200		—			—			—			—			—			—			200
	Purchase of treasury stock, at cost		—		—	—		—		—		—			—			—			—			(104	)		—			(104	)
	Net income		—		—	—		—		—		—			—			—			8,454			—			—			8,454
Balance on December 31, 2000			—		—	6,853		137		47,500		—			(1,551	)		(8,799	)		12,608			(104	)		—			49,791
	Issuance of 5% convertible preferred stock		5,005		101,175	—		—		—		—			—			—			—			—			—			101,175
	Exercise of stock options and warrant		—		—	270		5		2,682		—			—			—			—			—			—			2,687
	Issuance of restricted stock		—		—	50		1		909		—			—			—			—			—			—			910
	Realization of deferred tax asset		—		—	—		—		47		—			—			—			—			—			—			47
	Principal and interest payments on notes receivable—employees		—		—	—		—		—		—			615			—			—			—			—			615
	Notes issued by employees		—		—	—		—		—		—			(181	)		—			—			—			—			(181	)
	Purchase of treasury stock		—		—	—		—		—		—			—			—			—			(761	)		—			(761	)
	Dividends on preferred stock ($.53 per share)		—		—	—		—		—		—			—			—			(2,653	)		—			—			(2,653	)
	Net loss		—		—	—		—		—		—			—			—			(39,347	)		—			—			(39,347	)
	Other comprehensive income:
	Foreign currency translation adjustment		—		—	—		—		—		—			—			—			—			—			(1,646	)		(1,646	)
	Hedging activities:
		Cumulative effect of change in accounting principal	—		—	—		—		—		—			—			—			—			—			(1,068	)		(1,068	)
		Reclassification adjustments for settled contracts	—		—	—		—		—		—			—			—			—			—			(10,687	)		(10,687	)
		Changes in fair value of outstanding hedge positions	—		—	—		—		—		—			—			—			—			—			22,843			22,843
		Amortization of gains from terminated hedges	—		—	—		—		—		—			—			—			—			—			(1,346	)		(1,346	)
Balance on December 31, 2001			5,005		101,175	7,173		143		51,138		—			(1,117	)		(8,799	)		(29,392	)		(865	)		8,096			120,379
	Exercise of stock options		—		—	90		2		1,025		—			—			—			—			—			—			1,027
	Stock-based compensation expense		—		—	—		—		—		239			—			—			—			—			—			239
	Deferred compensation		—		—	—		—		944		(944	)		—			—			—			—			—			—
	Interest income on notes receivable—employees		—		—	—		—		—		—			(63	)		—			—			—			—			(63	)
	Principal and interest payments on notes receivable—employees		—		—	—		—		—		—			1,007			—			—			—			—			1,007
	Purchase of treasury stock		—		—	—		—		—		—			—			—			—			(2,802	)		—			(2,802	)
	Issuance of treasury stock		—		—	—		—		—		—			—			—			15			105			—			120
	Dividends on preferred stock ($1.05 per share)		—		—	—		—		—		—			—			—			(5,256	)		—			—			(5,256	)
	Net loss		—		—	—		—		—		—			—			—			(967	)		—			—			(967	)
	Other comprehensive income:
		Foreign currency translation adjustment	—		—	—		—		—		—			—			—			—			—			708			708
		Unrealized loss on equity investments	—		—	—		—		—		—			—			—			—			—			(878	)		(878	)
		Reclassification adjustments for impairment of marketable securities	—		—	—		—		—		—			—			—			—			—			1,136			1,136
	Hedging activities:
		Reclassification adjustments for settled contracts	—		—	—		—		—		—			—			—			—			—			8,197			8,197
		Changes in fair value of outstanding hedge positions	—		—	—		—		—		—			—			—			—			—			(15,987	)		(15,987	)
		Amortization of gains from terminated contracts	—		—	—		—		—		—			—			—			—			—			(6,976	)		(6,976	)
Balance on December 31, 2002			5,005	$	101,175	7,263	$	145	$	53,107	$	(705	)	$	(173	)	$	(8,799	)	$	(35,600	)	$	(3,562	)	$	(5,704	)	$	99,884

See accompanying notes.

61

EXCO RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

			Year Ended December 31,
			2000		2001			2002
			(In thousands)
Net income (loss)			$	8,454	$	(39,347	)	$	(967	)
Other comprehensive income (loss):
	Hedging activities:
		Cumulative effect of change in accounting principle — January 1, 2001		—		(1,068	)		—
		Effective changes in fair value		—		22,843			(15,987	)
		Reclassification adjustments for settled contracts		—		(10,687	)		8,197
		Amortization of terminated contracts		—		(1,346	)		(6,976	)
	Total hedging activities			—		9,742			(14,766	)
	Foreign currency translation adjustment			—		(1,646	)		708
	Reclassification adjustment for impairment of marketable securities			—		—			1,136
	Unrealized loss on equity investments			—		—			(878	)
Total comprehensive income (loss)			$	8,454	$	(31,251	)	$	(14,767	)

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.    Summary of Significant Accounting Policies

Organization

        EXCO Resources, Inc., (the Company), a Texas corporation, was formed in 1955. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States and Canada. We also act as the operator of some of these properties and receive overhead reimbursement fees as a result.

Principles of Consolidation

        The accompanying consolidated financial statements include the financial statements of EXCO Resources, Inc. and its subsidiaries. We accounted for our investment in Pecos-Gomez, L.P., which ceased operations during 2001 with all remaining net assets distributed to the partners, using the proportional method of consolidation. Under this method, only our combined 55.13742% interest in the partnership is reflected in the financial statements with no recording of minority interest. All inter-company transactions have been eliminated.

Functional Currency

        The assets, liabilities and operations of Addison Energy Inc. (Addison), our Canadian subsidiary, are measured using the Canadian dollar as the functional currency. These assets and liabilities are translated into U.S. dollars using end-of-period exchange rates. Revenue and expenses are translated into U.S. dollars at the average exchange rates in effect during the period. Translation adjustments are deferred and accumulated in other comprehensive income.

Quasi-Reorganization

        Effective December 31, 1997, we effected a quasi-reorganization by applying approximately $8.8 million of our additional paid-in capital account to eliminate our accumulated deficit. Our board of directors decided to effect a quasi-reorganization given the change in management, the infusion of new equity capital and an increase in activities. Our accumulated deficit was primarily related to past operations and properties that have been sold or abandoned. We did not adjust the historical carrying values of our assets and liabilities in connection with the quasi-reorganization.

Management Estimates

        In preparing financial statements in conformity with accounting principles generally accepted in the United States, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGL reserve volumes, future development, dismantlement and abandonment costs, valuation of deferred tax assets, estimates relating to certain oil, natural gas and NGL revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management's estimates.

Cash Equivalents and Marketable Securities

        We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.

        We have evaluated our investment policies in accordance with Statement of Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities" and

63

determined that all of our investment securities, other than cash equivalents, are to be classified as available for sale. Available for sale securities are carried at fair value, with the unrealized gains and losses reported in other comprehensive income. Realized gains and losses are included in other income on the consolidated statement of operations. Declines in value that are considered to be "other than temporary" on available for sale securities are shown separately on the consolidated statement of operations. Realized gains and losses are determined using the first-in, first-out method.

Concentration of Credit Risk and Accounts Receivable

        Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our hedging and derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. Substantially all of our accounts receivable are due from either purchasers of oil, natural gas or NGLs or participants in oil and natural gas wells for which we serve as the operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. Oil, natural gas and NGL sales are generally unsecured. We have provided for credit losses in the financial statements and these losses have been within management's expectations. The allowance for doubtful accounts receivable aggregated $111,000 and $220,000 at December 31, 2001 and 2002, respectively. We place our hedging and derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our hedging activities, please see "Note 9. Hedging Activities."

Hedging and Derivative Financial Instruments

        In connection with the incurrence of debt related to our acquisition activities and to protect against commodity price fluctuations to achieve a more predictable cash flow, our management has adopted a policy of hedging oil and natural gas prices whenever such prices are in excess of the prices anticipated in our operating budget and profit plan through the use of commodity futures, options and swap agreements. These derivatives are not held for trading purposes.

        We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. In accordance with the transition provisions of SFAS 133, we recorded a cumulative-effect loss in other comprehensive income of $1.1 million to recognize the fair value of our derivatives designated as cash-flow hedging instruments at the date of adoption.

        On the date the derivative contract is entered into, we designate the derivative as a hedge. All of our derivative instruments at December 31, 2000, 2001 and 2002, were designated as cash flow hedges. Changes in the fair value of a derivative that is highly effective as a cash flow hedge are recorded in other comprehensive income, until earnings are affected by the variability of cash flows.

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

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        We discontinue hedge accounting prospectively when: (1) it is determined that the derivative is no longer highly effective in offsetting changes in cash flows of a hedged item; (2) the derivative expires or is sold, terminated or exercised; (3) the derivative is not designated as a hedge instrument, because it is unlikely that a forecasted transaction will occur; or (4) management determines that designation of the derivative as a hedge instrument is no longer appropriate.

        When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with changes in its fair value recognized in current-period earnings. Amounts previously recognized in other comprehensive income will remain there until the previously hedged item affects earnings. Please see "Note 9. Hedging Activities" for a discussion of certain derivative transactions for which hedge accounting was discontinued during 2001.

        For the years ended December 31, 2001 and 2002, we recorded as other income in the statement of operations, a gain of $3.5 million and a loss of $886,000, respectively, from hedge ineffectiveness. For the years ended December 31, 2001 and 2002, we also recorded as other income in the statement of operations $1.3 million and $7.0 million, respectively, from derivative transactions for which hedge accounting was discontinued.

Oil and Natural Gas Properties

        We have recorded oil and natural gas properties at cost using the full cost method of accounting. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool. Capitalized costs are limited to the aggregate of the after-tax present value of future net revenues plus the lower of cost or fair market value of unproved properties.

        Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not proved reserves can be assigned to such properties. At December 31, 2001 and 2002, the $6.6 million and $5.0 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the purchase price of Canadian properties to undeveloped acreage and possible and probable reserves. We assess our unproved oil and natural gas properties for impairment on a quarterly basis.

        Depreciation, depletion and amortization of evaluated oil and natural gas properties is provided using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers.

        Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the amortization rate.

        At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). This calculation is done separately for the United States and Canadian full cost pools.

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        The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, and plan of development. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

        As a result of low oil and natural gas prices at September 30, 2001 and December 31, 2001, we recorded pre-tax non-cash ceiling test write-downs during the year ended December 31, 2001, totaling approximately $49.6 million (of which $28.7 million was from the United States full cost pool and $20.9 million was from the Canadian full cost pool). As a result of lower prices for Canadian natural gas at June 30, 2002, we had a pre-tax non-cash ceiling test write-down of our oil and natural gas properties during the second quarter of 2002 of $17.5 million ($9.7 million after-tax) from our Canadian full cost pool.

Office and Field Equipment

        Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives.

Deferred Abandonment and Asset Retirement Obligations

        Prior to 2003, we provided for future site restoration costs on our Canadian oil and natural gas properties based upon management's estimates. The costs were being recognized over the remaining life of proved reserves by a charge to depreciation, depletion and amortization in the statement of operations with a related increase in the non-current deferred abandonment liability. Actual expenditures for site restoration were charged to the deferred abandonment liability when incurred.

        In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We will adopt the new rules on asset retirement obligations on January 1, 2003, for both our U.S. and Canadian operations. Application of the new rules is expected to result in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.2 million, recognition of an asset retirement obligation liability of approximately $10.2 million, a reduction in deferred income tax liability of approximately $700,000, and a cumulative effect of adoption that will increase net income and stockholder's equity by approximately $1.7 million.

Revenue Recognition and Gas Imbalances

        We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2001 and 2002 were not significant; however, we have recorded a liability of $92,000 at December 31, 2002 for those wells where there are insufficient reserves to retire the imbalance.

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Capitalization of Internal Costs

        We capitalize as part of our proved developed and undeveloped oil and natural gas properties a portion of salaries paid to employees who are directly involved in the acquisition and exploitation of oil and natural gas properties. During the years ended December 31, 2000, 2001, and 2002, we have capitalized $500,000, $1.1 million, and $1.1 million, respectively.

Overhead Reimbursement Fees

        We have classified fees from overhead charges billed to working interest owners, including ourselves, of $1.5 million, $2.9 million and $2.9 million for the years ended December 31, 2000, 2001 and 2002, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. Our share of these charges were $894,000, $1.8 million and $1.8 million in 2000, 2001, and 2002, respectively, and are classified as oil and natural gas production costs.

Earnings Per Share

        SFAS No. 128, "Earnings per Share," requires presentation of two calculations of earnings per common share. Basic earnings per common share equals earnings on common stock divided by weighted average common shares outstanding during the period. Diluted earnings per common share equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents assumed to be issued. Common stock equivalents are shares assumed to be issued if our 5% convertible preferred stock were converted and our outstanding stock options and warrants, if any, were exercised.

        For the year ended December 31, 2000, employee and director stock options increased the weighted average number of shares outstanding by approximately 287,000 shares for the purpose of calculating diluted earnings per share. Since we reported a net loss for the years ended December 31, 2001 and 2002, our common stock equivalents are considered to be anti-dilutive and are not considered in the earnings per share calculation. For the year ended December 31, 2001, employee and director stock options, and our 5% convertible preferred stock would have increased the weighted average number of shares outstanding by approximately 469,000 shares and 2,537,000 shares, respectively. For the year ended December 31, 2002, employee and director stock options, and our 5% convertible preferred stock would have increased the weighted average number of shares outstanding by approximately 467,000 shares and 5,004,869 shares, respectively.

Stock Options and Benefit Plan

        SFAS No. 123, "Accounting for Stock-Based Compensation" defines a fair value based method of accounting for employee stock compensation plans, but allows for the continuation of the intrinsic value based method of accounting to measure compensation cost prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). For companies electing not to change their accounting, SFAS 123 requires pro forma disclosures of earnings and earnings per share as if the change in accounting provision of SFAS 123 has been adopted.

        We have elected to continue to utilize the accounting method prescribed by APB 25, under which no compensation cost has been recognized, and adopt the disclosure requirements of SFAS 123. As a result, SFAS 123 has no effect on our financial condition or our results of operations at December 31, 2000, 2001 and 2002. Stock based compensation expense reflected in the table below for the year ended

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December 31, 2002, is a result of options issued under our 1998 Stock Option Plan that were issued subject to our shareholders' approval and options that were issued to the management and key employees of Addison. See "Note 5. Stock Transactions" for a further description of these stock options.

        Had compensation costs for these plans been determined consistent with SFAS 123, our net income (loss) and earnings per share (EPS) would have been adjusted to the following pro forma amounts:

		December 31,
		2000		2001			2002
		(In thousands, except per share amounts)
Stock based compensation expense (net of taxes)	As Reported Pro Forma	$ $	— 678	$ $	— 1,118		$ $	991 2,487
Net income (loss)	As Reported Pro Forma	$ $	8,454 7,776	$ $	(39,347 (40,465	) )	$ $	(967 (2,463	) )
Basic EPS	As Reported Pro Forma	$ $	1.23 1.14	$ $	(5.96 (6.12	) )	$ $	(0.88 (1.09	) )
Diluted EPS	As Reported Pro Forma	$ $	1.18 1.09	$ $	(5.96 (6.12	) )	$ $	(0.88 (1.09	) )

        We sponsor a 401(k) plan for our U.S. employees and match employee contributions up to 6%. Our matching contributions of $44,000, $100,000 and $151,000 for the years ended December 31, 2000, 2001 and 2002, respectively, have been included as general and administrative expense.

Reclassified Prior Year Amounts

        Certain prior year amounts have been reclassified to conform to current year presentation.

2.    Marketable Securities

        Marketable securities at December 31, 2001 and 2002, consist primarily of common stock investments in public corporations, which are classified as available for sale securities. At December 31, 2001, our cost basis of marketable securities was $2.6 million while the aggregate fair value was $2.7 million. At December 31, 2002, our cost basis of marketable securities was $2.7 million while the aggregate fair value was $1.8 million.

        At December 31, 2002, we had gross unrealized holding gains from available for sale securities of $258,000. We had no gross unrealized holding losses from available for sale securities at December 31, 2002. Investment income is presented in the following table:

	December 31,
	2000		2001		2002
	(In thousands)
Gross realized gains from sales of marketable securities	$	15	$	107	$	—
Gross realized losses from sales of marketable securities		—		—		(1	)
Unrealized net loss included in other comprehensive income		—		—		(878	)
Reclassification adjustment for impairment of marketable securities		—		—		1,136

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3.    Long-Term Debt

        Long-term debt is summarized as follows:

	December 31,
	2001		2002
	(In thousands)
Notes payable	$	44,994	$	97,943
Less current maturities		—		—
Long-term debt	$	44,994	$	97,943

Credit Agreements

        We have a U.S. credit agreement and a Canadian credit agreement. The U.S. credit agreement is with Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and certain financial institutions as lenders. The Canadian credit agreement is with Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and certain financial institutions as lenders. The credit agreements mature on April 30, 2004.

        U.S. Credit Agreement.    Our restated U.S. credit agreement provides for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $82.0 million. The borrowing base is to be redetermined as of May 1, 2003, and each November 1 and May 1 thereafter. At December 31, 2002, we had approximately $34.4 million of outstanding indebtedness, letter of credit commitments of $310,000, and approximately $47.3 million available for borrowing under our U.S. credit agreement. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be either (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin.

        As part of the financing of the acquisition of Addison, the U.S. credit agreement provided for a bridge loan to us in the amount of $16.0 million. We repaid the $16.0 million borrowed under the bridge loan on June 29, 2001, from net proceeds from our 5% convertible preferred stock offering and from proceeds from the exercise of employee stock options and the 200,000 share warrant (see "Note 4. Stock Transactions"). By the terms of the U.S. credit agreement, we may not make any additional borrowings under the bridge loan after it has been repaid.

        Canadian Credit Agreement.    Our restated Canadian credit agreement provides for borrowings of up to U.S. $157.5 million under a revolving credit facility with a borrowing base of U.S. $83.0 million. The borrowing base is to be redetermined as of May 1, 2003, and each November 1 and May 1 thereafter. At December 31, 2002, we had approximately U.S. $63.5 million of outstanding indebtedness and approximately $19.5 million available for borrowing under our Canadian credit agreement. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be either (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin.

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        The U.S. and the Canadian credit agreements contain certain financial covenants and other restrictions which require that we:

•

maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;



•

maintain a minimum consolidated tangible net worth of not less than $48.0 million (adjusted upward by 50% of quarterly net income and 75% of the net proceeds from the issuance of any equity securities after April 26, 2001);



•

not permit the ratio of consolidated debt to consolidated total capital to be greater than 65% at the end of each fiscal quarter; and



•

not permit the ratio of indebtedness to earnings before interest expense, state and federal taxes, and depreciation, depletion and amortization expense to be more than 3.0 to 1.0 at the end of each fiscal quarter.

        Additionally, the credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and prohibit the payment of dividends on our common stock. As of December 31, 2002, we were in compliance with the covenants contained in the U.S. and Canadian credit agreements.

        Dividend Restrictions.    We have not paid any cash dividends on our common stock, and we 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. If there is a default under our credit agreements, we will not be able to pay dividends on the shares of our 5% convertible preferred stock. Even if our credit agreements permitted 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 pay our liabilities as they become due.

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4.    Income Taxes

        The income tax provision attributable to our income (loss) before income taxes consists of the following:

			December 31,
			2000		2001			2002
			(In thousands)
Current:
	U.S.		$	2,200	$	1,157		$	(2,672	)
	Canadian			—		—			—
				2,200		1,157			(2,672	)
Deferred:
	U.S.			2,200		(1,211	)		—
	Canadian			—		—			(4,010	)
				2,200		(1,211	)		(4,010	)
		Total income tax (benefit)	$	4,400	$	(54	)	$	(6,682	)

        We have net operating loss carryforwards (NOLs) for income tax purposes that have either been generated from our operations or were purchased in our acquisitions. These NOLs begin to expire in 2003. Our ability to use the purchased NOLs has been significantly restricted because of a change in our ownership, which occurred December 19, 1997, as well as the change in ownership of Rio Grande, Inc. which occurred on March 16, 1999. We estimate that approximately $4.9 million of the purchased NOLs will become available in the future at the rate of approximately $460,000 per year. For financial reporting purposes, a valuation allowance has been recognized to offset the deferred tax assets related to carryforwards prior to our quasi-reorganization. When realized, the tax benefit for those carryforwards will be credited to additional paid-in capital. In 2002, no such amounts were recognized. In addition, a valuation allowance has been recognized to offset all of our remaining U.S. deferred tax assets, including the NOLs generated from our operations.

        We have not provided any U.S. deferred income taxes on the undistributed earnings of our Canadian subsidiary based upon the determination that at this time those earnings will be indefinitely reinvested in Canada. As of December 31, 2002, there were no material cumulative undistributed earnings of this subsidiary.

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        Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:

		December 31,
		2000			2001			2002
		(In thousands)
Deferred tax assets:
Net operating loss carryforwards—United States		$	1,984		$	1,814		$	2,719
Tax basis of oil and natural gas properties in excess of book basis—United States			—			3,280			771
Basis difference in fair value of hedges			—			2,482			(48	)
Credit carryforwards			5			2			5
Other			13			41			46
Valuation allowance for deferred tax assets			(1,306	)		(7,619	)		(3,493	)
	Total deferred tax assets		696			—			—
Deferred tax liabilities:
Book basis of oil and natural gas properties in excess of tax basis—United States			1,907			—			—
Book basis of oil and natural gas properties in excess of tax basis—Canada			—			10,895			7,978
	Total deferred tax liabilities		1,907			10,895			7,978
	Net deferred tax liabilities	$	1,211		$	10,895		$	7,978

        A reconciliation our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the years ended December 31, 2000, 2001 and 2002, is presented in the following table:

		December 31,
		2000			2001			2002
		(In thousands)
United States federal income taxes (benefit) at statutory rate of 34%		$	4,374		$	(13,396	)	$	(2,601	)
Increases (reductions) resulting from:
	Adjustments to the valuation allowance		(422	)		6,313			(4,126	)
	Rate difference on foreign taxes		—			—			(860	)
	Non-deductible charges		—			7,928			675
	Other		448			(899	)		230
Tax provision		$	4,400		$	(54	)	$	(6,682	)

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5.    Stock Transactions

Issuance of Common Stock

        During the year ended December 31, 2000, two of our directors and three of our employees exercised stock options covering 48,000 shares of our common stock, 46,375 at a strike price of $6.00 per share and 1,625 shares at $6.25 per share. We received net proceeds of approximately $288,400 for these shares all of which was paid in cash.

        During the year ended December 31, 2001, 17 of our employees, one of whom is also a director, exercised stock options covering 69,511 shares of our common stock at strike prices ranging from $6.00 per share to $15.125 per share. We received aggregate proceeds of approximately $486,600 for these shares with $305,600 paid in cash and $181,000 being borrowed from us.

        During the year ended December 31, 2002, 24 of our employees exercised stock options covering 90,366 shares of our common stock at strike prices ranging from $6.00 per share to $15.50 per share. We received aggregate proceeds of approximately $1,026,200 for these shares all of which was paid in cash.

        In 1998 and 1999, we loaned Douglas H. Miller, our Chairman and Chief Executive Officer, a total of $915,625 in order to enable him to exercise stock options granted to him under our 1998 stock option plan. Of the outstanding balance, $465,625 plus accrued interest was due and payable on November 29, 2002, and $450,000 plus accrued interest was due and payable on September 15, 2004. Mr. Miller paid us all outstanding amounts owed under these loans on November 29, 2002. Under the terms of the Sarbanes-Oxley Act of 2002, we can no longer loan money to our executive officers or amend the terms of any agreements that were in place at the time the law was enacted. At December 31, 2002, we had one executive officer with an outstanding loan balance of $60,000. This loan is due on May 18, 2004, and was used to exercise stock options granted under our 1998 Stock Option Plan.

        The following table summarizes our stock option activity:

		Stock Options		Weighted Average Exercise Price Per Share
Options outstanding at December 31, 1999		1,066,709		$	6.02
	Granted	414,637		$	13.77
	Expired or canceled	(34,747	)	$	6.01
	Exercised	(48,000	)	$	6.01
Options outstanding at December 31, 2000		1,398,599		$	8.32
	Granted	761,625		$	14.55
	Expired or canceled	(40,933	)	$	14.88
	Exercised	(69,511	)	$	7.00
Options outstanding at December 31, 2001		2,049,780		$	10.55
	Granted	172,668		$	16.10
	Expired or canceled	(82,251	)	$	13.64
	Exercised	(90,366	)	$	11.36
Options outstanding at December 31, 2002		2,049,831		$	10.85
Options exercisable at December 31, 2002		1,502,086		$	9.42

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        The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used:

Fair market value of stock at date of grant	$6.00 to $20.62
Option exercise prices	$6.00 to $20.62
Option term	10 years
Risk-free rate of return	10-year U.S. Treasury Notes
Company stock volatility	Based upon daily stock prices from January 1, 2000 through December 31, 2002
Company dividend yield	0%
Calculated Black-Scholes values	$2.60 to $8.94 per option

        See "Note 1. Summary of Significant Accounting Policies—Stock Options" for a comparison of our net loss and net loss per share as reported and as adjusted for the pro forma effects of determining compensation expense in accordance with SFAS 123.

        As part of the consideration paid for the acquisition of the Central Properties, we issued a warrant to Central Resources, Inc. to purchase 200,000 shares of our common stock for $11.00 per share. This warrant was assigned and then exercised on May 21, 2001, for the full 200,000 shares at which time we received $2.2 million cash. We filed a registration statement on Form S-3 with the SEC to register the resale of the 200,000 shares of common stock issued upon the exercise of the warrant. The registration statement was declared effective by the SEC on October 15, 2001.

        As an incentive to the management and certain key employees of Addison, the board of directors of Addison established the Addison Energy Inc. Stock Option Plan effective June 30, 2002. Addison stock options were issued as of June 30, 2002, under the plan that, if fully exercised, would allow the participants to own in the aggregate 1,000 shares of Addison common stock, approximately 10% of the shares of common stock in Addison on a fully-diluted basis. The Addison stock options are exercisable for a term of five years from the date of the grant. The Addison stock options are subject to vesting. The vesting schedule is as follows:

Vesting Date	Cumulative Percent Vested
Prior to April 26, 2003	None
April 26, 2003	50%
April 26, 2004	75%
April 26, 2005	100%

The exercise price under the Addison stock option plan as of June 30, 2002 was CDN $1,031.61 per share. The price was determined by using a formula as set forth in the Addison stock option agreement. The formula is based upon:

•

The value of Addison's proved reserves;



•

The amount of any working capital surplus or deficiency;



•

Any capital contributions or distributions made after June 30, 2002;

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•

Any debt owed to us, owed under the Canadian credit agreement or owed to other third parties;



•

The total exercise price of all outstanding Addison stock options under the plan;



•

The amount of deferred income tax liability incurred after June 30, 2002;



•

A calculated amount to allocate certain general and administrative costs that we incur that also benefit Addison; and



•

The ratio of the average trading price of our common stock divided by $18.25.

        This formula is to be calculated as of December 31 of each year, beginning December 31, 2002, to determine the value of each share of Addison's common stock.

        If an Addison stock option is exercised, we are obligated to purchase the shares of Addison common stock from the employee six months later at the then-current price as calculated using the above formula. Each employee receiving an Addison stock option has entered into an agreement that restricts their ability to sell or transfer any Addison common stock acquired under the Addison stock option plan to any party other than to us.

        The Addison stock options will become fully vested and exercisable if any of the following occurs:

•

A person, or a group of people acting together, has the right to cast more than 50% of the votes when electing our directors;



•

Our shareholders approve a merger or other transaction that would result in our shareholders owning less than 50% of the combined entity; or



•

We sell the shares of Addison or substantially all of its assets.

        At the time one of these events occurs, we are to perform the above calculation to determine the value of each share of Addison common stock as of the date of the event. We will then pay in cash the difference between the calculated value per share and the Addison stock option exercise price times the number of shares of Addison common stock that the participant has the right to purchase under the Addison stock option plan.

        The value of a share of Addison common stock was calculated to be CDN $7,013.94 per share as of December 31, 2002.

        The following table summarizes our Addison stock option activity:

		Stock Options	Weighted Average Exercise Price Per Share
Options outstanding at December 31, 2001		0	CDN $        —
	Granted	1,000	CDN $  1,031.61
	Expired or canceled	0	—
	Exercised	0	—
Options outstanding at December 31, 2002		1,000	CDN $  1,031.61

        During the year ended December 31, 2002, we recognized U.S. $1.4 million as stock-based compensation expense for the Addison stock option plan.

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Issuance of Preferred Stock

        We are authorized to issue up to 10,000,000 shares of preferred stock, $.01 par value per share, that the board of directors may issue from time to time in one or more series. With respect to each series of preferred stock, the board is authorized to fix and determine by resolution the number of shares of each series, the designation thereof and all rights and preferences including voting, dividend, conversion, redemption and liquidation rights.

        On June 29, 2001, we closed our rights offering to existing shareholders that resulted in the sale of 5,004,869 shares of 5% convertible preferred stock at $21.00 per share. We raised a total of approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions), through the exercise of 4,466,869 rights and the sale of 538,000 shares of 5% convertible preferred stock by dealer managers. We applied approximately $97.6 million of the offering proceeds to pay-off our bank loans and have used the remaining proceeds for general corporate purposes. Dividends on our 5% convertible preferred stock are payable quarterly in cash. Currently, the requirement for such dividend payment is approximately $1.3 million per quarter beginning September 30, 2001. During 2001, preferred stock dividends of approximately $2.7 million were paid. During 2002, preferred stock dividends of approximately $5.3 million were paid. Each share of 5% convertible preferred stock is convertible into one share of our common stock, at the option of the holder, on or before June 30, 2003. On June 30, 2003, each outstanding share of 5% convertible preferred stock will be automatically converted into one share of our common stock.

        The remaining authorized but unissued shares of preferred stock are available for future equity financings through issuance to the general public, future acquisitions, stock dividends or splits or for other corporate purposes for which the issuance of preferred shares may be advisable.

6.    Commitments and Contingencies

        We lease our offices and certain equipment. Our rental expenses were approximately $202,000, $476,000 and $728,000 for 2000, 2001 and 2002, respectively. Our future minimum rental payments under operating leases with remaining noncancellable lease terms at December 31, 2002, are as follows:

	Amount
	(In thousands)
2003	$	868
2004		715
2005		650
2006		345
Thereafter		230
	$	2,808

7.    Environmental Regulation

        Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the near future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these

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laws and regulations are constantly being changed, we are unable to predict the conditions and other factors, over which we do not exercise control, that may give rise to environmental liabilities affecting us.

8.    Geographic Operating Segment Information and Oil and Natural Gas Disclosures

        We have operations in only one industry segment, that being the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have reportable operations in the United States and Canada. The following tables provide our geographic operating segment data. Operating segment data represents Canadian activity beginning April 26, 2001, when we acquired Addison Energy Inc.

        The following table presents total capitalized costs of proved and unproved properties, accumulated depreciation, depletion and amortization related to oil and natural gas production, and total assets:

		United States			Canada			Total
		(In thousands)
As of December 31, 2000:
Oil and natural gas properties		$	90,586		$	—		$	90,586
Accumulated depreciation, depletion and amortization			(10,231	)		—			(10,231	)
Oil and natural gas properties, net		$	80,355		$	—		$	80,355
	Total assets	$	102,372		$	—		$	102,372
As of December 31, 2001:
Oil and natural gas properties		$	135,306		$	105,230		$	240,536
Accumulated depreciation, depletion and amortization			(48,006	)		(27,695	)		(75,701	)
Oil and natural gas properties, net		$	87,300		$	77,535		$	164,835
	Total assets	$	109,682		$	81,374		$	191,056
As of December 31, 2002:
Oil and natural gas properties		$	165,058		$	154,438		$	319,496
Accumulated depreciation, depletion and amortization			(56,581	)		(52,964	)		(109,545	)
Oil and natural gas properties, net		$	108,477		$	101,474		$	209,951
Total assets		$	130,829		$	110,345		$	241,174

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        Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities:

	United States		Canada		Total
	(In thousands, except per unit amounts)
2000:
Property acquisition costs	$	66,270	$	—	$	66,270
Development costs		847		—		847
Production costs		9,484		—		9,484
Depreciation, depletion and amortization per Boe	$	4.18	$	—	$	4.18
Depreciation, depletion and amortization per Mcfe	$	0.69	$	—	$	0.69
2001:
Property acquisition costs	$	29,471	$	84,576	$	114,047
Development costs		14,977		8,858		23,835
Production costs		21,395		2,519		23,914
Depreciation, depletion and amortization per Boe	$	4.82	$	9.07	$	5.65
Depreciation, depletion and amortization per Mcfe	$	0.80	$	1.50	$	0.94
2002:
Property acquisition costs	$	23,049	$	32,783	$	55,832
Development costs		10,554		15,468		26,022
Production costs		19,020		10,203		29,223
Depreciation, depletion and amortization per Boe	$	4.56	$	5.20	$	4.85
Depreciation, depletion and amortization per Mcfe	$	0.76	$	0.87	$	0.81

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8.    Geographic Operating Segment Information and Oil and Natural Gas Disclosures (Continued)

        The results of operations from our oil and natural gas producing activities are as follows:

	United States			Canada			Corporate and Other			Total
	(In thousands)
Year ended December 31, 2000:
Oil and natural gas sales	$	28,869		$	—		$	—		$	28,869
Other income		—			—			1,790			1,790
		28,869			—			1,790			30,659
Production costs		(9,484	)		—			—			(9,484	)
Depreciation, depletion and amortization		(4,949	)		—			—			(4,949	)
General and administrative		—			—			(2,003	)		(2,003	)
Interest		—			—			(1,369	)		(1,369	)
		(14,433	)		—			(3,372	)		(17,805	)
Income (loss) before income taxes		14,436			—			(1,582	)		12,854
Income tax expense (benefit)		4,908			—			(508	)		4,400
Net income (loss)	$	9,528		$	—		$	(1,074	)	$	8,454
Year ended December 31, 2001:
Oil and natural gas sales	$	53,017		$	8,220		$	—		$	61,237
Income from derivative ineffectiveness and terminated hedges		4,147			—			—			4,147
Other income		—			—			1,556			1,556
		57,164			8,220			1,556			66,940
Production costs		(21,395	)		(2,519	)		—			(23,914	)
Depreciation, depletion and amortization		(9,743	)		(4,501	)		—			(14,244	)
General and administrative		—			—			(4,806	)		(4,806	)
Interest		—			—			(3,133	)		(3,133	)
Impairment of oil and natural gas properties		(28,646	)		(20,929	)		—			(49,575	)
Uncollectible value of Enron hedges		(10,669	)		—			—			(10,669	)
		(70,453	)		(27,949	)		(7,939	)		(106,341	)
Income (loss) before income taxes		(13,289	)		(19,729	)		(6,383	)		(39,401	)
Income tax expense (benefit)		(4,518	)		(8,799	)		13,263			(54	)
Net income (loss)	$	(8,771	)	$	(10,930	)	$	(19,646	)	$	(39,347	)

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Year ended December 31, 2002:
Oil and natural gas sales	$	34,254		$	32,192		$	—		$	66,446
Income from derivative ineffectiveness and terminated hedges		6,090			—			—			6,090
Other income		—			—			567			567
		40,344			32,192			567			73,103
Production costs		(19,020	)		(10,203	)		—			(29,223	)
Depreciation, depletion and amortization		(9,529	)		(9,029	)		—			(18,558	)
General and administrative		—			—			(10,968	)		(10,968	)
Interest		—			—			(3,408	)		(3,408	)
Impairment of oil and natural gas properties		—			(17,459	)		—			(17,459	)
Impairment of marketable securities		—			—			(1,136	)		(1,136	)
		(28,549	)		(36,691	)		(15,512	)		(80,752	)
Income (loss) before income taxes		11,795			(4,499	)		(14,945	)		(7,649	)
Income tax expense (benefit)		4,010			(2,007	)		(8,685	)		(6,682	)
Net income (loss)	$	7,785		$	(2,492	)	$	(6,260	)	$	(967	)

9.    Hedging Activities

        In connection with the incurrence of debt related to our acquisition activities and to protect against commodity price fluctuations, management has adopted a policy of hedging oil and natural gas prices through the use of commodity futures, options and swap agreements. Effective January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activity," which established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings. Hedge effectiveness is measured quarterly based on the relative fair value between the derivative contract and the hedged item over time. At adoption, we recognized a net derivative liability and a reduction in other comprehensive income of

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approximately $1.1 million as a cumulative effect of an accounting change for all of our cash flow hedges in place at that time.

        In accordance with management's policy of hedging oil and natural gas prices, we entered into several swap transactions during 2000, and through September 2001. The counterparty of all of these swap transactions was Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern District of New York. We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001, as a result of the failure of the Enron affiliate to make payments totaling approximately $2.1 million due us on December 5, 2001, on hedged natural gas volumes and on December 7, 2001, we believe that we are owed approximately $15.3 million, including settlements already due, but the exact amount will be determined pursuant to the terms of the ISDA Master Agreement.

        In accordance with the provisions of SFAS No. 133, we had recognized, as of November 30, 2001, a $13.2 million derivative asset on our balance sheet. This amount represented the estimated fair value of the future cash flows to us based upon the market price of oil and natural gas at that date. Due to the complex nature of the Enron bankruptcy proceedings and the extensive litigation involving Enron, we do not expect that we will receive any settlement as a result of the bankruptcies for an extended period of time, if at all; therefore, at December 31, 2001, we classified the Enron derivative asset as an other long-term asset and reduced the asset balance to $2.8 million, which represented our estimate of the fair market value of our bankruptcy claim against Enron North America. As a result, we charged $10.7 million to expense during 2001. Our estimate of the value of our bankruptcy claim is based upon informal offers that we have received from third parties attempting to purchase those claims as well as management's best estimate of the financial condition of Enron's bankruptcy estate as determined from published reports and court filings related to the bankruptcy.

        As stated above, we terminated hedge accounting for the Enron Hedges effective as of November 30, 2001. Under the requirements of SFAS No. 133, we are required to reclassify amounts related to the Enron Hedges that remain in other comprehensive income as of the date of the termination into revenue as the oil and natural gas volumes that were hedged are produced. During the years ended December 31, 2001 and 2002, we reclassified approximately $1.3 million and $7.0 million, respectively, related to the Enron Hedges from other comprehensive income to other income. At December 31, 2002, approximately $2.1 million remained in other comprehensive income related to the Enron Hedges and will be reclassified into other income as shown in the following table:

	Amount
	(In thousands)
During 2003:
Quarter ending March 31, 2003	$	976
Quarter ending June 30, 2003		631
Quarter ending September 30, 2003		464
Total amount in 2003	$	2,071

        The following table sets forth our oil and natural gas hedges as of December 31, 2002. Our contracts are swap arrangements for the sale of oil and natural gas based upon NYMEX pricing. The

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market values at December 31, 2002, are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at December 31, 2002.

Commodity	Contract Date (1)	Effective Date	Termination Date	Notional Volume/Range Per Month (2)(3)	Aggregate Volume (2)(3)	Strike Price			Market Value at December 31, 2002 (4)
Natural Gas	3/12/2002	1/1/2003	12/31/2003	455,000 Mmbtus	5,460,000 Mmbtus	$	3.50		$	(5,858,928	)
Natural Gas	12/16/2002	1/1/2003	12/31/2003	321,000 Mmbtus - 420,000 Mmbtus	4,428,000 Mmbtus	$	4.61	(5)	$	90,258
Oil	4/5/2002	1/1/2003	12/31/2003	40,000 Bbls	480,000 Bbls	$	22.94		$	(1,893,760	)
Oil	9/5/2002	1/1/2003	12/31/2003	22,600 Bbls	271,200 Bbls	$	25.95		$	(261,730	)
Oil	9/5/2002	1/1/2004	12/31/2004	20,000 Bbls	240,000 Bbls	$	23.96		$	140,001

(1)

The counterparties to these contracts are BNP Paribas and Bank One, financial lending institutions and members of our U.S. and Canadian bank groups.

(2)

Bbls—Barrels.

(3)

Mmbtus—Million British thermal units.

(4)

On December 31, 2002, the average forward NYMEX oil prices for calendar 2003 and 2004 were $26.91 per Bbl and $23.36 per Bbl, respectively, and the average forward NYMEX natural gas price for calendar 2003 was $4.58 per Mmbtu.

(5)

Weighted average.

        At December 31, 2002, there was a net loss of approximately $7.1 million in other comprehensive income related to our oil and natural gas hedges. Based upon contractual volumes, we expect to reclassify $7.2 million as a reduction of oil and natural gas revenues during 2003.

        Oil and natural gas revenues for the years ended December 31, 2000, 2001 and 2002, include a net loss of $1.1 million, a net gain of $6.3 million and a net loss of $7.7 million, respectively, from the settlement of cash flow hedges. For the years ended December 31, 2001 and 2002, other income included a gain of $3.5 million and a loss of $886,000, respectively, from hedge ineffectiveness.

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10.    Acquisitions and Dispositions

        We have accounted for the following acquisitions in accordance with APB No. 16, "Business Combinations" and SFAS 141 where applicable.

Entity	Transactions in 2000	Event Date
EXCO Resources, Inc.	Purchased Val Verde County Properties	February 25, 2000
	Purchased Central Properties	September 22, 2000
Pecos-Gomez, L.P.	Purchased Pecos County Properties	March 24, 2000

Entity	Transactions in 2001	Event Date
EXCO Resources, Inc.	Purchased STB Energy Properties	March 8, 2001
EXCO Resources, Inc.	Purchased Addison Energy Inc.	April 26, 2001
EXCO Resources, Inc.	Purchased additional interests in Pecos County Properties	July 3, 2001
Addison Energy Inc.	Purchased PrimeWest Properties	December 18, 2001

Entity	Transactions in 2002	Event Date
Addison Energy Inc.	Purchased Medicine River Properties	April 29, 2002
EXCO Resources, Inc.	Purchased DJ Basin Properties	November 1, 2002

        Significant transactions which closed during 2001 are more fully described below.

STB Energy Properties Acquisition.

        On March 8, 2001, we acquired from STB Energy, Inc. oil and natural gas properties located in Louisiana, Oklahoma, Texas and Nebraska. As of January 1, 2001, estimated total proved reserves net to our interest included approximately 694,000 Bbls of oil and 9.5 Bcf of natural gas from 125 gross (78.3 net) wells. The purchase price consisted of $15.0 million in cash ($14.8 million after contractual adjustments).

Addison Energy Inc. Acquisition.

        On April 26, 2001, we acquired all of the outstanding common stock of Addison Energy Inc. (Addison), which is headquartered in Calgary, Alberta, Canada. At the date of acquisition, Addison owned interests in 95 gross (85.03 net) wells located in Alberta and Addison operated 91 of these wells. The Addison properties included approximately 27,672 gross and 23,994 net developed acres and approximately 38,947 gross and 28,795 net undeveloped acres. As of January 1, 2001, estimated total proved reserves net to our interest acquired in this acquisition included approximately 2.1 million Bbls of oil and NGLs and 36.9 Bcf of natural gas. After adjustments for working capital and long-term debt, we paid approximately $44.4 million (CDN $68.5 million) for Addison. We paid the adjusted purchase price from the proceeds of borrowings under our new U.S. and Canadian credit agreements. The price was determined through arms-length negotiation between the parties.

Pecos County Properties Acquisitions.

        On March 24, 2000, Pecos-Gomez, L.P. (previously known as Humphrey-Hill, L.P.) (the Partnership) acquired 8 gross (4.25 net) producing wells in Pecos County, Texas for $10.2 million. As of January 1, 2000, the acquired properties were estimated to contain total proved reserves of 25.1 Bcf of natural gas. At the time of the acquisition, EXCO was the general partner of the Partnership and

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owned a 1% interest in the Partnership as the general partner and a 50% interest as a limited partner. The acquisition price was partially funded from the proceeds of a credit facility established by the Partnership with Bank of America, N.A. On May 16, 2000, EXCO acquired an additional 4.1% limited partnership interest in the Partnership. On July 3, 2001, the Partnership conveyed all of its oil and natural gas property interests to its partners and began the process to dissolve the Partnership. Also on July 3, 2001, EXCO acquired additional interests in the properties from two of the limited partners for $8.8 million (approximately $7.5 million after contractual adjustments). In addition, EXCO received an assignment of the existing Partnership hedge contract. Borrowings under the Partnership credit facility of $3.9 million were also repaid at the time of the acquisition and the credit facility was canceled.

PrimeWest Properties Acquisition.

        On December 18, 2001, Addison, our Canadian subsidiary, acquired oil and natural gas properties located in Alberta, Canada. As of December 31, 2001, total proved reserves net to our interest included approximately 3.6 million barrels of oil and NGLs, and 27.1 Bcf of natural gas. Estimated daily production, net to our interest, in December 2001, was approximately 600 barrels of oil and NGLs, and 4,100 Mcf of natural gas from the acquired properties. The effective date of this transaction was December 18, 2001. The purchase price was approximately $33.8 million or CDN $53.6 million cash ($33.6 million or CDN $53.3 million after contractual adjustments), funded with borrowings under our Canadian credit agreement.

        Significant transactions which closed during 2002 are more fully described below.

Medicine River Properties Acquisition.

        On April 29, 2002, Addison 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.

DJ Basin Properties Acquisition.

        On November 1, 2002, we acquired oil and natural gas properties located in the DJ Basin in Colorado. As of October 1, 2002, estimated total proved reserves net to our interest included approximately 2.1 Mmbbls 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 cash ($21.1 million after contractual adjustments), funded with $19.7 million of bank debt from our U.S. credit agreement and $1.4 million from surplus cash.

Pro Forma Results of Operations.

        The following reflects the pro forma results of operations as though the acquisition of the STB Energy Properties, Addison Energy Inc., and the PrimeWest Properties, the related borrowings and our

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5% convertible preferred stock offering had been consummated on January 1, 2001. The remaining acquisitions were all less than 20% of our total assets when purchased.

		Year Ended December 31,
		2001			2002
		(In thousands, except per share data) (Unaudited)
Revenues		$	86,008		$	73,103
Earnings (loss) on common stock		$	(38,077	)	$	(6,223	)
Income (loss) per share before extraordinary item:
	Basic	$	(5.29	)	$	(0.88	)
	Diluted	$	(5.29	)	$	(0.88	)

11.    Concentration of Credit Risk

        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. 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 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.

        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. During 2000, sales of oil and natural gas to three purchasers, Western Gas Resources, Inc., Plains All American, Inc. and Oneok Gas Marketing, LLC accounted for 23.6%, 19.9% and 11.9%, respectively, of our total oil and natural gas revenues.

12.    Acquisition Proposal

        We announced on August 7, 2002, that our Chairman and Chief Executive Officer, Douglas H. Miller, made an offer to purchase all of the outstanding shares of our stock not already owned by Mr. Miller. Mr. Miller currently owns approximately 8.2% of our outstanding common stock and 1.8% of our outstanding 5% convertible preferred stock.

        Under the terms of that offer, the holders of our outstanding shares of common stock would have received $17.00 per share in cash. The holders of our outstanding 5% convertible preferred stock would have received between $17.00 and $18.05 per share in cash depending upon the closing date of the acquisition transaction, which price we were advised took into account the remaining stated dividends at the time the offer was made and the mandatory conversion of the 5% convertible preferred stock on June 30, 2003.

        Our board of directors established a special committee comprised of J. Michael Muckleroy and Stephen F. Smith to consider the proposal, and to evaluate, negotiate and make a recommendation to

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our full board on the proposal. The special committee retained Bracewell & Patterson, L.L.P. as its legal advisor and Merrill Lynch & Co. as its financial advisor to assist it in evaluating the proposal from Mr. Miller and other proposals it receives. The proposal from Mr. Miller was made subject to the negotiation and execution of a definitive acquisition agreement containing mutually agreeable terms and conditions as are customary in such agreements, including but not limited to customary representations, warranties, covenants and conditions. It was also subject to, among other things, (1) the approval of the transaction by the special committee, our board of directors and our shareholders, (2) receipt of satisfactory financing for the transaction, (3) receipt of a fairness opinion by the special committee, and (4) the receipt of all necessary regulatory approvals.

        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.

        On December 30, 2002, we announced that we had received a revised proposal for the acquisition of the company by Mr. Miller and his group. The revised proposal increased the consideration for the common stock to $18.00 per share and the consideration for the 5% convertible preferred stock to between $18.00 per share and $18.525 per share, depending upon the date of the closing. The revised proposal took into account the remaining stated dividends at the time the offer was made and the mandatory conversion of the 5% convertible preferred stock on June 30, 2003.

13.    Subsequent Event

        On March 11, 2003, the special committee recommended approval, our board of directors resolved to submit to our shareholders, and we entered into an Agreement and Plan of Merger providing for the merger of ER Acquisitions, Inc., a Texas corporation, and a wholly-owned subsidiary of EXCO Holdings Inc., a Delaware corporation, into EXCO. Following the completion of the merger, ER Acquisitions, Inc. will cease to exist as a separate entity, and EXCO will continue as the surviving corporation of the merger and as a wholly-owned subsidiary of EXCO Holdings, Inc. Upon consummation of the merger transaction, our common stock and 5% convertible preferred stock could

86

be delisted from trading on the NASDAQ National Market or any other exchange and the common stock and the 5% convertible preferred stock could become eligible for termination of registration pursuant to Secion 12(g)(4) of the Securities Exchange Act of 1934.

14.    Supplemental Oil and Natural Gas Reserves and Standardized Measure Information (Unaudited)

        We retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil, natural gas and NGL reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves that we may recover through existing wells. Proved undeveloped reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.

        Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

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Estimated Quantities of Proved Reserves

		United States						Canada						Total
		Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)		Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)		Oil (Bbls)		Natural Gas (Mcf)		NGLs (Bbls)		Mcfe(1)
		(In thousands)
December 31, 1999		2,744		16,548		370		—		—		—		2,744		16,548		370		35,232
	Purchase of reserves in place	10,043		80,279		126		—		—		—		10,043		80,279		126		141,293
	New discoveries and extensions	—		—		—		—		—		—		—		—		—		—
	Revisions of previous estimates	93		2,543		112		—		—		—		93		2,543		112		3,773
	Production	(433	)	(3,982	)	(89	)	—		—		—		(433	)	(3,982	)	(89	)	(7,114	)
	Sales of reserves in place	(69	)	(944	)	(54	)	—		—		—		(69	)	(944	)	(54	)	(1,682	)
December 31, 2000		12,378		94,444		465		—		—		—		12,378		94,444		465		171,502
	Purchase of reserves in place	809		23,463		329		3,137		63,901		2,539		3,946		87,364		2,868		128,248
	New discoveries and extensions	79		72		—		318		4,611		198		397		4,683		198		8,253
	Revisions of previous estimates	(1,200	)	(956	)	98		425		6,978		160		(775	)	6,022		258		2,920
	Production	(887	)	(6,243	)	(96	)	(80	)	(2,086	)	(68	)	(967	)	(8,329	)	(164	)	(15,115	)
	Sales of reserves in place	(126	)	(524	)	(9	)	—		—		—		(126	)	(524	)	(9	)	(1,334	)
December 31, 2001		11,053		110,256		787		3,800		73,404		2,829		14,853		183,660		3,616		294,474
	Purchase of reserves in place	1,781		18,844		—		1,201		25,839		1,002		2,982		44,683		1,002		68,587
	New discoveries and extensions	339		7,774		105		323		17,867		643		662		25,641		748		34,101
	Revisions of previous estimates	502		12,777		299		829		(2,850	)	(238	)	1,331		9,927		61		18,279
	Production	(869	)	(6,878	)	(74	)	(399	)	(6,565	)	(242	)	(1,268	)	(13,443	)	(316	)	(22,947	)
	Sales of reserves in place	(525	)	(1,175	)	(20	)	—		—		—		(525	)	(1,175	)	(20	)	(4,445	)
December 31, 2002		12,281		141,598		1,097		5,754		107,695		3,994		18,035		249,293		5,091		388,049

Estimated Quantities of Proved Developed Reserves

	United States			Canada			Total
	Oil (Bbls)	Natural Gas (Mcf)	NGLs (Bbls)	Oil (Bbls)	Natural Gas (Mcf)	NGLs (Bbls)	Oil (Bbls)	Natural Gas (Mcf)	NGLs (Bbls)	Mcfe(1)
	(In thousands)
December 31, 2000	8,148	66,497	465	—	—	—	8,148	66,497	465	118,175
December 31, 2001	7,555	87,868	774	3,414	65,230	2,470	10,969	153,098	3,244	238,376
December 31, 2002	9,067	115,222	985	5,425	92,512	3,432	14,492	207,734	4,417	321,188

(1)

Mcfe—Thousand cubic feet equivalent by converting 1 Bbl of oil to 6 Mcf of natural gas.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14.    Supplemental Oil and Natural Gas Reserves and Standardized Measure Information (Unaudited) (Continued)

Standardized Measure of Discounted Future Net Cash Flows

        We have summarized the standardized measure of discounted net cash flows related to our proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to proved reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

	United States		Canada		Total
	(In thousands)
Year ended December 31, 2000:
Future cash inflows	$	1,192,705	$	—	$	1,192,705
Future production and development costs		344,013		—		344,013
Future income taxes		274,899		—		274,899
Future net cash flows		573,793		—		573,793
Discount of future net cash flows at 10% per annum		291,357		—		291,357
Standardized measure of discounted future net cash flows	$	282,436	$	—	$	282,436
Year ended December 31, 2001:
Future cash inflows	$	453,313	$	280,001	$	733,314
Future production and development costs		225,167		122,212		347,379
Future income taxes		41,855		47,345		89,200
Future net cash flows		186,291		110,444		296,735
Discount of future net cash flows at 10% per annum		103,206		50,000		153,206
Standardized measure of discounted future net cash flows	$	83,085	$	60,444	$	143,529
Year ended December 31, 2002:
Future cash inflows	$	997,524	$	683,969	$	1,681,493
Future production and development costs		375,879		223,372		599,251
Future income taxes		294,387		175,700		470,087
Future net cash flows		327,258		284,897		612,155
Discount of future net cash flows at 10% per annum		174,335		127,480		301,815
Standardized measure of discounted future net cash flows	$	152,923	$	157,417	$	310,340

        At December 31, 2002, the present value of our future net cash flows before income taxes discounted at 10% was approximately $530.0 million.

        During recent years, prices paid for oil and natural gas have fluctuated significantly. The prices of oil, natural gas and NGLs at December 31, 2000, 2001 and 2002 used in the above table, were $24.82, $17.76 and $29.56 per Bbl of oil, respectively, $9.26, $2.23 and $4.12 per Mcf of natural gas, respectively, and $21.50, $15.09 and $21.96 per Bbl of NGLs, respectively.

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Changes in Standardized Measure

        The following are the principal sources of change in the standardized measure of discounted future net cash flows:

	United States			Canada			Total
	(In thousands)
Year ended December 31, 2000:
Sales and transfers of oil and natural gas produced, net of production costs	$	(20,526	)	$	—		$	(20,526	)
Net changes in prices and production costs		233,572			—			233,572
Extensions and discoveries, net of future development and production costs		—			—			—
Development costs during the period		352			—			352
Changes in estimated future development costs		550			—			550
Revisions of previous quantity estimates		9,880			—			9,880
Sales of reserves in place		(4,740	)		—			(4,740	)
Purchases of reserves in place		155,648			—			155,648
Accretion of discount before income taxes		3,595			—			3,595
Net change in income taxes		(124,490	)		—			(124,490	)
Net change	$	253,841		$	—		$	253,841
Year ended December 31, 2001:
Sales and transfers of oil and natural gas produced, net of production costs	$	(25,348	)	$	(5,701	)	$	(31,049	)
Net changes in prices and production costs		(344,892	)		(54,809	)		(399,701	)
Extensions and discoveries, net of future development and production costs		607			6,112			6,719
Development costs during the period		8,340			8,858			17,198
Changes in estimated future development costs		4,356			—			4,356
Revisions of previous quantity estimates		(6,499	)		6,836			337
Sales of reserves in place		(1,062	)		—			(1,062	)
Purchases of reserves in place		41,547			114,120			155,667
Accretion of discount before income taxes		10,147			8,380			18,527
Net change in income taxes		113,453			(23,352	)		90,101
Net change	$	(199,351	)	$	60,444		$	(138,907	)
Year ended December 31, 2002:
Sales and transfers of oil and natural gas produced, net of production costs	$	(22,971	)	$	(21,954	)	$	(44,925	)
Net changes in prices and production costs		90,164			31,336			121,500
Extensions and discoveries, net of future development and production costs		23,415			35,888			59,303
Development costs during the period		7,063			16,121			23,184
Changes in estimated future development costs		2,979			24,281			27,260
Revisions of previous quantity estimates		25,806			981			26,787
Sales of reserves in place		(1,705	)		—			(1,705	)
Purchases of reserves in place		29,228			50,908			80,136
Accretion of discount before income taxes		28,384			24,595			52,979
Net change in income taxes		(112,525	)		(65,183	)		(177,708	)
Net change	$	69,838		$	96,973		$	166,811

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15.    Selected Quarterly Financial Information (Unaudited)

	2002
	March 31		June 30			September 30			December 31
	(In thousands, except per share amounts)
Total revenues	$	14,648	$	17,128		$	17,701		$	23,626
Earnings (loss) on common stock		752		(9,117	)		(510	)		2,652
Basic earnings (loss) per share		0.10		(1.28	)		(0.07	)		0.37
Diluted income (loss) per share		0.10		(1.28	)		(0.07	)		0.37
Total assets		198,033		214,764			210,874			241,174
Long-term debt, less current maturities		51,945		84,865			80,235			97,943
Stockholders' equity		111,076		100,815			95,482			99,884

	2001
	March 31		June 30		September 30			December 31
	(In thousands, except per share amounts)
Total revenues	$	13,663	$	17,870	$	18,032		$	17,375
Impairment of oil and natural gas properties		—		—		45,942			3,633
Uncollectible value of Enron hedges		—		—		—			10,669
Earnings (loss) on common stock		2,962		2,821		(38,819	)		(8,964	)
Basic earnings (loss) per share		0.43		0.40		(5.41	)		(1.25	)
Diluted income (loss) per share		0.40		0.37		(5.41	)		(1.25	)
Total assets		121,421		224,240		166,885			191,056
Long-term debt, less current maturities		56,157		2,151		1,361			44,994
Stockholders' equity		54,137		170,822		133,370			120,379

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

        None.

PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors and Executive 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.

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.

Jeffrey D. Benjamin, 41, has been one of our directors since August 1998. Mr. Benjamin has been a Senior Advisor to Apollo Management, LP since September 2002. He had previously been a Managing Director of Libra Securities LLC, an investment banking firm since January 2002 and served in various capacities, including Co-Chief Executive Officer of Libra Securities and its predecessors since May 1998. From May 1996 to May 1998, Mr. Benjamin was Managing Director at UBS Securities LLC, an investment banking firm. Mr. Benjamin is also a Director of McLeod USA Incorporated, Dade Behring Holdings Inc., Chiquita Brands International, Inc. and NTL Incorporated.

Earl E. Ellis, 61, has been one of our directors since March 1998. Mr. Ellis is currently a private investor. He served as a Director of Coda from 1992 until 1996. Mr. Ellis served as a managing partner of Benjamin Jacobson & Sons, LLC, specialists on the New York Stock Exchange. He had been associated with Benjamin Jacobson & Sons, LLC from 1977 to 2001.

J. Michael Muckleroy, 72, has been one of our directors since March 1998. He is currently an independent oil and gas producer and acts as manager of his family's stock portfolios. Mr. Muckleroy served as President of Houston Natural Gas Liquids from 1984 until the end of 1985. From 1985 until his retirement in 1993, Mr. Muckleroy served as Chairman and Chief Executive Officer of Enron Liquid Fuels.

Boone Pickens, 74, has been one of our directors since March 1998. Mr. Pickens is currently the Chairman and CEO of BP Capital LP and Mesa Water, Inc. and is a board member of ENRG. BP Capital LP or affiliates is the general partner and an investment advisor of private funds investing in energy commodities (BP Capital Energy Fund) and publically-traded energy equities (BP Capital Equity Fund and its offshore counterpart). ENRG is the largest provider of natural gas (CNG and LNG) and related services in North America. He was the founder of Mesa Petroleum Co., an independent oil and natural gas exploration and production company. He served as CEO and Chairman of the Board of Mesa from its inception until his departure in 1996.

Stephen F. Smith, 61, has been one of our directors since March 1998. From 1980 to present, Mr. Smith has been co-founder and Executive Vice President of Sandefer Oil and Gas, Inc., an

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independent oil and gas exploration and production company. Prior to 1980, Mr. Smith was an Audit Partner with Arthur Andersen LLP.

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.

Section 16(a) Beneficial Ownership Reporting Compliance

        Section 16(a) of the Securities Exchange Act of 1934 requires the company's executive officers, directors and persons who own more than 10% of the company's stock to file reports with the Securities and Exchange Commission and to provide us with copies of ownership and changes in ownership. The SEC regulations require the company to identify anyone who filed a required report after the filing deadline during the most recent fiscal year. Based upon a review of our records, we believe that all 2002 filing requirements were timely met.

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ITEM 11.    EXECUTIVE COMPENSATION

Summary Compensation Table

        The following table provides compensation information for the fiscal years 2000, 2001 and 2002 for the company's Chief Executive Officer, Douglas H. Miller, and the four most highly compensated executive officers other than Mr. D. H. Miller: T. W. Eubank, J. Douglas Ramsey, Richard E. Miller and Charles R. Evans.

		Annual Compensation						Long-Term Compensation Awards
Name and Principal Position	Fiscal Year	Salary		Bonus		Other Annual Compensation		Common Stock Underlying Options	All Other Compensation
		($)		($)		($)		(# of shares)	($)(1)
Douglas H. Miller Chairman and Chief Executive Officer	2002 2001 2000	$ $ $	300,000 300,000 100,000	$ $ $	30,000 30,000 20,000	$ $ $	— — —	— 30,000 10,000	$ $ $	9,600 6,300 4,200
T. W. Eubank President and Treasurer	2002 2001 2000	$ $ $	200,000 200,000 100,000	$ $ $	20,000 20,000 20,000	$ $ $	— — —	— 20,000 10,000	$ $ $	8,800 6,300 4,000
J. Douglas Ramsey Vice President and Chief Financial Officer	2002 2001 2000	$ $ $	150,000 150,000 100,000	$ $ $	15,000 15,000 20,000	$ $ $	— — —	— 15,000 10,000	$ $ $	8,800 6,300 4,200
Richard E. Miller Vice President, Secretary and General Counsel	2002 2001 2000	$ $ $	150,000 150,000 125,000	$ $ $	15,000 15,000 25,000	$ $ $	— — —	— 15,000 12,500	$ $ $	8,800 6,300 4,200
Charles R. Evans Vice President and Chief Operating Officer	2002 2001 2000	$ $ $	150,000 150,000 100,000	$ $ $	15,000 15,000 20,000	$ $ $	— — —	— 15,000 10,000	$ $ $	8,800 6,300 4,200

(1)

Includes the company's matching contributions under the company's 401(k) plan.

        The compensation described in this table does not include medical, group life insurance or other benefits that are available generally to all of the company's salaried employees. It also does not include certain perquisites and other personal benefits, securities or property received by these executive officers that are not material in amount.

Option Grants of Common Stock in Fiscal 2002

	Individual Grants
Name	Number of Securities Underlying Options Granted	% of Total Options Granted To Employees in Fiscal Year	Exercise Price Per Share	Expiration Date	Grant Date Present Value
Douglas H. Miller	—	—	N/A	N/A	N/A
T. W. Eubank	—	—	N/A	N/A	N/A
J. Douglas Ramsey	—	—	N/A	N/A	N/A
Richard E. Miller	—	—	N/A	N/A	N/A
Charles R. Evans	—	—	N/A	N/A	N/A

Option Exercises in Fiscal Year 2002 and Value at Fiscal Year End 2002

        The following table shows the number of shares of common stock covered by both exercisable and non-exercisable stock options held by Messrs. D. H. Miller, Eubank, Ramsey, R. E. Miller, and Evans

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as of December 31, 2002. This table also shows the value on that date of their "in-the-money" common stock options, which is the positive spread, if any, between the exercise price of existing stock options and $17.48 per share (the closing market price of the common stock on December 31, 2002).

			Number of Securities Underlying Unexercised Options at Fiscal Year-End		Value of Unexercised In-the-Money Options at Fiscal Year-End
	Shares Acquired on Exercise	Value Realized (Loss)
			(#)		($)
Name	(#)	($)
			Exercisable	Unexercisable	Exercisable		Unexercisable
Douglas H. Miller	—	—	190,000	17,500	$	1,998,388	$	65,588
T. W. Eubank	—	—	110,000	12,500	$	1,117,488	$	45,688
J. Douglas Ramsey	—	—	107,500	10,000	$	1,106,913	$	35,738
Richard E. Miller	—	—	58,021	10,625	$	521,784	$	37,209
Charles R. Evans	—	—	73,487	10,000	$	716,822	$	35,738

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

        This section contains shareholder information for persons known to us to be large shareholders (5% or more of our common or 5% convertible preferred stock), directors or executive officers of EXCO.

        Ownership of our common and 5% convertible preferred stock is shown in terms of "beneficial ownership." A person generally "beneficially owns" shares if he has the right to either vote those shares or dispose of them. More than one person may be considered to beneficially own the same shares.

        In this report, unless otherwise noted, a person has sole voting and dispositive power for those shares shown as beneficially owned by him. Shares shown as beneficially owned by our executive officers include shares that they have the right to acquire by exercising options on or before May 31, 2003. The percentages shown in this annual report compare the person's beneficially owned shares of common stock plus shares of 5% convertible preferred stock owned by that person on February 28, 2003, plus shares of common stock that can be acquired by that person from exercising options on or before May 31, 2003, plus shares of 5% convertible preferred stock owned by that person on February 28, 2003, with the total number of shares of common stock outstanding on February 28, 2003 (7,277,952 shares of common stock) plus shares of common stock that can be acquired by that person from exercising options on or before May 31, 2003, plus shares of 5% convertible preferred stock owned by that person on February 28, 2003. Also shown is the percentage of 5% convertible preferred stock owned by our executive officers on February 28, 2003, compared with the total number of shares of 5% convertible preferred stock outstanding on February 28, 2003 (4,989,869 shares of 5% convertible preferred stock). There are no outstanding options to purchase our 5% convertible preferred stock. Please note that the 5% convertible preferred stock is immediately convertible into shares of common stock.

Certain Shareholders

        The following table shows the beneficial ownership of our common stock and 5% convertible preferred stock as of February 28, 2003, for persons known by us, either through SEC filings or information provided to us, to own five percent or more of our common stock or 5% convertible preferred stock. In the case of Douglas H. Miller, the shares of common stock beneficially owned in the following table also shows beneficial ownership of shares of common stock that he can acquire by

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exercising options on or before May 31, 2003, plus shares of 5% convertible preferred stock owned by him.

	Shares of Common Stock Beneficially Owned				Shares of 5% Convertible Preferred Stock Beneficially Owned
Name and Address
	Number		Percent		Number	Percent
Ares Leveraged Investment Fund, L.P. Ares Leveraged Investment Fund II, L.P. 1999 Avenue of the Stars, #1900 Los Angeles, California 90067	867,491	(1)	11.9	%(1)	325,000	6.5	%
Stephen Feinberg, as investment manager of Cerberus Capital Management, L.P. 450 Park Avenue New York, New York 10022	1,122,323		15.4	%	—	—
FleetBoston Financial Corporation 100 Federal Street Boston, Massachusetts 02110	399,310	(2)	5.5	%(2)	274,190	5.5	%
Lord, Abbett & Co. 90 Hudson Street Jersey City, NJ 07302	865,120		11.9	%	—	—
Putnam Investment Management, LLC The Putnam Advisory Company, LLC One Post Office Square Boston, Massachusetts 02109	1,058,257		14.5	%	—	—
Douglas H. Miller group (6) EXCO Resources, Inc. 6500 Greenville Avenue, Suite 600, LB 17 Dallas, Texas 75206	2,352,258	(5)	28.0	%(5)	142,385	2.9	%
Mellon Financial Corporation Mellon Bank, N.A. The Dreyfus Corporation One Mellon Center Pittsburgh, Pennsylvania 15258	—		—		714,285	14.3	%
Marvin Mermelstein 2955 West Morse Chicago, Illinois 60645	719,094	(3)	9.9	%(3)	300,000	6.0	%
Henry Mermelstein 7141 North Kedzie Chicago, Illinois 60645	399,188	(4)	5.5	%(4)	397,188	8.0	%

(1)

Includes 325,000 shares of common stock that may be acquired upon conversion of the 5% convertible preferred stock.

(2)

Includes 274,190 shares of common stock that may be acquired upon conversion of the 5% convertible preferred stock.

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(3)

Includes 300,000 shares of common stock that may be acquired upon conversion of the 5% convertible preferred stock.

(4)

Includes 397,188 shares of common stock that may be acquired upon conversion of the 5% convertible preferred stock.

(5)

Includes 91,788 shares of common stock that may be acquired upon conversion of the 5% convertible preferred stock and 190,000 options to purchase shares of common stock that will be exercisable upon the closing of the merger.

(6)

Includes shares owned by the following members of a Schedule 13D group: Douglas H. Miller—859,122 shares, including 190,000 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 91,788 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; T.W. Eubank—263,407 shares, including 110,000 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 9,044 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; J. Douglas Ramsey—179,586 shares, including 107,500 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 2,087 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Jeffrey D. Benjamin—118,230 shares, including 50,000 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 10,000 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Earl E. Ellis—322,829 shares, including 25,000 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 26,000 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Charles R. Evans—85,934 shares, including 73,487 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 436 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Richard E. Miller—72,016 shares, including 58,021 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 1,035 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; J. David Choisser—8,006 shares, including 7,812 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; James M. Perkins, Jr.—5,451 shares, including 5,000 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 451 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Richard L. Hodges—16,784 shares, including 12,925 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; John D. Jacobi—94,069 shares, including 75,222 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Daniel A. Johnson—81,592 shares, including 80,222 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Harold L. Hickey—12,648 shares, including 12,084 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 44 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Stephen E. Puckett—20,162 shares, including 18,662 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days and 1,500 shares of common stock that may be acquired upon the conversion of our 5% convertible preferred stock; Russell W. Romoser—13,764 shares, including 13,250 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; W. Andy Bracken—25,498 shares, including 13,138 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Paul B. Rudnicki—6,143 shares, including 5,981 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Gary M. Nelson—23,235 shares, including 21,792 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Craig F. Hruska—28,882 shares,

98

including 11,182 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Steve Fagan—23,572 shares, including 11,182 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Dennis G. McIntyre—23,632 shares, including 11,182 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Gregory Robb—18,682 shares, including 11,182 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Jonathan Kuhn—4,400 shares, including 4,200 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Jamie Beninger—3,858 shares, including 3,858 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Terry Pidkowa—5,132 shares, including 5,132 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Duane Masse—2,540 shares, including 2,540 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Jennifer M. Perry—1,462 shares, including 1,462 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Kirstie M. Egan—4,726 shares, including 4,726 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Wesley E. Roberts—3,026 shares, including 3,026 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Delwyn C. Dennison—3,620 shares, including 3,620 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Muharem Mastalic—4,144 shares, including 4,144 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; H. Wayne Gifford—2,500 shares, including 2,500 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Gary L. Parker—13,606 shares, including 13,158 shares of common stock that may be acquired upon the exercise of options exercisable within 60 days; Terry Trudeau—0 shares; and Neil Burrows—0 shares.

        The following table contains shareholder information for our directors, our executive officers, and our directors and executive officers as a group.

				Shares of 5% Convertible Preferred Stock Beneficially Owned
	Shares of Common Stock Beneficially Owned
Name
	Number	Percent		Number	Percent
Douglas H. Miller (2)(8)	859,122	11.4	%	91,788	1.8	%
T. W. Eubank (9)	263,407	3.6	%	9,044	(1	)
J. Douglas Ramsey (10)	179,586	2.4	%	2,087	(1	)
Jeffrey D. Benjamin (6)	118,230	1.6	%	10,000	(1	)
Earl E. Ellis (5)(7)	322,829	4.4	%	26,000	(1	)
J. Michael Muckleroy (3)(14)	130,029	1.8	%	0	(1	)
Boone Pickens (16)	261,743	3.5	%	104,964	2.1	%
Stephen F. Smith (15)	130,079	1.8	%	25,000	(1	)
J. David Choisser (11)	8,006	(1	)	0	(1	)
Charles R. Evans (4)(12)	85,933	1.2	%	436	(1	)
Richard E. Miller (13)	72,016	1.0	%	1,035	(1	)
All directors and executive officers as a group (11 persons)	2,430,980	29.2	%	270,354	5.4	%

(1)

Less than 1%

(2)

Does not include 16,500 shares of common stock owned by the Miller Children's Trust of which Mr. D. H. Miller is neither the trustee nor the beneficiary.

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(3)

Includes 60,000 shares of common stock held by Paine Webber, Inc. Cust FBO Richard Sinz Marital Trust and Paine Webber, Inc., Cust FBO Dorothy Sinz, for both of which Mr. Muckleroy is trustee.

(4)

Includes 200 shares of common stock held by Mr. Evans as custodian for his children.

(5)

Includes 63,450 shares of common stock held by Benjamin Jacobson and Sons, LLC in trust for which Mr. Ellis is the beneficiary, 3,200 shares of common stock held by Mr. Ellis' daughter, and 1,000 shares of 5% convertible preferred stock held by Mr. Ellis' wife.

(6)

Includes 50,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Director Compensation Plan, and 10,000 shares of 5% convertible preferred stock.

(7)

Includes 25,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Director Compensation Plan, and 26,000 shares of 5% convertible preferred stock.

(8)

Includes 190,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Stock Option Plan, and 91,788 shares of 5% convertible preferred stock.

(9)

Includes 110,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Stock Option Plan, and 9,044 shares of 5% convertible preferred stock.

(10)

Includes 107,500 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Stock Option Plan, and 2,087 shares of 5% convertible preferred stock.

(11)

Includes 7,812 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Stock Option Plan, and no shares of 5% convertible preferred stock.

(12)

Includes 73,487 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Stock Option Plan, and 436 shares of 5% convertible preferred stock.

(13)

Includes 58,021 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Stock Option Plan, and 1,035 shares of 5% convertible preferred stock.

(14)

Includes 50,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Director Compensation Plan, and no shares of 5% convertible preferred stock.

(15)

Includes 50,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Director Compensation Plan, and 25,000 shares of 5% convertible preferred stock.

(16)

Includes 50,000 shares currently exercisable and/or vesting by May 31, 2003, under the 1998 Director Compensation Plan, and 104,964 shares of 5% convertible preferred stock.

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Securities Authorized for Issuance Under Equity Compensation Plans

        The following table provides information as of December 31, 2002 regarding compensation plans (including individual compensation arrangements) under which equity securities of EXCO are authorized for issuance:

EQUITY COMPENSATION PLAN INFORMATION

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights* (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity Compensation Plans Approved by Security Holders	2,049,831	$	10.85	974,792
Equity Compensation Plans not Approved by Security Holders	—		—	—
Total	2,049,831	$	10.85	974,792

*As adjusted for stock splits.

See Note 5 to our consolidated financial statements included in this annual report for information regarding the material features of the above plans. Each of the above plans provides that the number of shares with respect to which options may be granted, and the number of shares of common stock subject to an outstanding option, shall be proportionately adjusted in the event of a subdivision or consolidation of shares or the payment of a stock dividend on common stock, and the purchase price per share of outstanding options shall be proportionately revised.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

        Douglas H. Miller.    Mr. D. H. Miller, a director and executive officer, received a loan in the form of a promissory note from the company for $450,000 on September 15, 1998, which was renewed on September 15, 2001, and repaid in full including accrued interest on November 29, 2002. The loan was secured by a pledge of 75,000 shares of Mr. D. H. Miller's common stock in the company.

        Mr. D. H. Miller also received a loan in the form of a promissory note from the company for $465,625 on November 29, 1999, which was repaid in full including accrued interest on November 29, 2002. The loan was secured by a pledge of 77,500 shares of Mr. D. H. Miller's common stock in the company.

        T. W. Eubank.    Mr. Eubank, a director and executive officer, received a loan in the form of a promissory note from the company for $225,000 on September 15, 1998, which was repaid in full including accrued interest on June 20, 2001. The loan was secured by a pledge of 37,500 shares of Mr. Eubank's common stock in the company.

        Mr. Eubank also received a loan in the form of a promissory note from the company for $240,625 on November 29, 1999, which was repaid in full including accrued interest on June 20, 2001. The loan was secured by a pledge of 40,000 shares of Mr. Eubank's common stock in the company.

        J. Douglas Ramsey, Ph.D.    Dr. Ramsey, a director and executive officer, received a loan in the form of a promissory note from the company for $150,000 on September 15, 1998, which was repaid in full including accrued interest on July 27, 2001. The loan was secured by a pledge of 25,000 shares of Dr. Ramsey's common stock in the company.

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        Richard E. Miller.    Mr. R. E. Miller, an executive officer, received a loan in the form of a promissory note from the company for $60,000 on May 18, 2001. The loan bears interest at the rate of 6.44% and is due and payable on May 18, 2004. The loan is secured by a pledge of 10,000 shares of Mr. R. E. Miller's common stock in the company.

        Mr. R. E. Miller also owns working and royalty interests in some wells we operate. Mr. R. E. Miller does not receive payments from us in excess of $60,000 per year from these interests.

        Under the terms of each of the promissory notes Messrs. D. H. Miller, Eubank, Ramsey and R. E. Miller have timely paid all accrued interest due and payable.

        Jeffrey D. Benjamin.    Mr. Benjamin, a director, owns working interests in some wells in which we also own working interests but do not operate. Mr. Benjamin does not receive any payments from us from these interests.

        J. Michael Muckleroy.    Mr. Muckleroy, a director, owns working, royalty, and overriding royalty interests in some wells we operate. Mr. Muckleroy does not receive payments from us in excess of $60,000 per year from these interests.

ITEM 14.    CONTROLS AND PROCEDURES

        (a)  Evaluation of Disclosure Controls and Procedures.    The term "disclosure controls and procedures" is defined in Rule 13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. Our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer have evaluated the effectiveness of our disclosure controls and procedures as of a date within 90 days before the filing of this annual report, and they have concluded that as of that date, our disclosure controls and procedures were effective at ensuring that required information will be disclosed on a timely basis in our reports filed under the Exchange Act.

        (b)  Changes in Internal Controls.    We maintain a system of internal controls that are designed to provide reasonable assurance that our books and records accurately reflect our transactions and that our established policies and procedures are followed. There were no significant changes to our internal controls or in other factors that could significantly affect our internal controls subsequent to the date of their evaluation by our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, including any corrective actions with regard to significant and material weaknesses.

102

PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

1.    Financial Statements

        See Index to Financial Statements on page 65 to this annual report.

2.    Financial Statement Schedules

        All schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in our consolidated financial statements or related notes.

3.    Exhibits

No.	Description of Exhibit
3.1	Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein.
3.2	Statement of Designation for 5% Convertible Preferred Stock, dated June 21, 2001, filed as an Exhibit to EXCO's Form 8-K/A filed June 29, 2001 and incorporated by reference herein.
3.3	Restated Bylaws of EXCO, as amended (filed herewith).
4.1	Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein.
4.2	Restated Bylaws of EXCO, as amended (filed herewith).
4.3	Specimen Stock Certificate for the Common Stock of EXCO filed as an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2 filed on June 2, 1998 and incorporated by reference herein.
4.4	Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
4.5	Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
4.6	Statement of Designation for 5% Convertible Preferred Stock, dated June 21, 2001, filed as an Exhibit to EXCO's Form 8-K/A filed June 29, 2001 and incorporated by reference herein.
4.7	First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.

103

4.8	First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein.
4.9	Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein.
4.10	Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
4.11	Restated Credit Agreement among Addison Energy, Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
4.12	Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
4.13	Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
4.14	Second Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.
4.15	Second Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.

104

4.16	Third Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
4.17	Third Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
4.18	Fourth Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
4.19	Fourth Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
10.1*	EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A to EXCO's Proxy Statement dated March 17, 1998 and incorporated by reference herein.
10.2*	Amendment No. 1 to the EXCO Resources, Inc. 1998 Stock Option Plan, filed as Exhibit 10.10 to EXCO's Form 10-Q dated May 17, 1999 and incorporated by reference herein.
10.3*	Amendment No. 2 to EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.6 to Form S-8 filed April 26, 2001 and incorporated by reference herein.
10.4*	Amendment No. 3 to the EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.8 to Form S-8 filed May 10, 2002 and incorporated by reference herein.
10.5*	EXCO Resources, Inc. 1998 Director Compensation Plan filed as Appendix D to EXCO's Proxy Statement dated March 16, 1999 and incorporated by reference herein.
10.6	Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
10.7	Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.

105

10.8	First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
10.9	First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein.
10.10	Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein.
10.11	Agreement of Purchase and Sale among PrimeWest Energy Inc. and PrimeWest Oil and Gas Corp., as sellers, and Addison Energy Inc., as buyer, dated November 22, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
10.12	Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
10.13	Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
10.14	Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
10.15	Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.

106

10.16	Second Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.
10.17	Second Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.
10.18	Third Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.19	Third Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.20	Fourth Amendment to Restated Credit Agreement among EXCO Resources, Inc. And EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BPN Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
10.21	Fourth Amendment to Restated Credit Agreement among Addison Energy, Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
10.22*	Severance Plan of EXCO Resources, Inc., effective as of August 15, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.23	Agreement of Purchase and Sale between Devon Canada, as vendor, and Addison Energy Inc., as purchaser, dated January 25, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.24	Purchase and Sale Agreement between Southwestern Eagle, L.L.C. and SW Production Company, as sellers, and EXCO Resources, Inc., as buyer, dated October 18, 2002 filed as an Exhibit to EXCO's Form 8-K filed November 12, 2002 and incorporated by reference herein.
10.25*	Promissory Note dated May 18, 2001 by and between Richard E. Miller, as maker, and EXCO Resources, Inc., as payee (filed herewith).
10.26*	Pledge Agreement dated May 19, 2001 by and between Richard E. Miller, as pledger, and EXCO Resources, Inc., as the secured party (filed herewith).

107

10.27	Form of Addison Energy Inc. Stock Option Agreement effective as of June 30, 2002 (filed herewith).
10.28	Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003 filed as an Exhibit to EXCO's Form 8-K filed March 12, 2003 and incorporated by reference herein.
10.29	Agreement dated October 14, 2002, by and between EXCO Resources, Inc. and Douglas H. Miller, and any person who executes a joinder agreement, filed as an exhibit to Douglas H. Miller's Schedule 13D/A filed October 14, 2002 and incorporated by reference herein.
21.1	Subsidiaries of EXCO Resources, Inc. (filed herewith).
23.1	Consent of Independent Accountants, Ernst & Young LLP (filed herewith).
23.2	Consent of Independent Petroleum Engineers, Lee Keeling and Associates, Inc. (filed herewith).
99.1	Certification of Douglas H. Miller, Chairman of the Board and Chief Executive Officer of EXCO Resources, Inc., dated March 25, 2003, relating to EXCO's Annual Report on Form 10-K for the year ended December 31, 2002 (filed herewith).
99.2	Certification of J. Douglas Ramsey, Vice President and Chief Financial Officer of EXCO Resources, Inc., dated March 25, 2003, relating to EXCO's Annual Report on Form 10-K for the year ended December 31, 2002 (filed herewith).
99.3	Share Acquisition Agreement between Douglas H. Miller and EXCO Resources, Inc. dated as of October 14, 2002 filed as an Exhibit to Mr. Miller's 13D filed October 24, 2002 and incorporated by reference herein.
99.4	Joinder of T. W. Eubank to that certain Share Acquisition Agreement between Douglas H. Miller and EXCO Resources, Inc. dated as of October 23, 2002 filed as an Exhibit to Mr. Miller's 13D filed October 24, 2002 and incorporated by reference herein.

*These exhibits are management contracts.

4.    Reports on Form 8-K

        Current report on Form 8-K dated November 1, 2002 pursuant to Item 2 reporting the acquisition of properties from Southwestern Eagle, L.L.C. and SW Production Company.

        Current report on Form 8-K dated November 22, 2002 pursuant to Item 5 reporting the signing of the fourth amendments to our restated U.S. and Canadian credit agreements, increases in the borrowing base under each agreement, and the addition of a new lender to the U.S. bank group.

        Current report on Form 8-K dated December 27, 2002 pursuant to Item 5 reporting the receipt of a revised proposal for the acquisition of the company by a group led by the company's Chairman and Chief Executive Officer, Douglas H. Miller. The new proposal increased the consideration for our common stock to $18.00 per share and the consideration for our 5% convertible preferred stock to be between $18.00 and $18.525 per share, depending upon the date of the closing.

108

SIGNATURE PAGE

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act, the Registrant has duly caused this report to be signed on its behalf by the undersigned, there unto duly authorized in the City of Dallas, Texas on the 25th of March, 2003.

EXCO RESOURCES, INC.
By:	/s/  DOUGLAS H. MILLER Douglas H. Miller Chairman of the Board of Directors and Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

March 25, 2003	/s/  DOUGLAS H. MILLER Douglas H. Miller Chairman of the Board of Directors and Chief Executive Officer
March 25, 2003	/s/  T. W. EUBANK T. W. Eubank Director, President and Treasurer
March 25, 2003	/s/  J. DOUGLAS RAMSEY J. Douglas Ramsey, Ph.D. Director, Vice President and Chief Financial Officer (Principal Financial Officer)
March 25, 2003	/s/  J. DAVID CHOISSER J. David Choisser Chief Accounting Officer (Principal Accounting Officer)
March 25, 2003	/s/  JEFFREY D. BENJAMIN Jeffrey D. Benjamin Director
March 25, 2003	/s/  EARL E. ELLIS Earl E. Ellis Director
March 25, 2003	/s/  J. MICHAEL MUCKLEROY J. Michael Muckleroy Director

109

March 25, 2003	/s/  BOONE PICKENS Boone Pickens Director
March 25, 2003	/s/  STEPHEN F. SMITH Stephen F. Smith Director

110

CERTIFICATION

I, Douglas H. Miller, Chief Executive Officer of EXCO Resources, Inc. certify that:

1.

I have reviewed this annual report on Form 10-K of EXCO Resources, Inc.;



2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and



3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.



4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:



a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and



c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;




5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):



a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and




6.

The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 25, 2003
/s/  DOUGLAS H. MILLER Douglas H. Miller
Chief Executive Officer

111

CERTIFICATION

I, J. Douglas Ramsey, Chief Financial Officer of EXCO Resources, Inc., certify that:

1.

I have reviewed this annual report on Form 10-K of EXCO Resources, Inc.;



2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and



3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.



4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:



a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and



c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;




5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):



a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and




6.

The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 25, 2003
/s/  J. DOUGLAS RAMSEY J. Douglas Ramsey
Chief Financial Officer

112

CERTIFICATION

I, J. David Choisser, Chief Accounting Officer of EXCO Resources, Inc. certify that:

1.

I have reviewed this annual report on Form 10-K of EXCO Resources, Inc.;



2.

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and



3.

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.



4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:



a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and



c)

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;




5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):



a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and




6.

The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 25, 2003
/s/  J. DAVID CHOISSER J. David Choisser
Chief Accounting Officer

113

INDEX TO EXHIBITS

No.	Description of Exhibit
3.1	Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein.
3.2	Statement of Designation for 5% Convertible Preferred Stock, dated June 21, 2001, filed as an Exhibit to EXCO's Form 8-K/A filed June 29, 2001 and incorporated by reference herein.
3.3	Restated Bylaws of EXCO, as amended (filed herewith).
4.1	Restated Articles of Incorporation of EXCO filed as an Exhibit to EXCO's Form S-3/A filed June 2, 1998 and incorporated by reference herein.
4.2	Restated Bylaws of EXCO, as amended (filed herewith).
4.3	Specimen Stock Certificate for the Common Stock of EXCO filed as an Exhibit to EXCO's Pre-Effective Amendment No. 1 to Form S-2 filed on June 2, 1998 and incorporated by reference herein.
4.4	Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
4.5	Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
4.6	Statement of Designation for 5% Convertible Preferred Stock, dated June 21, 2001, filed as an Exhibit to EXCO's Form 8-K/A filed June 29, 2001 and incorporated by reference herein.
4.7	First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
4.8	First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein.
4.9	Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q, dated November 14, 2001 and incorporated by reference herein.

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4.10	Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
4.11	Restated Credit Agreement among Addison Energy, Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
4.12	Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
4.13	Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
4.14	Second Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.
4.15	Second Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.
4.16	Third Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
4.17	Third Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.

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4.18	Fourth Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
4.19	Fourth Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
10.1*	EXCO Resources, Inc. 1998 Stock Option Plan, filed as Appendix A to EXCO's Proxy Statement dated March 17, 1998 and incorporated by reference herein.
10.2*	Amendment No. 1 to the EXCO Resources, Inc. 1998 Stock Option Plan, filed as Exhibit 10.10 to EXCO's Form 10-Q dated May 17, 1999 and incorporated by reference herein.
10.3*	Amendment No. 2 to EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.6 to Form S-8 filed April 26, 2001 and incorporated by reference herein.
10.4*	Amendment No. 3 to the EXCO Resources, Inc. 1998 Stock Option Plan filed as Exhibit 4.8 to Form S-8 filed May 10, 2002 and incorporated by reference herein.
10.5*	EXCO Resources, Inc. 1998 Director Compensation Plan filed as Appendix D to EXCO's Proxy Statement dated March 16, 1999 and incorporated by reference herein.
10.6	Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
10.7	Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
10.8	First Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated April 26, 2001, filed as an Exhibit to EXCO's Form 10-Q filed May 8, 2001 and incorporated by reference herein.
10.9	First Amendment to Credit Agreement among EXCO Resources, Inc. as borrower, and Bank One, NA and the institutions named herein as lenders, Bank One, NA, as administrative agent and Fleet National Bank, as syndication agent and BNP Paribas, as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein.

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10.10	Second Amendment to Credit Agreement among EXCO Resources Canada Inc. as borrower, and Bank One Canada and the institutions named herein as lenders, Bank One Canada, as administrative agent and BNP Paribas (Canada) as documentation agent and Banc One Capital Markets, Inc. as lead arranger and bookrunner, dated November 14, 2001, filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2001 and incorporated by reference herein.
10.11	Agreement of Purchase and Sale among PrimeWest Energy Inc. and PrimeWest Oil and Gas Corp., as sellers, and Addison Energy Inc., as buyer, dated November 22, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
10.12	Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
10.13	Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated December 18, 2001, filed as an Exhibit to EXCO's Form 8-K filed January 2, 2002 and incorporated by reference herein.
10.14	Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
10.15	Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated April 26, 2002 filed as an Exhibit to EXCO's Form 10-Q filed May 14, 2002 and incorporated by reference herein.
10.16	Second Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.
10.17	Second Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and the financial institutions which are or may become Lenders, dated June 24, 2002 filed as an Exhibit to EXCO's Form 10-Q filed August 14, 2002 and incorporated by reference herein.

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10.18	Third Amendment to Restated Credit Agreement among EXCO Resources, Inc. and EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.19	Third Amendment to Restated Credit Agreement among Addison Energy Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated September 30, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.20	Fourth Amendment to Restated Credit Agreement among EXCO Resources, Inc. And EXCO Operating, LP, as borrowers, Bank One, NA, as administrative agent, BPN Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and financial institutions which are or may become Lenders dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
10.21	Fourth Amendment to Restated Credit Agreement among Addison Energy, Inc., as borrower, Bank One, NA, Canada Branch, as administrative agent, BNP Paribas (Canada), as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc., as lead arranger and bookrunner, and financial institutions which are or may become Lenders, dated November 22, 2002, filed as an Exhibit to EXCO's Form 8-K filed November 22, 2002 and incorporated by reference herein.
10.22*	Severance Plan of EXCO Resources, Inc., effective as of August 15, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.23	Agreement of Purchase and Sale between Devon Canada, as vendor, and Addison Energy Inc., as purchaser, dated January 25, 2002 filed as an Exhibit to EXCO's Form 10-Q filed November 14, 2002 and incorporated by reference herein.
10.24	Purchase and Sale Agreement between Southwestern Eagle, L.L.C. and SW Production Company, as sellers, and EXCO Resources, Inc., as buyer, dated October 18, 2002 filed as an Exhibit to EXCO's Form 8-K filed November 12, 2002 and incorporated by reference herein.
10.25*	Promissory Note dated May 18, 2001 by and between Richard E. Miller, as maker, and EXCO Resources, Inc., as payee (filed herewith).
10.26*	Pledge Agreement dated May 19, 2001 by and between Richard E. Miller, as pledger, and EXCO Resources, Inc., as the secured party (filed herewith).
10.27	Form of Addison Energy Inc. Stock Option Agreement effective as of June 30, 2002 (filed herewith).
10.28	Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003 filed as an Exhibit to EXCO's Form 8-K filed March 12, 2003 and incorporated by reference herein.
10.29	Agreement dated October 14, 2002, by and between EXCO Resources, Inc. and Douglas H. Miller, and any person who executes a joinder agreement, filed as an exhibit to Douglas H. Miller's Schedule 13D/A filed October 14, 2002 and incorporated by reference herein.
21.1	Subsidiaries of EXCO Resources, Inc. (filed herewith).
23.1	Consent of Independent Accountants, Ernst & Young LLP (filed herewith).

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23.2	Consent of Independent Petroleum Engineers, Lee Keeling and Associates, Inc. (filed herewith).
99.1	Certification of Douglas H. Miller, Chairman of the Board and Chief Executive Officer of EXCO Resources, Inc., dated March 25, 2003, relating to EXCO's Annual Report on Form 10-K for the year ended December 31, 2002 (filed herewith).
99.2	Certification of J. Douglas Ramsey, Vice President and Chief Financial Officer of EXCO Resources, Inc., dated March 25, 2003, relating to EXCO's Annual Report on Form 10-K for the year ended December 31, 2002 (filed herewith).
99.3	Share Acquisition Agreement between Douglas H. Miller and EXCO Resources, Inc. dated as of October 14, 2002 filed as an Exhibit to Mr. Miller's 13D filed October 24, 2002 and incorporated by reference herein.
99.4	Joinder of T. W. Eubank to that certain Share Acquisition Agreement between Douglas H. Miller and EXCO Resources, Inc. dated as of October 23, 2002 filed as an Exhibit to Mr. Miller's 13D filed October 24, 2002 and incorporated by reference herein.

*These exhibits are management contracts.

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QuickLinks

PART I

ITEM 1. BUSINESS

ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT ACCOUNTANTS
EXCO RESOURCES, INC. CONSOLIDATED BALANCE SHEETS
EXCO RESOURCES, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
EXCO RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
EXCO RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

EQUITY COMPENSATION PLAN INFORMATION

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14. CONTROLS AND PROCEDURES

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

SIGNATURE PAGE
CERTIFICATION
CERTIFICATION
CERTIFICATION
INDEX TO EXHIBITS

EX-3.3

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Exhibits 3.3 and 4.2

RESTATED BYLAWS
OF
EXCO RESOURCES, INC.
(F/K/A MINERAL DEVELOPMENT, INC.)
(As Amended August 15, 2002)

ARTICLE ONE

Title and Effective Date

Section 1.01 - Title. These Restated Bylaws shall be known as the Bylaws of EXCO Resources, Inc. (f/k/a Mineral Development, Inc.) and shall, as of the date set forth in Section 1.02 hereof, supersede any Bylaws previously in effect for EXCO Resources, Inc. (hereinafter referred to as the "Corporation").

Section 1.02 - Effective Date. These Restated Bylaws are effective as of the 11^th day of September, 1996, as amended August 15, 2002.

ARTICLE TWO

Offices

Section 2.01 - Principal Office. The principal office of the Corporation shall be in the City of Dallas, County of Dallas, State of Texas. The principal office of the Corporation shall be the registered office of the Corporation in the State of Texas.

Section 2.02 - Other Offices. The Corporation may also have offices at such other places as the Board of Directors may from time to time appoint, or as the business of the Corporation may require.

ARTICLE THREE

Meetings of Shareholders

Section 3.01 - Place. All meetings of shareholders shall be held at the principal office of the Corporation or in such other place as the Board of Directors shall designate from time to time.

Section 3.02 - Time of Annual Meeting. The annual meeting of shareholders shall be held at such date and time as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting.

Section 3.03 - Special Meetings. Special meetings of the shareholders may be called by the President, the Board of Directors or by the holders of not less than one-tenth of all the shares entitled to vote at the meeting so called. No question may be voted upon at a special meeting of the shareholders unless the notice of such meeting states that one of the purposes of such meeting will be to act upon such question or such meeting is attended by all of the shareholders entitled to vote upon such question and all of the shareholders vote that such question may then be voted upon at such meeting.

Section 3.04 - Notice of Meetings. Written or printed notice stating the place, day and hour of the meeting and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be delivered not less than ten (10) nor more than fifty (50) days before the date of the meeting, either personally or by mail, by, or at the direction of, the President, the Secretary or the officer or person or persons calling the meeting. If mailed, such notice shall be deemed to be delivered when

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deposited in the United States mail addressed to the shareholder at his address as it appears on the stock transfer books of the Corporation with postage thereon prepaid.

Section 3.05 - Fixing Record Date. In order that the Corporation may determine the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors may fix, in advance, a record date, which shall not be more than fifty (50) nor less than ten (10) days before the date of such meeting, not more than fifty (50) days prior to any other action, for the determination of the shareholders entitled to notice of, and to vote at, any such meeting or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitles to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action. If the Board of Directors fix, in advance, a record date as herein provided, then, in such case, such shareholders, and only such shareholders, as shall be shareholders of record on the date so fixed shall be entitled to such notice of, and to vote at, any such meeting or any adjournment thereof, or to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock, or for the purpose of any other lawful action, as the case may be, notwithstanding any transfer of any stock on the books of the Corporation after such record date is fixed as aforesaid.

Section 3.06 - Voting List. The officer or agent having charge of the Corporation's stock transfer books shall make, on the record date established pursuant to Section 3.05 hereof, a complete list of the shareholders entitled to vote at such meeting or any adjournment thereof. Such list shall be arranged in alphabetical order, with the last known address of and the number of shares held by each, which list shall be kept on file at all times prior to such meeting at the principal office of the Corporation and shall be subject to inspection by any shareholder at any time during usual business hours. Such list shall also be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any shareholder at any time during the meeting. The original stock transfer books shall be prima facie evidence as to who are the shareholders entitled to examine such list or transfer books and to vote at any meeting of shareholders.

Section 3.07 - Quorum. The holders of a majority of the shares entitled to vote, represented in person or by valid proxy, shall constitute a quorum at a meeting of shareholders. The vote of the holders of a majority of the shares entitled to vote and thus represented at a meeting at which a quorum is present shall constitute the act of the shareholders, unless the vote of a greater number is required by law.

Section 3.08 - Voting of Shares.

        (a)  Each outstanding share of the Corporation shall be entitled to one vote on each matter submitted to a vote of a meeting of shareholders.

        (b)  Treasury shares, shares of the Corporation's own stock owned by another corporation, the majority of the voting stock of which is owned or controlled by the Corporation, and shares of the Corporation's own stock held by it in a fiduciary capacity shall not be voted, directly or indirectly, at any meeting, and shall not be counted in determining the total number of outstanding shares at any given time.

        (c)  A shareholder may vote either in person or by proxy executed in writing by the shareholder or by his duly authorized attorney in fact. No proxy shall be valid after eleven (11) months from the date of its execution unless otherwise provided in the proxy. Each proxy

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shall be revocable unless expressly provided therein to be irrevocable, and unless otherwise made irrevocable by law.

        (d)  At each election for directors, every shareholder entitled to vote at such election shall have the right to vote in person or by proxy the number of shares owned by him for as many persons as there are directors to be elected and for whose election he has a right to vote. Shareholders may not cumulate their votes by giving one candidate as many votes as the number of such directors multiplied by the number of his shares shall equal.

        (e)  Shares standing in the name of another corporation, domestic or foreign, may be voted by such officer, agent or proxy as the bylaws of such corporation may authorize or, in the absence of such authorization, as the board of directors of such corporation may determine.

        (f)    Shares held by an administrator, executor, guardian or conservator may be voted by him so long as such shares forming part of an estate are in the possession and forming a part of the estate being served by him, either in person or by proxy, without a transfer of shares into his name. Shares standing in the name of a trustee may be voted by him, either in person or by proxy, but no trustee shall be entitled to vote shares held by him without a transfer of such shares into his name as trustee.

        (g)  Shares standing in the name of a receiver may be voted by such receiver, and shares held by or under the control of a receiver may be voted by such receiver without the transfer hereof into his name if authority to do so be contained in an appropriate order of the court by which such receiver was appointed.

        (h)  A shareholder whose shares are pledged shall be entitled to vote such shares until the shares have been transferred into the name of the pledgee, and thereafter the pledgee shall be entitled to vote the shares so transferred.

ARTICLE FOUR

Directors

Section 4.01 - Management. The business and affairs of the Corporation shall be managed by the Board of Directors.

Section 4.02 - Number. The number of directors which shall constitute the whole board shall from time to time be fixed and determined by resolution adopted by the board of directors. The number to be elected at any meeting of the shareholders shall be set forth in the notice of any meeting of shareholders held for such purpose.

Section 4.03 - Qualifications. A director need not be a shareholder of the Corporation in order to be elected to the office of director.

Section 4.04 - Election. At each annual meeting of shareholders, the shareholders shall elect directors to hold office until the next succeeding annual meeting.

Section 4.05 - Term of Office. Unless removed in accordance with these bylaws, each director shall hold office for the term for which he is elected and until his successor shall have been elected and qualified.

Section 4.06 - Removal. Any director may be removed from his position as director, either with or without cause, at any special meeting of shareholders if notice of intention to act upon the question of removing such director shall have been stated as a purpose for the calling of such meeting.

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Section 4.07 - Vacancy. A particular directorship shall be considered to be vacant upon the happening of any one of the following events:

        (1)  Death of the person holding such directorship;

        (2)  Resignation of the person holding such directorship; or

        (3)  Removal of a director at a special shareholders' meeting as provided in Section 4.06 hereof.

Section 4.08 - Filling of Vacancy. Any vacancy occurring in the Board of Directors may be filled by the affirmative vote of a majority of the remaining directors though less than a quorum. A director elected to fill a vacancy shall be elected for the unexpired term of his predecessor in office.

Section 4.09 - Election to New Directorship. In the event of the creation of one or more new directorships in accordance with Section 4.02 hereof, then any directorship to be filled by reason of such increase in the number of directors may be filled by election at an annual meeting or special meeting of the shareholders called for that purpose or may be filled by the Board of Directors for a term continuing only until the next election of one or more directors by the shareholders; provided that the Board of Directors may not fill more than two such directorships during the period between any two successive annual meetings of shareholders.

Section 4.10 - Quorum. A majority of the number of directors shall constitute a quorum for the transaction of business. The act of the majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors unless otherwise specifically required by law or these Bylaws.

Section 4.11 - Executive and Other Committees. The Board of Directors, by resolution adopted by a majority of the full Board of Directors, may designate from among its members an Executive Committee and one or more other committees, each of which, to the extent provided in such resolution, shall have and may exercise all of the authority of the Board of Directors except in reference to amending the Articles of Incorporation, approving a plan of merger or consolidation, recommending to the shareholders the sale, lease or exchange of all or substantially all of the property and assets of the Corporation otherwise than in the usual and regular course of its business, recommending to the shareholders a voluntary dissolution of the Corporation or a revocation thereof, amending, altering or repealing the Bylaws of the Corporation or adopting new Bylaws for the Corporation, filling vacancies in the Board of Directors or such committee, electing or removing officers or members of any such committee, fixing the compensation of any member of such committee, or altering or repealing any resolution of the Board of Directors which by its terms provides that it shall not be so amendable or repealable; and, unless such resolution expressly so provides, no such committee shall have the power or authority to declare a dividend or to authorize the issuance of shares of the Corporation. The designation of such committee and the delegation thereto of authority shall not operate to relieve the Board of Directors, or any member thereof, of any responsibility imposed by law. Any committee so established by the Board of Directors shall be comprised of not less than one (1) Director. Regular minutes shall be kept of the proceedings of any committee and a report thereof shall be delivered to the Board of Directors of the Corporation when required.

Section 4.12 - Regular Meetings. A regular meeting of the Board of Directors shall be held without other notice than these Bylaws immediately after and at the same place as the annual meeting of shareholders. The Board of Directors may provide, by resolution, the time and place, either within or without the State of Texas, for the holding of additional regular meetings without other notice than such resolution.

Section 4.13 - Special Meetings. Special meetings of the Board of Directors may be called by or at the request of the President or any two directors. Notice of the call of a special meeting shall be in

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writing and delivered for transmission to each of the directors not later than during the third day immediately preceding the day for which such meeting is called. Notice of any special meeting may be waived in writing signed by the person or persons entitled to such notice; such waiver may be executed at any time before or after the time herein specified for the giving of such notice but not later than the time specified in such notice for the holding of such special meeting. Attendance of a director at a special meeting shall constitute a waiver of notice of such special meeting, except where a director attends a meeting for the express purpose of objecting to the transaction of any business or the meeting is not lawfully called or convened.

Section 4.14 - Place of Meetings. Unless otherwise authorized by these Bylaws, all meetings of the Board of Directors shall be held at the principal office of the Corporation; provided, however, this provision of these Bylaws may be waived as to any particular meeting by written waiver signed by all of the directors before the holding of such meeting, and this provision shall be considered as waived as to any particular meeting by the attendance of all of the Directors at such meeting without objection by any one of them at the time of convening of such meeting that such meeting is not being convened and held at the principal office of the Corporation.

Section 4.15 - Conference Telephone Meetings. Subject to the provisions herein concerning notice of meetings, members of the Board of Directors or members of any committee designated by the Board may participate in and hold any regular or special meeting of the Board or such committee by means of conference telephone or other communications equipment by means of which all persons participating in the meeting can hear each other, and participation in such meeting shall constitute presence in person thereat, except where a person participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened.

Section 4.16 - Actions Without a Meeting of Directors. Any action required or permitted to be taken at a meeting of the Board of Directors or the Executive Committee, may be taken without a meeting if a consent in writing setting forth the action so taken is signed by all the members of the Board of Directors or Executive Committee, as the case may be. Such consent shall have the same force and effect as a unanimous vote at a meeting.

Section 4.17 - Compensation. By resolution of the Board of Directors, the directors may be paid their expenses, if any, of attendance of each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors. No such payment, however, shall preclude any directors from serving the Corporation in any other capacity and receiving compensation therefor.

ARTICLE FIVE

Officers

Section 5.01 - Number. The officers of the Corporation shall be a President, one or more Vice Presidents (the number thereof to be determined by the Board of Directors), a Treasurer, and a Secretary, and such Assistant Treasurers, Assistant Secretaries or other officers as may be elected by the Board of Directors. Any two or more offices may be held by the same person, except that the President and Secretary shall not be the same person. In the event there are two or more Vice Presidents, the Board of Directors may designate one of such Vice Presidents the Executive Vice President.

Section 5.02 - Election and Term of Office. The officers of the Corporation shall be elected annually by the Board of Directors at the first meeting of the Board of Directors held after each annual meeting of shareholders or as soon thereafter as conveniently as vacancies may be filled. Each officer shall hold

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office until his successor shall have been duly elected and shall have qualified or until his death or until he shall resign or shall have been removed in the manner herein provided.

Section 5.03 - Removal. Any officer or agent or member of the Executive Committee elected or appointed by the Board of Directors may be removed by the Board of Directors whenever in its judgment the best interest of the Corporation would be served thereby, but such removal shall be without prejudice to the contract rights, if any, of the person so removed.

Section 5.04 - Vacancies. A vacancy in any office because of death, resignation, removal, disqualification or otherwise, may be filled by the Board of Directors for the unexpired portion of the term.

Section 5.05 - President. The President shall be the principal executive officer of the Corporation and shall in general supervise and control all of the business and affairs of the Corporation. He shall preside at all meetings of the shareholders and of the Board of Directors. He shall sign or execute, with the Secretary or an Assistant Secretary, certificates for shares of the Corporation, any deeds, mortgages, pledges, leases, assignments, bonds, contracts or other instruments which the Board of Directors has authorized to be executed, except in cases where the signing and execution thereof shall be expressly delegated by the Board of Directors to some other officer or agent of the Corporation, or shall be required by law to be otherwise signed or executed; and in general he shall perform all duties incident to the office of President and such other duties as may be prescribed by the Board of Directors from time to time.

Section 5.06 - Executive Vice President. In the event the Board of Directors shall designate one of the Vice Presidents of the Corporation as Executive Vice President, as authorized in Section 5.01, such Executive Vice President shall, in the absence of the President, or in the event of his inability or refusal to act, perform the duties of the President, and when so acting, shall have all the powers of and be subject to all the restrictions upon the President.

Section 5.07 - Vice President. In the absence of the President and the Executive Vice President (if any has been designated by the Board of Directors), any Vice President may perform the duties of the President, and when so acting, shall have all of the powers of and be subject to all of the restrictions placed upon the President, and the Vice President shall perform such other duties as from time to time may be assigned to him by the President, the Executive Vice President, or by the Board of Directors.

Section 5.08 - The Treasurer. The Treasurer shall have charge and custody of and be responsible for all funds and securities of the Corporation, receive and give receipts for moneys due and payable to the Corporation from any source whatsoever, and deposit all moneys in the name of the Corporation in such banks, trust companies or other depositories as shall be selected by the Board of Directors; and in general, perform all the duties as from time to time may be assigned to him by the Board of Directors.

Section 5.09 - The Secretary. The Secretary shall:

        (a)  be responsible for the recordation and keeping of the minutes of the shareholders' and of the Board of Directors' meetings in one or more books provided for that purpose;

        (b)  see that all notices are duly given in accordance with the provisions of these Bylaws or as required by law;

        (c)  be custodian of the Corporate records and of the seal of the Corporation and see that the seal of the Corporation is affixed in accordance with the provisions of these Bylaws;

        (d)  keep a register of the post office address of each shareholder;

        (e)  sign or execute with the President certificates for shares of the Corporation, the issue of which shall have been authorized by resolution of the Board of Directors, and any and all deeds,

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mortgages, pledges, security agreements, leases, assignments, bonds, contracts or other instruments which the Board of Directors has authorized to be executed;

        (f)    have general charge of the stock transfer books of the Corporation; and

        (g)  in general perform all duties incident to the office of Secretary and such other duties as from time to time may be assigned to him by the President or by the Board of Directors.

Section 5.10 - Assistant Treasurer or Assistant Secretaries. The Assistant Secretaries as thereunto authorized by the Board of Directors may sign or execute with the President certificates for shares of the Corporation, the issue of which shall have been authorized by a resolution of the Board of Directors, and any and all deeds, mortgages, pledges, security agreements, leases, assignments, contracts or other instruments which the Board of Directors has authorized to be executed. The Assistant Treasurers and Assistant Secretaries, in general, shall perform such duties as shall be assigned to them by the Treasurer or the Secretary, respectively, or by the President or the Board of Directors.

Section 5.11 - Salaries. The salaries and other compensation of the officers shall be fixed from time to time by the Board of Directors and no officer shall be prevented from receiving such salary by reason of the fact that he is also a director of the Corporation.

ARTICLE SIX

Indemnification of Directors and Officers

Section 6.01 - Indemnification. This Corporation shall indemnify each of its directors or officers or its former directors and officers or any person who may have served at its request as a director or officer of another corporation in which it owns shares of capital stock or of which it is a creditor against expenses actually and reasonably incurred by him in connection with the defense of any action, suit or proceeding, civil or criminal, in which he is made a party by reason of being or having been such director or officer, except in relation to matters as to which he shall be adjudged in such action, suit or proceeding to be liable for negligence or misconduct in the performance of his duty to such corporation. Negligence or misconduct for this purpose shall be deemed to include willful misfeasance, bad faith, gross negligence or the reckless disregard of the duties involved in the conduct of his office. A conviction of judgment (whether based on a plea of guilty or nolo contendere or its equivalent, or after trial) in a criminal action, suit or proceeding shall not be deemed an adjudication of liability for negligence or misconduct in the performance of duty to the Corporation if the director, officer or other person acted in good faith in what he considered to be the best interests of the Corporation and without reasonable cause to believe that the action upon which the judgment of conviction is predicated was illegal. In the absence of an adjudication which expressly absolves the director, officer or other person of liability to the Corporation or its shareholders for negligence and misconduct within the meaning thereof, as used herein, or in the event of a settlement the right to indemnification of each director, officer or other person shall be conditioned upon the prior determination by a resolution adopted by two-thirds (2/3) of those members of the Board of Directors who are not involved in the action, suit or proceeding that the director or officer has no liability by reason of negligence or misconduct, within the meaning thereof used herein, or, in the alternative, if a majority of the Board of Directors are involved in the action, suit or proceedings, such determination shall have been made by independent counsel. The right to indemnification provided for herein shall extend and include the heirs, personal representatives, executors and administrators of any deceased officer, director or other person described above.

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Section 6.02 - Indemnification in Securities Matters. In the event that a claim for indemnification under the provisions of Section 6.01 hereof is made for liabilities arising under the Securities Act of 1933, as amended and supplemented, the indemnification shall not be made or allowed unless:

        (1)  the claim for indemnification under the circumstances is predicated upon the prior successful defense by the applicant of any action, suit or proceeding;

        (2)  the Board of Directors receives an opinion of counsel of the Corporation to the effect that it has been settled by controlling precedent that indemnification under the circumstances is not against public policy as expressed in said Act; or

        (3)  a court of appropriate jurisdiction finally adjudicates in an action, suit or proceeding in which the issue is submitted to the court by the Corporation prior to allowance of the claim that indemnification under the circumstances is not contrary to the public policy expressed in said Act.

Section 6.03 - Types of Actions. The provisions of Section 6.01 and 6.02 hereof shall apply to any action, suit or proceeding by or in the right of the Corporation, as well as to other actions, suits or proceedings, whatsoever the nature thereof or the claim or cause of action asserted therein.

Section 6.04 - Other Rights. The right of indemnification provided for in Sections 6.01 and 6.02 hereof shall be in amplification, and not in limitation, of any other right, relief or remedy to which the directors, officers and other person referred to therein may be entitled according to law.

Section 6.05 - Reliance Upon Counsel; Corporate Records. Every officer, director or member of any committee appointed by the Board of Directors shall, in the performance of his duties, be fully protected in relying in good faith upon the opinion of counsel of the Corporation and upon the books of account or reports made to the Corporation by any of its officials, or by an independent certified public accountant, or by an appraiser selected with reasonable care by the Board of Directors, or by such committee, or in relying in good faith upon other records of the Corporation.

ARTICLE SEVEN

Contracts, Loans, Checks and Deposits

Section 7.01 - Contracts. The Board of Directors may authorize any officer or officers, agent or agents, to enter into any contract or execute and deliver any instrument in the name of and on behalf of the Corporation, and such authority may be general or confined to specific instances.

Section 7.02 - Loans. No loans shall be contracted on behalf of the Corporation and no evidences of indebtedness shall be issued in its name unless authorized by a resolution of the Board of Directors. Such authority may be general or confined to specific instances.

Section 7.03 - Checks, Drafts, etc. All checks, drafts or other orders for the payment of money, notes or other evidences of indebtedness issued in the name of the Corporation, shall be signed by such officer or officers, agent or agents of the Corporation and in such manner as shall from time to time be determined by resolution of the Board of Directors.

Section 7.04 - Deposits. All funds of the Corporation not otherwise employed shall be deposited from time to time to the credit of the Corporation in such banks, trust companies, money market funds, other depositories, certificates of deposit, negotiable instruments or securities as the Board of Directors may select.

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ARTICLE EIGHT

Certificates for Shares

Section 8.01 - Certificates of Shares. Certificates representing shares of the Corporation shall be in such form as may be determined by the Board of Directors. Such certificates shall be signed by the President or a Vice President and by the Secretary or an Assistant Secretary and shall be sealed with the seal of the Corporation. All certificates for shares shall be consecutively numbered or otherwise identified. The name of the person to whom the shares represented thereby are issued, with the number of shares and date of issue, shall be entered on the books of the Corporation. All certificates surrendered to the Corporation for transfer shall be cancelled and no new certificate shall be issued until the former certificate for a like number of shares shall have been surrendered and cancelled, except that, in case of a lost, destroyed or mutilated certificate, a new one may be issued therefor upon such terms and indemnity to the Corporation as the Board of Directors may prescribe.

Section 8.02 - Transfer of Shares. Transfers of shares of the Corporation shall be made only on the books of the Corporation by the holder of record thereof or by his legal representative, who shall furnish proper evidence of authority to transfer, or by his attorney thereunto authorized by power of attorney duly executed and filed with the Secretary of the Corporation, and on surrender for cancellation of the certificate for such shares. The person in whose name shares stand on the books of the Corporation shall be deemed the owner thereof for all purposes as regards the Corporation.

ARTICLE NINE

General Provisions

Section 9.01 - Fiscal Year. The fiscal year of the Corporation shall begin each year on January 1^st and end on the next succeeding December 31^st.

Section 9.02 - Amendment of Bylaws. The power to alter, amend or repeal the Bylaws or adopt new Bylaws, subject to repeal or change by action of the shareholders, shall be vested in the Board of Directors. The Bylaws of this Corporation may contain any provisions for the regulation and management of the affairs of the Corporation not inconsistent with law or the Articles of Incorporation.

Section 9.03 - Seal. The seal of the Corporation, if any, shall be a circular disc which shall contain the name of the Corporation and its state of incorporation. Notwithstanding any provision of these Bylaws, the Board of Directors may discontinue or abolish the seal, and the absence of the Corporation's seal or a facsimile thereof on any document or instrument executed or issued by the Corporation shall not impair the validity thereof.

Section 9.04 - Powers of the Corporation and the Board of Directors. The Corporation and its Board of Directors shall enjoy all powers and authority as may be respectively conferred upon them pursuant to the Texas Business Corporation Act and as is not expressly denied them by these Bylaws, the Articles of Incorporation, or applicable law.

Dated: March 13, 2003 /s/  RICHARD E. MILLER Richard E. Miller, Secretary

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Exhibits 3.3 and 4.2

RESTATED BYLAWS OF EXCO RESOURCES, INC. (F/K/A MINERAL DEVELOPMENT, INC.) (As Amended August 15, 2002)
ARTICLE ONE
ARTICLE TWO
ARTICLE THREE
ARTICLE FOUR
ARTICLE FIVE
ARTICLE SIX
ARTICLE SEVEN
ARTICLE EIGHT
ARTICLE NINE

EX-10.25

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Exhibit 10.25

PROMISSORY NOTE

$60,000.00 Dallas, Texas May 18, 2001

        FOR VALUE RECEIVED, the undersigned, Richard E. Miller ("Maker") unconditionally promises to pay to the order of EXCO Resources, Inc., a Texas corporation ("Payee"), at 6500 Greenville Avenue, Suite 600, Dallas, Texas 75206 or at such other address given to Maker by Payee, the principal sum of Sixty Thousand and no/100 Dollars ($60,000.00), in lawful money of the United States of America, together with interest (calculated on the basis of a 365 or 366-day year, as appropriate), on the unpaid principal balance from day-to-day remaining, computed from the date of advance until maturity at the rate per annum which shall from day-to-day be equal to the lesser of (a) the Maximum Rate, or (b) six and 44/100 percent (6.44%). If at any time and from time to time the rate of interest calculated pursuant to item (b) above would exceed the Maximum Rate, thereby causing the interest payable hereon to be limited to the Maximum Rate, then any subsequent reduction in the rate specified in item (b) above shall not reduce the rate of interest hereon below the Maximum Rate until the total amount of interest accrued hereon from and after the date of the first advance hereunder equals the amount of interest which would have accrued hereon if the rate specified in item (b) above had at all times been in effect.

        The term "Maximum Rate," as used herein, shall mean, with respect to the holder hereof, the maximum nonusurious interest rate, if any, that at any time, or from time to time, may be contracted for, taken, reserved, charged, or received on the indebtedness evidenced by this Note. To the extent that Article 5069-1.04, Title 79, Texas Revised Civil Statutes, 1925, as amended, is relevant to any holder of this Note for the purposes of determining the Maximum Rate, the Payee hereby notifies Maker that the "applicable rate ceiling" shall be the "indicated rate ceiling" referred to in Article 5069-1.04(a)(1) from time to time in effect, as limited by Article 5069-1.04(b); provided, however, that to the extent permitted by applicable law, Payee reserves the right to change the "applicable rate ceiling" from time to time by further notice and disclosure to Maker; and, provided further, that the "Maximum Rate" for purposes of this Note shall not be limited to the applicable rate ceiling under Article 5069-1.04 if federal laws or other state laws now or hereafter in effect and applicable to this Note (and the interest contracted for, charged and collected hereunder) shall permit a higher rate of interest.

        The principal of and interest upon this Note shall be due and payable as follows:

        (a)  Interest, computed as aforesaid, shall be due and payable annually on each yearly anniversary date of the Note as it accrues, beginning on May 18, 2002 and thereafter, on May 18, 2003 and at maturity; and

        (b)  The entire unpaid principal balance of this Note shall be due and payable in full on May 18, 2004, unless sooner demanded.

        All past-due principal and, to the extent permitted by applicable law, past-due interest upon this Note shall bear interest at the Maximum Rate or, if no Maximum Rate is established by applicable law, then at the rate 18% per annum.

        Maker and each surety, endorser, guarantor and other party ever liable for payment of any sums of money payable on this Note, jointly and severally waive presentment, protest, notice of protest and non-payment, or other notice of default, notice of acceleration and intention to accelerate, and agree that their liability under this Note shall not be affected by any renewal or extension in the time of payment hereof, or in any indulgences, or by any release or change in any security for the payment of this Note, and hereby consent to any and all renewals, extensions, indulgences, releases or changes, regardless of the number of such renewals, extensions, indulgences, releases or changes.

        Maker shall be personally liable, and Payee shall have recourse against Maker, in an amount not greater than 40% of the principal amount due hereunder and accrued but unpaid interest thereon. This Note is secured by, among other things, a Pledge Agreement (hereinafter so called) dated of even date herewith from Maker to Payee, covering certain shares of Common Stock of Payee issued in the name of Maker, as more fully described therein (the "Property").

        No waiver by Payee of any of its rights or remedies hereunder or under any other document evidencing or securing this Note or otherwise shall be considered a waiver of any other subsequent right or remedy of Payee; no delay or omission in the exercise or enforcement by Payee of any rights or remedies shall ever be construed as a waiver of any right or remedy of Payee; and no exercise or enforcement of any such rights or remedies shall ever be held to exhaust any right or remedy of Payee.

        Maker reserves the right to prepay the outstanding principal balance of this Note, in whole or in part, at any time and from time to time, without premium or penalty. Any such prepayment shall be made together with payment of interest accrued on the amount of principal being prepaid through the date of such prepayment, and shall be applied to the installments of principal due hereunder in the inverse order of maturity.

        Regardless of any provision contained in this Note or any other document executed or delivered in connection therewith, Payee shall never be deemed to have contracted for or be entitled to receive, collect or apply as interest on this Note, any amount in excess of the Maximum Rate, and, in the event that Payee ever receives, collects or applies as interest any such excess, such amount which would be excessive interest shall be applied to the reduction of the unpaid principal balance of this Note, and, if the principal balance of this Note is paid in full, any remaining excess shall forthwith be paid to Maker. In determining whether or not the interest paid or payable under any specific contingency exceeds the highest Maximum Rate, Maker and Payee shall, to the maximum extent permitted under applicable law, (i) characterize any non-principal payment (other than payments which are expressly designated as interest payments hereunder) as an expense or fee rather than as interest, (ii) exclude voluntary pre-payments and the effect thereof, and (iii) spread the total amount of interest throughout the entire contemplated term of this Note so that the interest rate is uniform throughout such term; provided, that if this Note is paid and performed in full prior to the end of the full contemplated term hereof, and if the interest received for the actual period of existence thereof exceeds the Maximum Rate, if any, Payee or any holder hereof shall refund to Maker the amount of such excess, or credit the amount of such excess against the aggregate unpaid principal balance of all advances made by the Payee or any holder hereof under this Note at the time in question.

        This Note is being executed and delivered, and is intended to be performed in the State of Texas. Except to the extent that the laws of the United States may apply to the terms hereof, the substantive laws of the State of Texas shall govern the validity, construction, enforcement and interpretation of this Note. In the event of a dispute involving this Note or any other instruments executed in connection herewith, the undersigned irrevocably agrees that venue for such dispute shall lie in any court of competent jurisdiction in Dallas County, Texas.

MAKER:

/s/  RICHARD E. MILLER Richard E. Miller

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Exhibit 10.25

EX-10.26

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Exhibit 10.26

Pledge Agreement Date: May 19, 2001        

SECURED PARTY:		PLEDGOR/DEBTOR:
	EXCO Resources, Inc. c/o Chief Executive Officer 6500 Greenville, Suite 600 Dallas, Dallas County, Texas 75206	Richard E. Miller 4731 McKinney Ave., #1501 Dallas, Texas 75205

A.    Security Interest. For good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, Pledgor/Debtor (hereinafter referred to as "Pledgor") pledges, assigns and grants to EXCO Resources, Inc., a Texas corporation ("EXCO"), a security interest and lien in the Collateral (hereinafter defined) to secure the payment and the performance of the Obligation (hereinafter defined).

B.    Collateral. The security interest is granted in the following collateral (the "Collateral"):

1.    Specific Investment Property/Securities: 10,000 shares of common stock of EXCO, together with all investment property and/or securities hereafter delivered to and accepted by EXCO, in its sole discretion, in substitution therefor or in addition thereto.

2.    All additions, substitutes and replacements for and proceeds of the above Collateral (including all income and benefits resulting from any of the above, such as dividends payable or distributable in cash, property or stock; interest, premium and principal payments; redemption proceeds and subscription rights; and shares or other proceeds of conversions or splits of any securities in the Collateral). Any investment property and/or securities received by Pledgor, which shall comprise such additions, substitutes and replacements for, or proceeds of, the Collateral, shall be held in trust for EXCO and shall be delivered immediately to EXCO. Any cash proceeds shall be held in trust for EXCO and upon request shall be delivered immediately to EXCO.

C.    Obligation. The following obligations ("Obligation") are secured by this Agreement: (a) All debt, obligations and liabilities of Pledgor to EXCO under that certain Promissory Note (herein so called) made by Pledgor to EXCO dated on even date herewith, now existing or hereafter arising; (b) All costs incurred by EXCO to obtain, preserve, perfect and enforce this agreement and maintain, preserve, collect and enforce the Collateral; (c) Interest on the amounts below determined in accordance with applicable agreements between EXCO and Pledgor; (d) All expenses of the EXCO, including fees and expenses of the EXCO's counsel, incident to the enforcement of payment of the Obligation by any action or participation in, or in connection with a case or proceeding under the Bankruptcy Code, or any successor statute thereto.

D.    Pledgor's Warranties. Pledgor hereby represents and warrants to EXCO as follows:

1.    Financing Statements. Except as may be noted by schedule attached hereto and incorporated herein by reference, no financing statement covering the Collateral is or will be on file in any public office, except the financing statements relating to this security interest, and no security interest, other than the one herein created, has attached or been perfected in the Collateral or any part thereof.

2.    Ownership. Pledgor owns the Collateral free from any setoff, claim, restriction, lien, security interest or encumbrance except liens for taxes not yet due and payable and the security interest hereunder.

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3.    Power and Authority. Pledgor has full power and authority to make this Agreement, and all necessary consents and approvals of any persons, entities, governmental or regulatory authorities and securities exchanges have been obtained to effectuate the validity of this Agreement.

E.    Pledgor's Covenants. Until full payment and performance of all of the Obligation, unless EXCO otherwise consents in writing:

1.    Obligation and This Agreement. Pledgor shall perform all of its agreements herein.

2.    Ownership of Collateral. Pledgor shall defend the Collateral against all claims and demands of all persons at any time claiming any interest therein adverse to EXCO. Pledgor shall keep the Collateral free from all liens and security interests except those for taxes not yet due and payable and the security interest hereby created.

3.    EXCO's Costs. Pledgor shall pay all costs necessary to obtain, preserve, perfect, defend and enforce the security interest created by this Agreement, collect the Obligation, and preserve, defend, enforce and collect the Collateral, including but not limited to taxes, assessments, reasonable attorney's fees, legal expenses and expenses of sales. Whether the Collateral is or is not in EXCO's possession, and without any obligation to do so and without waiving Pledgor's default for failure to make any such payment, EXCO at its option may pay any such costs and expenses and discharge encumbrances on the Collateral, and such payments shall be a part of the Obligation and bear interest at the rate set out in the Obligation. Pledgor agrees to reimburse EXCO on demand for any costs so incurred.

4.    Information and Inspection. Pledgor shall (i) promptly furnish EXCO any information with respect to the Collateral requested by EXCO; (ii) allow EXCO or its representatives to inspect and copy, or furnish EXCO or its representatives with copies of, all records relating to the Collateral and the Obligation; and (iii) promptly furnish EXCO or its representatives with any other information EXCO may reasonably request regarding the Obligation.

5.    Additional Documents. Pledgor shall sign and deliver any papers furnished by EXCO which are necessary or desirable in the judgment of EXCO to obtain, maintain and perfect the security interest hereunder and to enable EXCO to comply with any federal or state law in order to obtain or perfect EXCO's interest in the Collateral or to obtain proceeds of the Collateral.

6.    Notice of Changes.     Pledgor shall notify EXCO immediately of (i) any material change in the Collateral, (ii) a change in Pledgor's residence or location, or (iii) a material change in any matter warranted or represented by Pledgor in this Agreement.

7.    Possession of Collateral. Pledgor shall deliver all investment securities and other instruments and documents which are a part of the Collateral and in Pledgor's possession to EXCO immediately upon request, or if hereafter acquired, immediately following acquisition, in a form suitable for transfer by delivery or accompanied by duly executed instruments of transfer or assignment in blank with signatures appropriately guaranteed in form and substance suitable to EXCO.

8.    Change of Name/Status. Pledgor shall not change its name, change its corporate status, use any trade name or engage in any business not reasonably related to its business as presently conducted, except with prior written notice to the EXCO.

9.    Power of Attorney. Pledgor appoints EXCO and any officer thereof as Pledgor's attorney-in-fact with full power in Pledgor's name and on Pledgor's behalf to do every act which Pledgor is obligated to do or may be required to do hereunder; however, nothing in this paragraph shall be construed to obligate EXCO to take any action hereunder nor shall EXCO be liable to Pledgor for failure to take any action hereunder. This appointment shall be deemed a power coupled with an interest and shall not be terminable as long as the Obligation is outstanding and shall not terminate on the disability or incompetence of Pledgor. Without limiting the generality of the foregoing, EXCO shall have the right and power to receive, indorse and collect all checks and other

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orders for the payment of money made payable to Pledgor representing any dividend, interest payment or other distribution payable in respect of the Collateral or any part thereof.

10.  Other Parties and Other Collateral. No renewal or extensions of or any other indulgence with respect to the Obligation or any part thereof, no modification of the document(s) evidencing the Obligation, no release of any security, no release of any person (including any maker, indorser, guarantor or surety) liable on the Obligation, no delay in enforcement of payment, and no delay or omission or lack of diligence or care in exercising any right or power with respect to the Obligation or any security therefor or guaranty thereof or under this Agreement shall in any manner impair or affect the rights of EXCO under any law, hereunder, or under any other agreement pertaining to the Collateral. EXCO need not file suit or assert a claim for any part of the Obligation before foreclosing or otherwise realizing upon the Collateral.

11.  Waivers by Pledgor. Pledgor waives notice of the creation, advance, increase, existence, extension or renewal of, and of any indulgence with respect to, the Obligation; waives presentment, demand, notice of dishonor, and protest; waives notice of the amount of the Obligation outstanding at any time, notice of any change in financial condition of any person liable for the Obligation or any part thereof, notice of any Event of Default, and all other notices respecting the Obligation; and agrees that maturity of the Obligation and any part thereof may be accelerated, extended or renewed one or more times by EXCO in its discretion, without notice to Pledgor. Pledgor further waives any right of subrogation or to enforce any right of action against any other pledgor until the Obligation is paid in full.

F.    Rights and Powers of EXCO.

1.    General. EXCO, before or after default, without liability to Pledgor may: take control of proceeds, including stock received as dividends or by reason of stock splits; release the Collateral in its possession to any Pledgor, temporarily or otherwise; require additional Collateral from the Company; reject as unsatisfactory any property hereafter offered by Pledgor as Collateral; take control of funds generated by the Collateral, such as cash dividends, interest and proceeds, and use same to reduce any part of the Obligation and exercise all other rights which an owner of such Collateral may exercise, except the right to vote or dispose of the Collateral before an Event of Default; and at any time transfer any of the Collateral or evidence thereof into its own name or that of its nominee. EXCO shall not be liable for failure to collect any account or instruments, or for any act or omission on the part of EXCO, its officers, agents or employees, except for its or their own willful misconduct or gross negligence. The foregoing rights and powers of EXCO will be in addition to, and not a limitation upon, any rights and powers of EXCO given by law, elsewhere in this Agreement, or otherwise.

2.    Convertible Collateral. EXCO may present for conversion any Collateral which is convertible into any other instrument or investment security or a combination thereof with cash, but EXCO shall not have any duty to present for conversion any Collateral unless it shall have received from Pledgor detailed written instructions to that effect at a time reasonably far in advance of the final conversion date to make such conversion possible.

G.    Default.

1.    Event of Default. An event of default ("Event of Default") under this Agreement shall occur if an event of default occurs under the Promissory Note (as it may be renewed, extended, amended, or restated).

2.    Rights and Remedies. If any event of default shall occur, then, in each and every such case, EXCO may, without (a) presentment, demand, or protest, (b) notice of default, dishonor, demand, non-payment, or protest, (c) notice of intent to accelerate all or any part of the Obligation, (d) notice of acceleration of all or any part of the Obligation, or (e) notice of any other kind, all of which Pledgor hereby expressly waives (except for any notice required under this Agreement, any other loan document

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concerning the Obligation or which may not be waived under applicable law), at any time thereafter exercise and/or enforce any of the following rights and remedies, at EXCO's option:

i.    Acceleration. The Obligation shall, at EXCO's option, become immediately due and payable, and the obligation, if any, of EXCO to permit further borrowings under the Obligation shall at EXCO's option immediately cease and terminate.

ii.    Liquidation of Collateral. Upon 20 days written to notice to Pledgor (and if such event of default has not been cured), sell, or instruct any Agent or Broker to sell, all or any part of the Collateral in a public or private sale, direct any Agent or Broker to liquidate all or any part of the Collateral and deliver all proceeds thereof to EXCO, and apply all proceeds to the payment of any or all of the Obligation in such order and manner as EXCO shall, in its discretion, choose.

iii.    Uniform Commercial Code. Upon 20 days written to notice to Pledgor (and if such Event of Default has not been cured), all of the rights, powers and remedies of a secured creditor under the Uniform Commercial Code ("UCC") as adopted in the jurisdiction to which EXCO is subject under this Agreement.

iv.    Cancellation of Shares. EXCO may cancel the Collateral on its stock transfer books at a value equal to the closing price on the Nasdaq Stock Market or other securities market on which shares of EXCO's Common Stock is then traded on the date of cancellation.

Pledgor specifically understands and agrees that any sale by EXCO of all or part of the Collateral pursuant to the terms of this Agreement may be effected by EXCO at times and in manners which could result in the proceeds of such sale as being significantly and materially less than might have been received if such sale had occurred at different times or in different manners, and Pledgor hereby releases EXCO and its officers and representatives from and against any and all obligations and liabilities arising out of or related to the timing or manner of any such sale.

If, in the opinion of EXCO, there is any question that a public sale or distribution of any Collateral will violate any state or federal securities law, EXCO may offer and sell such Collateral in a transaction exempt from registration under federal securities law, and any such sale made in good faith by EXCO shall be deemed "commercially reasonable."

H.    General.

1.    Parties Bound. EXCO's rights hereunder shall inure to the benefit of its successors and assigns, and in the event of any assignment or transfer of any of the Obligation or the Collateral, EXCO thereafter shall be fully discharged from any responsibility with respect to the Collateral so assigned or transferred, but EXCO shall retain all rights and powers hereby given with respect to any of the Obligation or the Collateral not so assigned or transferred. All representations, warranties and agreements of Pledgor if more than one are joint and several and all shall be binding upon the personal representatives, heirs, successors and assigns of Pledgor.

2.    Waiver. No delay of EXCO in exercising any power or right shall operate as a waiver thereof; nor shall any single or partial exercise of any power or right preclude other or further exercise thereof or the exercise of any other power or right. No waiver by EXCO of any right hereunder or of any default by Pledgor shall be binding upon EXCO unless in writing, and no failure by EXCO to exercise any power or right hereunder or waiver of any default by Pledgor shall operate as a waiver of any other or further exercise of such right or power or of any further default. Each right, power and remedy of EXCO as provided for herein or in any of the loan documents related to the Obligation, or which shall now or hereafter exist at law or in equity or by statute or otherwise, shall be cumulative and concurrent and shall be in addition to every other such right, power or remedy. The exercise or beginning of the exercise by EXCO of any one or more of such rights, powers or remedies shall not preclude the simultaneous or later exercise by EXCO of any or all other such rights, powers or remedies.

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3.    Agreement Continuing. This Agreement shall constitute a continuing agreement.

4.    Definitions. Unless the context indicates otherwise, definitions in the UCC apply to words and phrases in this Agreement; if UCC definitions conflict, Article 8 and/or 9 definitions apply.

5.    Notice. Notice shall be deemed reasonable if mailed postage prepaid at least 5 days before the related action (or if the UCC elsewhere specifies a longer period, such longer period) to the address of Pledgor given above. Each notice, request and demand shall be deemed given or made, if sent by mail, upon the earlier of the date of receipt or five (5) days after deposit in the U.S. Mail, first class postage prepaid, or if sent by any other means, upon delivery.

6.    Modifications. No provision hereof shall be modified or limited except by a written agreement expressly referring hereto and to the provisions so modified or limited and signed by Pledgor and EXCO. The provisions of this Agreement shall not be modified or limited by course of conduct or usage of trade.

7.    Partial Invalidity. The unenforceability or invalidity of any provision of this Agreement shall not affect the enforceability or validity of any other provision herein, and the invalidity or unenforceability of any provision of any loan document related to the Obligation to any person or circumstance shall not affect the enforceability or validity of such provision as it may apply to other persons or circumstances.

8.    Applicable Law and Venue. This Agreement has been delivered in the State of Texas and shall be construed in accordance with the laws of that State. It is performable by Pledgor in Dallas, Dallas County, Texas and Pledgor expressly waives any objection as to venue in any such location. Wherever possible each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement shall be prohibited by or invalid under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provisions or the remaining provisions of this Agreement.

9.    Financing Statement. To the extent permitted by applicable law, a carbon, photographic or other reproduction of this Agreement or any financing statement covering the Collateral shall be sufficient as a financing statement.

10.  ARBITRATION. ANY CONTROVERSY OR CLAIM BETWEEN OR AMONG THE PARTIES HERETO INCLUDING BUT NOT LIMITED TO THOSE ARISING OUT OF OR RELATING TO THIS INSTRUMENT, AGREEMENT OR DOCUMENT OR ANY RELATED INSTRUMENTS, AGREEMENTS OR DOCUMENTS, INCLUDING ANY CLAIM BASED ON OR ARISING FROM AN ALLEGED TORT, SHALL BE DETERMINED BY BINDING ARBITRATION IN ACCORDANCE WITH THE FEDERAL ARBITRATION ACT (OR IF NOT APPLICABLE, THE APPLICABLE STATE LAW), THE RULES OF PRACTICE AND PROCEDURE FOR THE ARBITRATION OF COMMERCIAL DISPUTES OF J.A.M.S./ENDISPUTE OR ANY SUCCESSOR THEREOF ("J.A.M.S."), AND THE "SPECIAL RULES" SET FORTH BELOW. IN THE EVENT OF ANY INCONSISTENCY, THE SPECIAL RULES SHALL CONTROL. JUDGMENT UPON ANY ARBITRATION AWARD MAY BE ENTERED IN ANY COURT HAVING JURISDICTION. ANY PARTY TO THIS INSTRUMENT, AGREEMENT OR DOCUMENT MAY BRING AN ACTION, INCLUDING A SUMMARY OR EXPEDITED PROCEEDING, TO COMPEL ARBITRATION OF ANY CONTROVERSY OR CLAIM TO WHICH THIS AGREEMENT APPLIES IN ANY COURT HAVING JURISDICTION OVER SUCH ACTION.

i.    SPECIAL RULES. THE ARBITRATION SHALL BE CONDUCTED IN THE COUNTY OF DALLAS, TEXAS AND ADMINISTERED BY J.A.M.S. WHO WILL APPOINT AN ARBITRATOR; IF J.A.M.S. IS UNABLE OR LEGALLY PRECLUDED FROM ADMINISTERING THE ARBITRATION, THEN THE AMERICAN ARBITRATION ASSOCIATION WILL SERVE. ALL ARBITRATION HEARINGS WILL BE COMMENCED WITHIN 90 DAYS OF THE DEMAND FOR ARBITRATION;

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FURTHER, THE ARBITRATOR SHALL ONLY, UPON A SHOWING OF CAUSE, BE PERMITTED TO EXTEND THE COMMENCEMENT OF SUCH HEARING FOR UP TO AN ADDITIONAL 60 DAYS.

ii.    RESERVATION OF RIGHTS. NOTHING IN THIS ARBITRATION PROVISION SHALL BE DEEMED TO (I) LIMIT THE APPLICABILITY OF ANY OTHERWISE APPLICABLE STATUTES OF LIMITATION OR REPOSE AND ANY WAIVERS CONTAINED IN THIS INSTRUMENT, AGREEMENT OR DOCUMENT; OR (II) BE A WAIVER BY EXCO OF THE PROTECTION AFFORDED TO IT BY 12 U.S.C. SEC. 91 OR ANY SUBSTANTIALLY EQUIVALENT STATE LAW; OR (III) LIMIT THE RIGHT OF EXCO HERETO (A) TO EXERCISE SELF HELP REMEDIES SUCH AS (BUT NOT LIMITED TO) SETOFF, OR (B) TO FORECLOSE AGAINST ANY REAL OR PERSONAL PROPERTY COLLATERAL, OR (C) TO OBTAIN FROM A COURT PROVISIONAL OR ANCILLARY REMEDIES SUCH AS (BUT NOT LIMITED TO) INJUNCTIVE RELIEF, WRIT OF POSSESSION OR THE APPOINTMENT OF A RECEIVER. EXCO MAY EXERCISE SUCH SELF HELP RIGHTS, FORECLOSE UPON SUCH PROPERTY, OR OBTAIN SUCH PROVISIONAL OR ANCILLARY REMEDIES BEFORE, DURING OR AFTER THE PENDENCY OF ANY ARBITRATION PROCEEDING BROUGHT PURSUANT TO THIS INSTRUMENT, AGREEMENT OR DOCUMENT. NEITHER THIS EXERCISE OF SELF HELP REMEDIES NOR THE INSTITUTION OR MAINTENANCE OF AN ACTION FOR FORECLOSURE OR PROVISIONAL OR ANCILLARY REMEDIES SHALL CONSTITUTE A WAIVER OF THE RIGHT OF ANY PARTY, INCLUDING THE CLAIMANT IN ANY SUCH ACTION, TO ARBITRATE THE MERITS OF THE CONTROVERSY OR CLAIM OCCASIONING RESORT TO SUCH REMEDIES.

        11.  NOTICE OF FINAL AGREEMENT. THIS WRITTEN AGREEMENT AND ANY OTHER DOCUMENTS EXECUTED IN CONNECTION HEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their duly authorized representatives as of the date first above written.

Secured Party:	Pledgor/Debtor:
EXCO RESOURCES, INC.
By: /s/ J. DOUGLAS RAMSEY	/s/ RICHARD E. MILLER Richard E. Miller

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SCHEDULE 1

ELIGIBLE SECURITIES

10,000 shares of Common Stock, par value $.02 per share, issued by EXCO Resources, Inc. evidenced by stock certificate no. 10544.

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Exhibit 10.26

SCHEDULE 1 ELIGIBLE SECURITIES

EX-10.27

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Exhibit 10.27

ADDISON ENERGY INC.

FORM OF STOCK OPTION AGREEMENT

JUNE 30, 2002

TABLE OF CONTENTS

1.	Definitions	1
2.	The Plan	3
3.	Purpose	3
4.	Administration	3
5.	Participation and Grant	4
6.	Value of the Corporation	4
7.	Tenn and Vesting	6
8.	Method of Exercise of Options	8
9.	Termination of Employment	9
10.	Death, Permanent Disability or Retirement of a Participant	10
11.	Adjustments	10
12.	Transferability	10
13.	Suspension, Termination or Amendment of Plan	10
14.	Gender	10
15.	Governing Law	11
SCHEDULE A		Form of Stock Option Grant Agreement
SCHEDULE B		Form of Notice of Determined Value Per Option
SCHEDULE C		Form of Exercise and Power of Attorney
SCHEDULE D		Unanimous Shareholder Agreement

ADDISON ENERGY INC.

STOCK OPTION AGREEMENT

1.

Definitions

        In this Plan:

(a)

"affiliate" has the meaning ascribed thereto by the Securities Act (Alberta);



(b)

"Acquisition" means the acquisition of all of the common shares of the Corporation by EXCO Resources Canada Inc. on April 26, 2001;



(c)

"Base Value Per Option" means One Thousand Thirty One Dollars and Sixty One Cents ($1031.61);



(d)

"Board" means the board of directors of the Corporation;



(e)

"Change of Control" shall have the meaning ascribed thereto in Section 7. d. below;



(f)

"Corporation" means Addison Energy Inc.;



(g)

"Corporation's Financial Statements" means the unaudited financial statements of the Corporation for a calendar year prepared in accordance with GAAP;



(h)

"Deemed Deferred Tax Liability" means the amount by which the acquisition price of a company purchased by the Corporation was discounted because of the low tax basis or pools of the acquired company;



(i)

"Determination Date" means December 31 of each Participating Year or, in the event of a Change of Control, the effective date of such Change of Control;



(j)

"Determined Value" means the Value of the Corporation as at a Determination Date for which the Value of the Corporation has been determined multiplied by a fraction, the numerator of which is either (i) with respect to a Determination Date occurring at December 31 of a Participating Year, the average trading price of EXCO's shares in U.S. Dollars ("USD") for the first ten (10) trading days of the following calendar year; or (ii) with respect to a DeteImination Date resulting from a Change of Control, the price at which EXCO's common stock was valued in such Change of Control; and the denominator of which is $18.25 USD.



(k)

"Determined Value Per Option" means, at a particular date, the amount determined by dividing the Determined Value applicable on such date by 10,000;



(l)

"Engineering Report" means: (i) in connection with a December 31 Determination Date, a report prepared by EXCO's independent oil and gas engineering firm evaluating the Proved Reserves of the Corporation in the manner set forth in Section 6; or (ii) in connection with a Determination Date caused by a Change of Control, EXCO's internal engineering report evaluating the Proved Reserves of the Corporation in the manner set forth in Section 6;



(m)

"Equity Contributions" means all contributions, of capital, properties or other assets to the Corporation by EXCO;



(n)

"Evaluation Date" means, for each year, the date in such year on which the Board establishes the Determined Value as at December 31 of the immediately preceding Participating Year;



(o)

"EXCO" means EXCO Resources, Inc., a corporation incorporated under the laws of the State of Texas;

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(p)

"Exercise Form" means a notice of exercise of Options in the form annexed hereto as Schedule C;



(q)

"Exercise Period" means, for each year, the 30-day period commencing on the day immediately following the Evaluation Date for such year;



(r)

"GAAP" means generally accepted accounting principles from time to time approved by the Canadian Institute of Chartered Accountants, or any successor institute, applicable as at the date on which any calculation or determination is required to be made or financial statements prepared hereunder, and where the Canadian Institute of Chartered Accountants includes a recommendation in its Handbook concerning the treatment of an accounting matter, such recommendation shall be regarded as the only generally accepted accounting principle applicable to the circumstances it covers;



(s)

"NYMEX" means the New York Mercantile Exchange;



(t)

"Net Working Capital Deficiency" means the amount by which the Corporation's current liabilities on a Determination Date exceed the Corporation's current assets on such date, in each case as indicated in the Corporation's Financial Statements for such year;



(u)

"Net Working Capital Surplus" means the amount by which the Corporation's current assets on a Determination Date exceed the Corporation's current liabilities on such date, in each case as indicated in the Corporation's Financial Statements for such year;



(v)

"Notice Form" means a notification of the Determined Value Per Option in the form annexed hereto as Schedule B;



(w)

"Option Price" is the Base Value Per Option (unless otherwise redetermined by the Board) multiplied by the number of shares exercised by a Participant;



(x)

"Options" means the rights granted to the Participants to purchase shares in the Corporation in accordance with the terms of this Plan;



(y)

"Participants" means Craig Hruska, Steve Fagan, Dennis McIntyre, Robert Hemminger, Gregory Robb, Ron Jocsak, James Beninger, Jonathan Kuhn, Terry Pidkowa, and Duane Masse;



(z)

"Participating Years" means the calendar years in the five-year period ending December 31, 2006, and "Participating Year" means any one of such calendar years;



(aa)

"Permanent Disability" of a Participant shall be deemed to have occurred when two medical doctors dealing at arm's length with the Corporation, EXCO and all the Participants deliver to the Corporation certificates stating that the Participant is disabled and by reason thereof cannot reasonably be expected to be able to continue performing for the Corporation for a period of at least 12 months the duties he performed before such disability;



(bb)

"Plan" means the stock option plan of the Corporation established hereby and "Section" means a section of the Plan;



(cc)

"Proved Developed Producing Reserves" or "PDP" means those reserves expected to be recovered from currently producing zones under continuation of present operating methods;



(dd)

"Proved Non-Producing Reserves" or "PNP" means those reserves expected to be recovered from zones that have been completed and tested but are not yet producing due to lack of market, minor completion problems that are expected to be corrected, or reserves expected to be recovered from future stimulation treatments based upon analogy to nearby wells. Proved Non-Producing Reserves also include reserves currently behind the pipe in existing wells that are considered proved by virtue of successful testing or production in offsetting wells;

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(ee)

"Proved Reserves" means the Proved Developed Producing Reserves, Proved Non-Producing Reserves and Proved Undeveloped Reserves of the Corporation;



(ff)

"Proved Undeveloped Reserves" or "PUD" means those reserves attributable to wells to be drilled at locations which can be considered proved by virtue of favourable structural position and which can be anticipated with a high degree of certainty;



(gg)

"Term" has the meaning ascribed thereto in Section 7;



(hh)

"Value of the Corporation" means the value of the Corporation for the purposes of the Plan as determined in accordance with the provisions of Section 6; and



(ii)

"Value of the Corporation's Proved Reserves" means the value of the Corporation's Proved Reserves as determined in accordance with the provisions of Section 6.B. hereof.

2.

The Plan

        A stock option plan of the Corporation is hereby established on the terms set forth herein pursuant to which Options shall be granted to the Participants.

3.

Purpose

        The purpose of the Plan is to encourage the interest and desire of the Participants to increase and enhance the profitable operation and continued growth and development of the Corporation.

4.

Administration

(a)

The Plan shall be administered by the Board.

(b)

Subject to the terms and conditions set forth herein, the Board shall have the sole authority and discretion to:

(i)

construe and interpret the Plan and all agreements entered into under the Plan,

(ii)

prescribe, amend and rescind rules and regulations relating to the Plan and the exercise of Options granted under the Plan, and

(iii)

make all other determinations necessary or advisable for the administration of the Plan.

All determinations and interpretations made by the Board shall be binding on the Corporation and the Participants and their respective heirs, administrators, successors, personal representatives and beneficiaries.

(c)

Notwithstanding any other provision of the Plan, the Board shall have the right to delegate the administration and operation of the Plan, in whole or in part, to a committee of the Board, and whenever used herein the term "Board" shall include any committee to which the board has, fully or partially, delegated the administration and operation of the Plan.

5.

Participation and Grant

        The Corporation shall grant to the Participant a total of 20 Options, upon the terms and conditions and subject to the limitations set forth in the Plan. Options granted under the Plan shall be evidenced by an agreement signed on behalf of the Corporation by any authorized officer or director and by the Participant to whom Options are granted, which agreement shall be in the form annexed hereto as Schedule A.

6.

Value of the Corporation

A.

The Value of the Corporation as of any Determination Date shall be equal to the remainder obtained by subtracting the items listed in b. below from the items listed in a. below.

a.

The Value of the Corporation shall include the following:

(i)

the Value of the Corporation's Proved Reserves, as determined in accordance with Section 6.B.;

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(ii)

the Corporation's Net Working Capital Surplus, if any, as at such date;



(iii)

any distributions of cash made by the Corporation to EXCO and its affiliates (other than subsidiaries of the Corporation) after June 30, 2002; and



(iv)

the total exercise price of all outstanding Options



b.

The Value of the Corporation shall be reduced by the following:



(i)

the Corporation's Net Working Capital Deficiency, if any, as at such date;



(ii)

all Equity Contributions to the Corporation from and after April 26, 2001;



(iii)

all debt payable by the Corporation to EXCO, banks and other third parties;



(iv)

the sum of all Deemed Deferred Tax Liability incurred after June 30, 2002; and



(v)

an estimate of the Corporation's cumulative share (from January 1, 2002 forward) of EXCO's annual corporate general and administrative expenses; such estimate to be based upon the Value of the Corporation's Proved Reserves as determined by the formula described in paragraph 6.B. below and without regard to this subparagraph 6.A.b. (iv). The following formula shall be used to obtain such estimate:

.5% of the first $200 million of the Value of the Corporation's Proved Reserves; plus

.25% of the next $200 million of the Value of the Corporation's Proved Reserves; plus

.125% of the Value of the Corporation's Proved Reserves over $400 million.

B.

EXCO shall obtain an Engineering Report which shall be used to establish the value of the Corporation's Proved Reserves at a Determination Date based on the following parameters:

(i)

The price forecast for oil and gas, which shall not include any pricing for oil and gas that is hedged, shall be based on NYMEX futures prices at the close of business on the Determination Date for the three years subsequent to the effective date of the Engineering Report and on the then current price policy (base case) of EXCO's lead bank for all subsequent periods. A basis differential future price between NYMEX and the AECO price for 3 years shall be used to adjust the price forecast for natural gas. The third year AECO/NYMEX basis differential shall be held constant for subsequent periods after 3 years. The oil price forecast shall be adjusted for each of the Corporation's properties to account for the difference between the actual price realized at the wellhead during the preceding twelve months and NYMEX pricing during the same period. The gas price forecast shall be adjusted for each of the Corporation's properties to account for the difference between the actual price realized at the wellhead during the preceding twelve months and AECO pricing during the same period. Transportation, gathering, compression, treating, processing and all other related costs (other than operating expenses as set out in the Engineering Report) shall be accounted for as adjustments in determining the value of the Corporation's Proved Reserves. Assumptions used in the Engineering Report (other than those relating to matters identified in this Section 6 that are to be derived from another source or applied in a different manner) shall be applied to the extent they are relevant.



(ii)

Natural gas liquids pricing, which shall not include any pricing for liquids that are hedged, shall be based on a percentage of the adjusted oil price for each of the Corporation's properties as determined by the respective realized pricing for each during the previous twelve months. Such percentage shall be held constant throughout the life of the property.

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(iii)

Operating expenses and capital costs shall be escalated based on the current policy (base case) of EXCO's lead bank.



(iv)

The value of the Proved Reserves shall be determined as follows:

(A)

Proved Developed Producing Reserves: 100% of the present value of such reserves determined by applying a discount rate of 10%;



(B)

Proved Non-Producing Reserves: 75% of the present value of such reserves determined by applying a discount rate of 15%;



(C)

Proved Undeveloped Reserves: 50% of the present value of such reserves determined by applying a discount rate of 20%;



(D)

no value shall be attributed to non-proved reserve categories; and



(E)

the present value of all reserves shall be determined without regard to federal and provincial income taxes.



(F)

Except as expressly provided in Paragraph 1.(k) above in connection with the calculation of Determined Value (which uses U. S. Dollars for part of such calculation), all references to monetary sums and dollar amounts herein are to Canadian Dollars.

(vi)

The Corporation and EXCO shall ensure that the valuation methodology outlined herein, including the definitions, shall be consistently applied for the purpose of providing an Engineering Report or evaluating the Corporation or any of its assets, irrespective of which engineering firm is selected to provide the Engineering Report or conduct the evaluation or if EXCO performs such evaluation internally.

C.

Notwithstanding anything contained in the Plan to the contrary, in the event of a sale of the Corporation or all or substantially all of its assets independent of the sale of EXCO, the Determined Value shall be the sale price of the Corporation.

7.

Term and Vesting

        The period during which Options may be exercised (the "Term") shall be as follows:

(a)

Subject to the other provisions set forth in this Section 7, each Option shall be exercisable for a period of five years from the date the Option is granted unless otherwise specifically provided by the Board.



(b)

The Term shall be automatically reduced in accordance with Sections 9 and 10 upon the occurrence of any of the events referred to therein.



(c)

The number of Options vested for each Participant shall be as follows:

Vesting Date	Portion of total number of Options vested (including Options previously vested)
April 26, 2003	50	%
April 26, 2004	75	%
April 26, 2005	100	%

A Participant shall not be entitled to exercise any vested Options prior to April 26, 2003. A Participant may exercise any vested Options beyond April 26, 2003, subject to the provisions of this Section 7 and provided that the total number of Options exercised by a Participant shall not exceed the aggregate number of Options granted to such Participant.

(d)

If a Change of Control of the Corporation or of EXCO occurs prior to the fifth anniversary of the date of grant of any Options, all Options, regardless of the date of grant, shall vest

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immediately and the Participant shall be entitled to exercise at any time thereafter in whole or in part any Options previously granted to the Participant that had not been exercised prior to the date on which the Change of Control occurred until the earlier of (i) the fifth anniversary of the date of grant of the Options, or (ii) the ninetieth day following the date on which the Change of Control occurs. The Corporation shall ensure that Corporation's Financial Statements are completed as of the effective date of the Change of Control, or within a reasonable period thereafter and that an Engineering Report is completed, having an effective date not more than 30 days prior to the date of such Change of Control. Unless determined pursuant to the terms of 6.C. above, the Determined Value shall be based on the Value of the Corporation as calculated using such new Corporation's Financial Statements and Engineering Report. The amount so determined shall be the Determined Value in respect of all Options exercised after the Change of Control occurs.

For the purpose of the Plan, a Change of Control of the Corporation or of EXCO shall be deemed to have occurred if and when:

(i)

there is any change in the holding, direct or indirect, of shares of the Corporation or of EXCO, as applicable, as a result of which a person, or a group of persons, or persons acting jointly or in concert, or persons associated or affiliated with any such person or group within the meaning of the Securities Act (Alberta), is or are in a position to exercise effective control of the Corporation or EXCO. For the purposes of the Plan, a person or group of persons holding shares and/or other securities of a corporation in excess of the number that, directly or indirectly, would entitle the holders thereof to cast more than 50% of the votes attaching to all shares of such corporation that may be cast to elect directors of such corporation shall be deemed to be in a position to exercise effective control of such corporation; or



(ii)

the shareholders of the Corporation or of EXCO approve an amalgamation, consolidation, merger, arrangement or other combination (including a sale) of the Corporation or EXCO with a corporation other than EXCO or the Corporation or an affiliate of EXCO or the Corporation as a result of which the shareholders of EXCO will own, directly or indirectly, less than 50% of the shares of the combined entity; or



(iii)

the shareholders of the Corporation or of EXCO approve the sale, transfer or lease of all or substantially all of the assets of the Corporation or of EXCO to a corporation other than EXCO or the Corporation or an affiliate of EXCO or the Corporation.

8.

Method of Exercise of Options

(a)

Except as set forth in Sections 7, 9 and 10 or as otherwise determined by the Board, no Options may be exercised unless the holder of such Options is, at the time the Options are exercised, an employee of the Corporation.

(b)

Any Participant (or his legal personal representative) wishing to exercise Options shall deliver to the Corporation at its principal office:

(i)

a duly executed Exercise Form expressing the intention of such Participant (or his legal personal representative) to exercise some or all of his Options and specifying the number of Options in respect of which the notice is given, accompanied by payment in full of the Option Price. Payment on exercise of an Option may be made by the Participant in cash or certified cheque, or such other form of payment as may be permitted by the Board at any time prior to exercise of the Option; and

(ii)

in the event that the Options are exercised in accordance with the Plan by a person other than the Participant, proof satisfactory to the Corporation of the right of such person to exercise the Options.

6

(c)

Except in connection with a Change of Control of the Corporation, upon exercising the Options each Participant shall hold the shares issued pursuant to the Options for a period of six (6) consecutive months. At the end of such period EXCO shall pay to each Participant so exercising the Determined Value Per Option for each Option so exercised. Each Participant shall return for cancellation any shares of the Corporation for which he has received payment pursuant to this clause.



(d)

If, in the event of a Change of Control of the Corporation, a Participant exercises such Participant's Options, EXCO shall pay to each Participant the Determined Value Per Option exercised by such Participant, at the effective time of the Change of Control or as soon thereafter as is reasonably practicable, but in no event later than employees of EXCO are entitled to receive payment for stock options they hold in EXCO.



(e)

Any shares issued to a Participant pursuant to this Plan shall be subject to the shareholder agreement which is attached hereto as Schedule "D", reference to which is here made for all purposes and the terms of which shall have the same effect as if included herein.

9.

Termination of Employment

        If a Participant's employment with the Corporation terminates for any reason other than death, Permanent Disability or retirement at normal retirement age, all Options held by such Participant that have not vested prior to the date of such termination shall immediately and automatically become null and void and shall not be exercisable under any circumstances, and all vested Options shall remain exercisable until 5:00 p.m. (Calgary time) on the earlier of the fifth anniversary of the date of grant of such Options and the ninetieth day following the date of such termination, or such later date as may be determined by the Board. For the purposes of the Plan, if a notice of termination or notice of resignation is provided in connection with any such termination of employment, the date of termination shall be the date on which notice of termination of employment is provided by the Corporation to the Participant or notice of resignation as an employee is provided by the Participant to the Corporation, as the case may be.

        If the employment relationship between the Participant and the Corporation is terminated for any reason prior to the fifth anniversary of the date of grant of the Options, the Participant's rights in respect of the Options shall be strictly limited to those expressly provided for in this Section 10, and the Participant shall have no claim or entitlement to any unvested Options which would have vested during any notice period arising from the termination of the Participant's employment (whether at common law or pursuant to the terms of any statute or agreement) but for the termination of the Participant's employment. The Participant shall also have no claim or entitlement to exercise any vested Options during any notice period arising from the termination of the Participant's employment (whether at common law or pursuant to the terms of any statute or agreement) other than as expressly set out herein.

        A former employee whose employment with the Corporation was terminated and is eligible to exercise Options shall be entitled to exercise such Options and to receive from EXCO, at the Participant's election, the Determined Value Per Option for:

(a)

the most recent prior Participating Year; or



(b)

the Participating Year in which his employment was terminated.

Such election shall be made by the Participant by giving written notice thereof to EXCO on or before the 30th day after termination of employment. If such notice is not made by the timely giving of such notice, the Determined Value Per Option for the most recent prior Participating Year shall be used.

7

        A former employee who resigns from the Corporation prior to normal retirement age shall be entitled to exercise Options vested upon the date of resignation and to receive from EXCO, at the Corporation's election the Determined Value Per Option for:

(a)

the most recent prior Participating Year; or



(b)

the Participating Year in which he resigned.

Such election shall be made by EXCO by giving written notice thereof to the Participant on or before the 30th day after resignation by the Participant. If such notice is not made by the timely giving of such notice, the Determined Value Per Option for the most recent prior Participating Year shall be used.

        Neither the identification of any person as a Participant nor the granting of any Options to a Participant shall (i) confer upon such Participant any right to continue as an employee of the Corporation, (ii) be construed as a guarantee that such Participant will continue as an employee of the Corporation, or (iii) nullify any right that such Participant or the Corporation may have to terminate his position as an employee of the Corporation at any time.

10.

Death, Permanent Disability or Retirement of a Participant

        In the event of the death, Permanent Disability or retirement at normal retirement age of a Participant, any Options previously granted to such Participant that had not vested as at the date of death, Permanent Disability or retirement shall immediately and automatically become null and void and shall not be exercisable under any circumstances, and any other Options that had vested prior thereto shall be exercisable until the earlier of the fifth anniversary of the date of grant of such Options and the 180^th day following the date of death, Permanent Disability or retirement at normal retirement age of such Participant, and in the event of death or Permanent Disability the Options shall be exercisable by the person or persons to whom the Participant's rights under the Options have passed under the Participant's will or applicable law.

11.

Adjustments

(a)

The Determined Value Per Option shall be increased or decreased proportionately in the event of a stock split, stock dividend, combination of shares, or subdivision or consolidation of the common shares of the Corporation.

(b)

Adjustments under this Section 11 shall be made by the Board, whose determination as to what adjustments shall be made, if any, and the extent thereof shall be final, binding and conclusive.

12.

Transferability

        All Options and all benefits and rights accruing to any Participant in accordance with the terms and conditions of the Plan shall be non-transferable and non-assignable unless specifically provided herein. Options may be exercised only by the Participant or, in the event of the death or Permanent Disability of a Participant, by the person or persons to whom the Participant's rights under the Options have passed under the Participant's will or applicable law.

13.

Suspension, Termination or Amendment of Plan

        The Board may, at any time in its absolute and unfettered discretion, suspend or terminate the Plan without prior notice to, or the consent of, the Participants, provided that such suspension or termination shall not affect any Options then outstanding. The Board may also at any time in its absolute and unfettered discretion amend or revise the terms of the Plan or any agreement in respect of Options granted pursuant to the Plan, provided that no such amendment or revision shall in any manner adversely affect the rights of a Participant under any Options theretofore granted without such Participant's consent. Participants shall be advised by the Corporation of any such amendments or revisions unless, in the opinion of the Board, they are immaterial or non-substantive.

8

14.

Gender

        Words used in the Plan importing gender shall include all genders.

15.

Governing Law

        The Plan will be governed by and construed in accordance with the laws of the Province of Alberta.

Dated at Calgary, Alberta, as of the 30th day of June, 2002.

ADDISON ENERGY INC.

Per:

Per:

ACKNOWLEDGED AND AGREED TO
effective the 30th day of June, 2002, by

EXCO RESOURCES, INC.

Per:

9

SCHEDULE A

ADDISON ENERGY INC.

June 30, 2002

TO: JONATHAN KUHN

        We are pleased to advise you that you have been granted 20 options ("Options") pursuant to the terms of the Stock Option Agreement dated June 30, 2002 (the "Plan"). Under the Plan, you have been granted Options which, upon exercise, entitle you to purchase shares of common stock of Addison Energy Inc. in accordance with the terms of this letter and the Plan.

        The vesting periods and expiry dates for your Options are as follows:

Cumulative Number of Options	Vesting Date	Expiry Date
10  (50% of total)	April 26, 2003	June 30, 2007
15  (75% of total)	April 26, 2004	June 30, 2007
20 (100% of total)	April 26, 2005	June 30, 2007

        Except as set forth in this letter, your Options are governed by the terms and conditions of the Plan.

        The Base Value Per Option of Addison Energy Inc. for the purposes of the Plan at June 30, 2002, as determined in accordance with the terms of the Plan is $1,031.61.

        The granting of these Options and the specification of vesting and expiry dates does not constitute any offer of continued or guaranteed employment and your rights with respect to the Options in the event of termination of your employment are as set out in the Plan.

        We wish to thank you for your valuable contribution to the Corporation both now and in the future. By granting Options to you we hope to allow you to share more directly in the future growth and success of the Corporation, of which you are an integral part. By executing this letter you acknowledge and accept the granting of these Options in accordance with the terms and conditions of the Plan and agree to be bound by the terms and conditions of the Plan.

	Yours truly,
	ADDISON ENERGY INC.
	Per:
	ACKNOWLEDGED AND AGREED TO by EXCO RESOURCES, INC.
	Per:
Witness	JONATHAN KUHN

SCHEDULE B

NOTICE OF DETERMINED VALUE PER OPTION

[Date]

TO:

        The Board of Directors of Addison Energy Inc. has determined the Determined Value Per Option of your Options for the year ended December 31, [2002/2003/2004/2005] to be $            per Option. You are under no obligation to exercise any of your Options.

Yours truly,

ADDISON ENERGY INC.

Per:

ACKNOWLEDGED AND AGREED TO
effective the    day of June 2002 by

EXCO RESOURCES, INC.

Per:

SCHEDULE C

EXERCISE FORM AND POWER OF ATTORNEY

TO:	ADDISON ENERGY INC. ATTENTION: Corporate Secretary
AND TO:	EXCO RESOURCES. INC. ATTENTION: Secretary

        The undersigned (the "Participant") hereby irrevocably exercises            options to purchase common shares (the "Purchased Shares") of Addison Energy Inc. ("Addison") pursuant to the stock option plan (the "Plan") of Addison established by the Stock Option Agreement between Addison and EXCO Resources, Inc. ("EXCO") dated June 30, 2002 (the "Agreement").

        The Participant acknowledges that the Participant and the Purchased Shares will be subject to and governed by (i) the Plan as specified in the Agreement, (ii) the Unanimous Shareholder Agreement made as of June 30, 2002, among Addison, EXCO, the Participant, and the other holders of options granted under the Plan, and (iii) the Irrevocable Stock Power of Attorney attached hereto, and the Participant hereby:

1.

irrevocably constitutes and appoints EXCO, its successors and assigns and any officer of EXCO, its successors and assigns, and each of them, and any other person designated by EXCO, its successors and assigns in writing, as the true and lawful agent, attorney and attorney-in-fact and proxy of the undersigned with respect to the Purchased Shares, with full power of substitution, in the name and on behalf of the undersigned (such power of attorney being deemed to be an irrevocable power coupled with an interest):

(a)

to register or record, transfer and enter any transfer of the Purchased Shares on the appropriate register of holders maintained by Addison; and

(b)

except as otherwise may be agreed, to exercise any and all of the rights of the holder of the Purchased Shares including, without limitation, to (i) vote, execute and deliver any and all instruments of proxy, authorizations or consents in respect of all or any of the Purchased Shares, (ii) revoke any such instrument, authorization or consent, (iii) designate in any such instruments of proxy any person or persons as the proxy or the proxy nominee or nominees of the Participant in respect of such Purchased Shares for all purposes including, without limitation, in connection with any meeting (whether annual, special or otherwise and any adjournments thereof) of holders of securities of Addison, and (iv) execute, endorse and negotiate, for and in the name of and on behalf of the registered holder of Purchased Shares, any and all cheques or other instruments respecting any distribution payable to or to the order of such holder in respect of such Purchased Shares;

2.

agrees not to vote any of the Purchased Shares at any meeting (whether annual, special or otherwise or any adjournment thereto) of holders of securities of Addison and, except as may otherwise be agreed, not to exercise any or all of the other rights or privileges attached to the Purchased Shares, and agrees to execute and deliver to EXCO any and all instruments of proxy, authorizations or consents in respect of the Purchased Shares and to designate in any such instruments of proxy the person or persons specified by EXCO as the proxy or proxy nominee or nominees of the holder of the Purchased Shares in respect of the Purchased Shares and acknowledges that upon such appointment, all prior proxies given by the holder of such Purchased Shares with respect thereto shall be revoked and no subsequent proxies may be given by such person with respect thereto;

3.

agrees that if Addison should declare or pay any cash dividend, stock dividend or make any other distribution on or issue any rights with respect to any of the Purchased Shares which is or are payable or distributable to the shareholders of record on a record date which is prior to the date of transfer into the name of EXCO or its nominees or transferees on the registers maintained by

Addison of such Purchased Shares following the purchase thereof pursuant to the Plan, then the whole of any such dividend, distribution or right will be received and held by the Participant for the account of EXCO and shall be promptly remitted and transferred by the Participant to EXCO, accompanied by appropriate documentation of transfer. Pending such remittance, EXCO will be entitled to all rights and privileges as the owner of any such dividend, distribution or right, and may withhold the entire consideration payable by EXCO pursuant to the Plan or deduct from the consideration payable by EXCO pursuant to the Plan the amount or value thereof, as determined by EXCO in its sole discretion;

4.

covenants to execute, upon request, any additional documents, transfers and other assurances as may be necessary or desirable to complete the sale, assignment and transfer of the Purchased Shares to EXCO or its nominees or transferees;

5.

acknowledges and agrees that all authority conferred or agreed to be conferred by the Participant herein may be exercised during any subsequent legal incapacity of the Participant and shall survive the death or incapacity, bankruptcy or insolvency of the Participant and all obligations of the Participant herein shall be binding upon the heirs, personal representatives, successors and assigns of the Participant.

Dated this                        day of                        , 200    .

Witness Signature of Participant
Name of Participant:

        The name and address of the person in whose name the shares of Addison Energy Inc. are to be registered is as follows:

Name
	(please print full name)
Address:
Postal Code:

NOTE:
One completed copy of this Exercise Form and Power of Attorney is to be delivered to Addison Energy Inc. and one completed copy of this Exercise Form and Power of Attorney together with a signed and witnessed Irrevocable Stock Power of Attorney in the form attached is to be delivered to EXCO Resources, Inc.

IRREVOCABLE STOCK POWER OF ATTORNEY

        FOR VALUE RECEIVED the undersigned hereby sells, assigns and transfers unto ____________
____________________________, ______________________________________________________________
common shares of Addison Energy Inc. standing in the name of the undersigned on the books of the said corporation represented by Certificate No.    and hereby irrevocably constitutes and appoints ______ ______________________ the true and lawful attorney of the undersigned to transfer the said shares on the books of the said corporation with full power of substitution in the premises.

DATED:
SIGNED, SEALED AND DELIVERED	)
in the presence of	)
	)
	)
	)
Witness	)	Name:

Schedule "D"


UNANIMOUS SHAREHOLDER AGREEMENT

THIS AGREEMENT made as of the 30^th day of June, 2002

AMONG:

ADDISON ENERGY INC. a corporation incorporated under the laws of the Province of Alberta (the "Corporation")

–and–

EXCO RESOURCES, INC. a corporation incorporated under the laws of the State of Texas ("EXCO")

–and–

CRAIG HRUSKA, an individual resident in the Province of Alberta ("Hruska")

–and–

STEVE FAGAN, an individual resident in the Province of Alberta ("Fagan")

–and–

DENNIS MCINTYRE, an individual resident in the Province of Alberta ("McIntyre")

–and–

ROBERT HEMMINGER, an individual resident in the Province of Alberta ("Hemminger")

–and–

GREGORY ROBB, an individual resident in the Province of Alberta ("Robb")

–and–

RON JOCSAK, an individual resident in the Province of Alberta ("Jocsak")

–and–

JAMES BENINGER, an individual resident in the Province of Alberta ("BENINGER")

–and–

DUANE MASSE, an individual resident in the Province of Alberta ("Masse")

–and–

TERRY PIDKOWA, an individual resident in the Province of Alberta ("Pidkowa")

–and–

JONATHAN KUHN, an individual resident in the Province of Alberta ("Beninger")

WHEREAS EXCO is the registered and beneficial owner of all of the issued and outstanding shares of the Corporation;

AND WHEREAS the Corporation has established a stock option plan on the terms set forth in the Stock Option Agreement pursuant to which Options will be granted to the Participants and Common Shares will be issued upon the exercise of Options;

AND WHEREAS it is the intention of the Shareholders to enter into an agreement to, among other things, restrict the transfer or other assignment of shares of the Corporation to the circumstances specified in the Stock Option Agreement.

NOW THEREFORE THIS AGREEMENT WITNESSES that in consideration of the mutual covenants of the parties and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged by each of the parties hereto, the parties covenant and agree as follows:

ARTICLE 1
INTERPRETATION

1.1

Definitions

In this Agreement:

(a)

"Agreement" means this agreement, as amended from time to time;



(b)

"Common Shares" means common shares in the capital of the Corporation;



(c)

"Option Shares" means Common Shares issued upon the exercise of Options;



(d)

"Options" means the right granted to the Participants to purchase shares in the Corporation in accordance with the terms of the Plan;



(e)

"Participants" means Hruska, Fagan, McIntyre, Hemminger, Robb, Jocsak, Kuhn, Pidkowa, Beninger and Masse and any other individuals to whom Options are granted under the Plan;



(f)

"Plan" means the stock option plan of the Corporation established pursuant to the Stock Option Agreement;



(g)

"Power of Attorney and Proxy" means the power of attorney and proxy to be delivered by a Participant as a condition of exercise of any Options;



(h)

"Shareholders" means EXCO, the Participants and any other persons who are or become the beneficial owners of Common Shares and each of their respective heirs, executors, administrators, other legal representatives, successors and assigns;



(i)

"Stock Option Agreement" means the agreement dated as of June 30, 2002, between the Corporation and EXCO.

1.2

Except as herein provided, this Agreement supersedes all former understandings and agreements relating to the disposition of shares of the Corporation and the other matters herein provided and all such understandings are hereby declared to be of no further force or effect whatsoever.

1.3

The parties agree that should there be, or at any time during which this Agreement is in force should there hereafter arise, any conflict between the provisions of this Agreement and the by-laws of the Corporation, then any of the parties may at any time require the others to the extent they are able with him to cause the by-laws of the Corporation to be amended to the extent necessary to remove or correct such conflict.

ARTICLE 2
CORPORATE AFFAIRS

2.1

Each of the Participants covenants and agrees that, to the extent the Participant is entitled to exercise voting rights in respect of any shares of the Corporation to which Participant's Power of Attorney and Proxy does not apply, the Participant will exercise all voting rights attached to any such shares as directed by EXCO in relation to any corporate action proposed in respect of the Corporation.

ARTICLE 3
RESTRICTION ON TRANSFER

3.1

Each of the Participants acknowledges and agrees that, unless otherwise agreed to by the Corporation and EXCO, the Participant's sole right to acquire Common Shares arises or will arise

upon the exercise of Options granted to the Participant under the Plan, and that the Participant is not and will not be entitled to sell, transfer or otherwise dispose of any Common Shares other than as provided in the Stock Option Agreement. Each Participant further acknowledges and agrees that, prior to becoming entitled to be registered as the owner of any Common Shares issuable upon the exercise of Options, the Participant must deliver to the Corporation an executed stock transfer power of attorney in respect of such Common Shares and a Power of Attorney and Proxy in the form annexed hereto as Schedule "A". Each of the Participants acknowledges that the delivery of these documents is a condition to the exercise of any Options and acknowledges that these documents are or will be delivered for the purpose of enabling EXCO and the Corporation to ensure that no Common Shares owned by any of the Participants may be transferred other than as permitted by the Stock Option Agreement or as otherwise agreed to in writing by EXCO, the Corporation and each of the other Participants.

ARTICLE 4
TRANSFER OF SHARES BY OPERATION OF LAW

4.1

The purported transfer at any time during the term of this Agreement of the whole or any portion of a Participant's Common Shares by operation of law (including death) or as a result of the appointment of a trustee in bankruptcy or the purported transfer by way of involuntary transfer of shares, including, but not restricted to, a purported sale under any judgment or purported acquisition of title by or transfer to any trustee, receiver or assignee for the benefit of creditors, shall be deemed to be a grant immediately prior to such event to EXCO of an option to purchase such Common Shares for the amount and at the time specified in the Stock Option Agreement or as determined in accordance with the Stock Option Agreement.

ARTICLE 5
GENERAL PROVISIONS

5.1

This Agreement shall terminate at such time as shall be determined by EXCO after the Plan has expired and the Corporation has no shareholders other than EXCO and no other person has any right to acquire any Common Shares of the Corporation.

5.2

This Agreement may be altered or amended as to any of its provisions when any such changes are reduced to writing and signed by all parties hereto.

5.3

Each of the parties hereto undertakes and agrees to execute and deliver such further and other documents and assurances as may be necessary to give full force and effect to all of the terms and conditions of this Agreement, the Stock Option Agreement and the Plan.

5.4

This Agreement shall enure to the benefit of and be binding upon each of the parties hereto and their respective heirs, executors, administrators, other personal representatives, successors and assigns.

5.5

Wherever the singular is used, it shall be deemed to extend to and include the plural, and where one gender is used, it shall include all genders, and when any party is referred to, it shall extend to that party's heirs, executors, administrators, other personal representatives, successors and assigns.

5.6

Any notice which one party may wish to give to another party may be given personally or by sending the same by prepaid registered mail in an envelope addressed as follows:

In the case of Hruska, Fagan, McIntyre, Hemminger, Robb, Jocsak, Kuhn, Pidkowa, Beninger and Masse:

1100, 635 - 8th Avenue SW
Calgary, AB T2P 3M3

In the case of EXCO and the Corporation:

6500 Greenville Avenue, Suite 600, LB17
Dallas, TX 75206

and any notice so sent shall be deemed to have been received on the fifth (5^th) business day following that on which it is mailed. Any party may change its address for notice from time to time by notice served as above set out.

5.7

This Agreement shall be interpreted in accordance with and be governed by the laws of the Province of Alberta.

5.8

The headings in this Agreement are inserted for convenience only and do not form part of this Agreement or in any way limit or define the clauses to which they relate.

5.9

Each of the Shareholders shall consider as confidential and use all best efforts to prevent the communication to others, both during the term of this Agreement and thereafter, all information, other than that which is public, that shall have been acquired as a result of that Shareholder's relations with the Corporation.

5.10

This Agreement shall become effective as of the date first above written.

5.11

A Shareholder who no longer holds any Common Shares or Options and who has not breached any of the provisions of this Agreement, the Stock Option Agreement and the Plan shall be deemed to be released from the provisions of this Agreement other than the provisions of clause 5.9.

5.12

Any and all prior agreements, whether written or oral, respecting the ownership of shares or the conduct of the business and affairs of the Corporation, are terminated effective as of the date first above written, and this Agreement together with the Stock Option Agreement and the documents delivered or to be delivered pursuant hereto and thereto constitutes the entire agreement among the Shareholders respecting the ownership of shares and the conduct of the business and affairs of the Corporation.

5.13

Time shall be of the essence in this Agreement.

5.14

If any covenant, obligation or agreement contained in this Agreement or the application thereof to any person or circumstances shall, to any extent, be invalid or unenforceable, the remainder of this Agreement or the application of such covenant, obligation or agreement to persons or circumstances other than those as to which it is held invalid or unenforceable shall not be affected thereby, and each covenant, obligation and agreement shall be separately valid and enforceable to the fullest extent permitted by law.

IN WITNESS WHEREOF we have hereunto set our hands and seals as of the day and year first above written.

ADDISON ENERGY INC.	EXCO RESOURCES, INC.
Per:	Per:
Title:	Title:
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	CRAIG HRUSKA
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	STEVE FAGAN
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	DENNIS MCINTYRE
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	ROBERT HEMMINGER
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	GREGORY ROBB
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	RON JOCSAK
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	JONATHAN KUHN
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	TERRY PIDKOWA
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	JAMES BENINGER
SIGNED, SEALED AND DELIVERED in the presence of:
Witness	DUANE MASSE

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Exhibit 10.27

TABLE OF CONTENTS
ADDISON ENERGY INC. STOCK OPTION AGREEMENT
SCHEDULE A
ADDISON ENERGY INC.

June 30, 2002

SCHEDULE B NOTICE OF DETERMINED VALUE PER OPTION
SCHEDULE C EXERCISE FORM AND POWER OF ATTORNEY
IRREVOCABLE STOCK POWER OF ATTORNEY
Schedule "D" UNANIMOUS SHAREHOLDER AGREEMENT
ARTICLE 1 INTERPRETATION
ARTICLE 2 CORPORATE AFFAIRS
ARTICLE 3 RESTRICTION ON TRANSFER
ARTICLE 4 TRANSFER OF SHARES BY OPERATION OF LAW
ARTICLE 5 GENERAL PROVISIONS

EX-21.1

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EXHIBIT 21.1

SUBSIDIARIES OF EXCO RESOURCES, INC.

Entity Name	State or Province of Incorporation
Addison Energy Inc.	Alberta, Canada
Kantec Petroleum (Southern) Ltd. (a subsidiary of Addison Energy Inc.)	Alberta, Canada
EXCO Investment I, LLC	Delaware
EXCO Investment II, LLC	Delaware
EXCO Operating, LP	Delaware
Taurus Acquisition, Inc.	Texas

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EXHIBIT 21.1

SUBSIDIARIES OF EXCO RESOURCES, INC.

EX-23.1

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Exhibit 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

        We consent to the incorporation by reference in the Registration Statement Form S-8 (No. 333-64331), the Registration Statement Form S-2A on Form S-3 (No. 333-49135), the Registration Statement Form S-3 (No. 333-70342), the Registration Statement Form S-3 (No. 333-60462), and the Registration Statement Form S-8 (No. 333-59596) of our report dated February 28, 2003 (except Note 13, as to which the date is March 11, 2003) with respect to the consolidated financial statements of EXCO Resources, Inc. included in this Annual Report on Form 10-K for the year ended December 31, 2002.

Dallas, Texas
March 24, 2003

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Exhibit 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

EX-23.2

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Exhibit 23.2

[LEE KEELING AND ASSOCIATES, INC. LETTERHEAD]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Lee Keeling and Associates, Inc. ("Lee Keeling") hereby consents to the references to Lee Keeling as an expert, its reserve reports at December 31, 2002 and to information depicted in the Annual Report on Form 10-K for the year ended December 31, 2002 for EXCO Resources, Inc., a Texas corporation, that was derived from our reserve reports. Lee Keeling also consents to the references to Lee Keeling as an expert, its reserve reports at December 31, 2002 and to information depicted in the Annual Report on Form 10-K for the year ended December 31, 2002 for EXCO Resources, Inc., a Texas corporation, that was derived from our reserve reports for incorporation by reference in the Registration Statement Form S-2/A on Form S-3 (No. 333-49135) and related Prospectus, the Registration Statement Form S-3 (No. 333-60462) and related Prospectus, the Registration Statement Form S-3 (No. 333-70342) and related Prospectus, and Registration Statement Form S-8 (No. 333-59596) and related Prospectus and Registration Statement Form S-8 (No. 333-64331) and related Prospectus.

	LEE KEELING AND ASSOCIATES, INC.
	By:	/s/  KENNETH RENBERG Kenneth Renberg
Tulsa, Oklahoma March 25, 2003

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Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

EX-99.1

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Exhibit 99.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Annual Report of EXCO Resources, Inc. (the "Company") on Form 10-K for the annual period ended December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Douglas H. Miller, Chairman of the Board and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

        (1)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

        (2)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ DOUGLAS H. MILLER      
Douglas H. Miller
Chairman of the Board and Chief Executive Officer

Dated: March 12, 2003

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Exhibit 99.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

EX-99.2

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Exhibit 99.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Annual Report of EXCO Resources, Inc. (the "Company") on Form 10-K for the annual period ended December 31, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, J. Douglas Ramsey, Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

        (1)  The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

        (2)  The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. DOUGLAS RAMSEY      
J. Douglas Ramsey
Vice President and Chief Financial Officer

Dated: March 12, 2003

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Exhibit 99.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002