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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the Fiscal Year Ended December 31, 2001
OR

For the Transition Period from                              to                             

Commission File Number 0-9204

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

(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

        The number of shares of Common Stock, par value $.02 per share, of the Registrant outstanding on February 28, 2002, was 7,183,137. The aggregate market value of the voting common equity held by non-affiliates (all directors and executive officers are presumed to be affiliates) of the Registrant on February 28, 2002, was approximately $87.8 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

        Portions of the Registrant's Proxy Statement for the 2002 Annual Meeting of Shareholders, filed on March 19, 2002, are incorporated by reference into Part III.

TABLE OF CONTENTS

EXCO RESOURCES, INC.

PART I

ITEM 1. BUSINESS

General

        EXCO Resources, Inc. is an independent energy company engaged in the acquisition, development and exploitation of oil and natural gas properties. Our primary areas of operations are onshore in Texas, Louisiana, 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. Since December 1997, we have completed 44 acquisitions for total net consideration of approximately $220.0 million, including 13 acquisitions for aggregate net consideration of approximately $114.0 million since January 1, 2001. Overall, our acquisitions have been made at an average cost of approximately $0.73 per Mcfe of proved reserves. 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, coupled with our experienced oil and natural gas operating and technical team, provide us with significant growth potential from development and exploitation activities.

        Our Canadian results are converted for use in this report from Canadian dollars to U.S. dollars using an exchange rate of $0.628 per CDN $1.00 for balance sheet items including cash, oil and natural gas properties and bank debt (the rate at December 31, 2001). For income statement items such as revenue, production costs, general and administrative costs and interest, we convert Canadian dollars to U.S. dollars using the average exchange rate across the applicable period. The average exchange rate for the year 2001 was $0.644 per CDN $1.00.

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, while continuing 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 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 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.

        In 2001, we evaluated approximately 175 acquisition opportunities with an aggregate estimated market value of over $3.6 billion. We made offers on properties totaling more than $885 million and successfully completed the purchase of approximately $114 million of oil and natural gas properties and related assets. Offers varied in amounts from less than $10,000 to $150 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 2001

We acquired oil and natural gas properties in Texas and Oklahoma.

        In March 2001, we acquired from STB Energy, Inc. oil and natural gas properties located in Texas, Oklahoma, Louisiana and Nebraska. As of January 1, 2001, estimated total proved reserves net to our interest included 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).

We acquired Addison Energy Inc.

        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 time 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 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 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 U.S. and Canadian credit agreements.

        We have also entered into employment agreements with the Addison management team to provide incentives for the continued growth of Addison. These incentives include a share appreciation rights plan which rewards the Addison managers for additions to Addison's reserves based upon certain established benchmarks. The incentives are payable in cash or our common stock at the election of the employee.

        The Addison managers also 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. They purchased in the open market 24,940 shares worth $455,144. In addition, as part of the Addison purchase, we issued 49,880 shares worth $910,310 to the Addison managers. The resale of the shares is restricted.

We entered into new credit agreements.

        As a result of the acquisition of Addison, we revised our banking arrangements. On April 26, 2001, we repaid all outstanding indebtedness owed to a syndicate of banks lead by Bank of America, N.A. and canceled the credit agreement. At the same time, we entered into two new credit agreements, a U.S. credit agreement and a Canadian credit agreement. On December 18, 2001, the U.S. credit

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agreement and the Canadian credit agreement were restated as part of the financing of the acquisition of the PrimeWest properties (see "Our subsidiary, Addison Energy Inc., acquired additional oil and natural gas properties in Canada" below).

        The restated U.S. credit agreement, with Bank One, N.A., as administrative agent, provides for borrowings of up to $124.0 million under a revolving agreement with an initial borrowing base of $58.0 million. At December 31, 2001, we had approximately $3.5 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $54.2 million available for borrowing under the restated U.S. credit agreement. The restated Canadian credit agreement, with Bank One, N.A. Canada Branch as administrative agent, provides for borrowings of up to $48.7 million under a revolving credit agreement with an initial borrowing base of $45.0 million. At December 31, 2001, we had approximately $41.5 million of outstanding indebtedness and approximately $3.5 million available for borrowing under the restated Canadian credit agreement.

        For more information about our credit agreements, please review "Our Liquidity and Capital Resources—Credit Agreements" in "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations."

We issued over 5 million shares of 5% convertible preferred stock.

        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 repay bank loans with the remaining proceeds used for general corporate purposes.

        For more information about the 5% convertible preferred stock, please review "Our Liquidity and Capital Resources—Effects of the 5% Convertible Preferred Stock Offering" in "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations."

We dissolved Pecos-Gomez, L.P. and acquired additional interest in the Pecos County Properties.

        On July 3, 2001, Pecos-Gomez, L.P. (the Partnership) distributed to its partners all of the interest in the Partnership's properties. At that time, we acquired additional working interests in the properties from two of the limited partners for $8.8 million (approximately $7.5 million after contractual adjustments). In addition, we received an assignment of the existing hedge agreement that was previously entered into by the Partnership. Borrowings under the Partnership credit agreement of $3.9 million were also repaid at the time of the acquisition and the credit agreement was canceled.

We terminated our existing hedge agreements and entered into new hedge agreements.

        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. The counterparty of the swap agreements that we entered into during 2000 and through September 2001 was an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities (including the Enron affiliate that was the counterparty to our swap agreements) 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 the Enron affiliate, 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, 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.

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        In December 2001, we entered into new, replacement hedge transactions with a new counterparty, BNP Paribas, (the BNP Paribas Hedges), a financial lending institution. BNP Paribas is a lender to us under our U.S. and Canadian credit agreements. For more information concerning the new hedging contracts as well as the accounting treatment of the terminated Enron Hedges, please review "Item 7A—Quantitative and Qualitative Disclosure about Market Risk".

Our subsidiary, Addison Energy Inc., acquired additional oil and natural gas properties in Canada.

        On December 18, 2001, Addison acquired oil and natural gas properties located in west central Alberta, Canada from PrimeWest Energy Inc. and PrimeWest Oil and Gas Corp. for $33.8 million ($33.6 million after contractual adjustments). The properties consisted of 96 gross (73.8 net) producing oil and natural gas wells. Under the terms of the acquisition, Addison became the operator of 78 of the wells. As of December 31, 2001, estimated total proved reserves net to our interest included 3.6 million Bbls of oil and NGLs and 27.1 Bcf of natural gas. Net daily production, as of December 2001, was approximately 600 Bbls of oil and NGLs and 4.1 Mmcf of natural gas.

Developments Since December 31, 2001

Our subsidiary, Addison Energy Inc., entered into an agreement to purchase oil and natural gas assets.

        On January 25, 2002, Addison entered into an agreement to purchase oil and natural gas assets in Alberta, Canada, from an independent producer totaling approximately $26.2 million (CDN $41.6 million). We estimate total proved reserves net to our interest of approximately 1.6 million Bbls of oil and NGLs and 19.0 Bcf of natural gas. We expect net daily production from these properties to be approximately 4.8 Mmcf of natural gas, 385 Bbls of oil and 195 Bbls of NGLs per day or 8.3 Mmcfe.

We entered into additional hedge agreements.

        On March 12, 2002, we entered into two agreements to hedge additional natural gas volumes on a portion of our expected production for 2002 and 2003. The counterparty to these agreements was BNP Paribas. For more information concerning the additional hedging contracts, please review "Item 7A-Quantitative and Qualitative Disclosure about Market Risk".

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 Operations," provide 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 our underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this 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 have been and may continue to be subject to lower market prices than natural gas prices in the United States. 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 substantially depends 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 other party to the hedging contract defaults on its contract 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 discussed above in "Developments During 2001," we terminated the Enron Hedges due to the bankruptcy filing of Enron Corp. and certain of its affiliates and the failure of Enron North America to make payments totaling approximately $2.1 million due us on hedged oil and natural gas volumes. Based upon oil and natural gas futures prices on the effective date of termination, we believe that we are owed approximately $15.3 million, including settlements already due. For the year ended December 31, 2001, our revenues were increased by approximately $6.9 million as a result of cash settlements actually received on the Enron Hedges. As of December 31, 2001, the unrealized gain on the BNP Paribas Hedges was $696,000 and our hedged volumes represented approximately 57%—61% of our forecasted oil production and 50%—54% of our forecasted natural gas production during 2002. 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 and the accounting for the Enron Hedges, please review "Item 7A—Quantitative and Qualitative Disclosure 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 which 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 proved reserves will generally decline as they are produced. Also, our production will generally decline. If our production declines then our revenues will decline unless an increase in oil and natural gas prices offsets the declines. In addition, if our reserves and production decline then the amount we

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are able to borrow under our credit agreements will also decline. We cannot assure you that we will be able to locate additional reserves or that we will drill economically productive wells or acquire properties containing proved reserves.

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

        We have recently completed several large acquisitions and 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 assure you that our recently acquired oil and natural gas properties will be successfully integrated into our operations or will 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 on third parties to transport our products. Transportation space on the gathering systems and pipelines we utilize is occasionally limited and at times unavailable due to repairs or improvements to facilities or due to space being utilized by other companies with priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state and Canadian regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and, consequently, 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. As a result, 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. 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 the financial results of our operations and may have a material adverse effect on our results of operations and our financial condition.

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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 are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agreed to provide indemnity, we cannot assure you that the indemnity would be fully enforceable.

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

        As of December 31, 2001, we have aggregate debt outstanding of approximately $45.0 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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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; or



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engage in specified transactions with subsidiaries and affiliates and our 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

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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 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 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 through production data and engineering studies, geophysical and geological analyses, and seismic and other data, the results of which are often inconclusive and subject to various interpretations.

We cannot control the development of a portion of our properties because our interests are in the form of non-operated working interests.

        We do not operate wells that represent approximately 20% of the PV-10 (as of December 31, 2001) of our proved reserves. As a result, the success and timing of our drilling and development activities on those properties operated by others depend upon a number of factors outside of our control, including:

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the timing and amount of capital expenditures;



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the operator's expertise and financial resources;



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the approval of other participants in drilling wells; and



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the selection of suitable technology.

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

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

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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, these estimates are an inherently imprecise evaluation of reserve quantities and future net revenues. Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves may vary substantially from 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:

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fire, explosions and blowouts;



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pipe failures;



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abnormally pressured formations; and



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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:

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injury or loss of life;



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



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pollution or other environmental damage;



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clean-up responsibilities;



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regulatory investigation; and



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penalties and suspension of operations.

        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.

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

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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 which were in compliance with all applicable laws at the time these 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.

        As a result of low oil and natural gas prices on September 30, 2001, we recorded a pre-tax non-cash ceiling test write-down of $45.9 million (of which $25.0 million was from the United States full cost pool and $20.9 million was from the Canadian full cost pool). We recorded an additional pre-tax non-cash ceiling test write-down of approximately $3.7 million from our United States full cost pool during the fourth quarter of 2001 as a result of low oil and natural gas prices on December 31, 2001. Depending upon oil and natural gas prices, we may be required to further 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 our covenants under our credit agreements.

We may not be permitted to pay cash dividends on our convertible preferred stock in some circumstances. We could also be prevented in some circumstances from paying dividends in 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 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. We cannot assure you that we will have any surplus.

The 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 the convertible preferred stock.

        The convertible preferred stock is subordinated to all of our indebtedness with respect to the payments of interest and amounts distributable upon our dissolution, liquidation or winding up. The terms of the 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 the convertible preferred stock.

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Sales, or the availability for sale, of substantial amounts of our common stock could adversely affect the value of the 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 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 the 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 held by the public 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 4,995,131 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 NGLs 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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        Other than the SEC, we have not filed any estimates or included estimates in reports to any other federal authority or agency since January 1, 2001. The following table summarizes our proved reserves at the dates shown, and was prepared according to the rules and regulations of the SEC:

        The reserve estimates presented as of December 31, 1999, 2000 and 2001, 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 annual report for additional information regarding our oil, natural gas and NGL reserves, including the present value of future net revenues.

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        The following table set forth our proved reserves and PV-10 by area as of December 31, 2001:

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:

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Our Interest in Productive Wells

        The following table sets forth our interest in productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells on December 31, 2001. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refers to the total number of physical wells that we hold any working interest in, regardless of our percentage interest. A net well is not a physical well, but is actually a concept that reflects the actual total working interests we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

(1)

As of December 31, 2001, we owned interests in six gross wells with multiple completions.

(2)

Other includes Colorado, Kansas, Nebraska, North Dakota and Wyoming.

        As of December 31, 2001, we were the operator of 621 gross (451 net) wells, which represented approximately 80% of our PV-10.

Our Drilling Activities

        We intend to continue concentrating 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.

        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:

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        During the three year period ended December 31, 2001, we participated in one gross (.4 net) exploratory well which was a dry hole. This well was drilled during 1999. The drilling activities during 2001 in the United States referenced in the above table were conducted in Texas, Mississippi, New Mexico and Kansas. The drilling activities during 2001 in Canada referenced in the above table were conducted in Alberta. On December 31, 2001, in the U.S., we owned a 100% working interest in each of three wells awaiting completion, a 60% working interest and a 50% working interest in two wells awaiting final facilities hook-up, and a 94% working interest in a well being evaluated for completion. On December 31, 2001, in Canada, we owned an average working interest of 92% in five wells awaiting final facilities hook-up. As of March 15, 2002, we owned an interest in one well (30% working interest) in Pecos County, Texas that was being drilled by another operator. In Alberta, Canada, we were drilling two wells. One well (72% working interest) is located in the Pine Creek Field and the second well (94% working interest) is located in the Caroline Field. The drilling and completion of these wells is expected to cost us approximately $2.5 million.

Summary of Our Development and Exploitation Projects

        We are currently pursuing an active development and exploitation strategy. For the year 2002 we have budgeted up to $21 million for development drilling, recompletions, production facilities and other exploitation related projects to implement this strategy. As of March 15, 2002, we were participating in a pressure maintenance project at the Righthand Creek Field (60% working interest) in Allen Parish, Louisiana, and in a non-operated waterflood project (90% working interest) in the Milroy Field, Carter County, Oklahoma. 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 23 producing wells, of which we operate 20 wells. The wells produce from the Strawn formation at depths from 10,000 to 10,500 feet. We drilled and completed a well during the fourth quarter of 2001. This well is currently waiting on a pipeline connection. We currently plan to drill an additional well during 2002.

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 eight producing wells in which we have an interest. Production is primarily from the Ellenburger formation at a depth of approximately 22,000 feet. During 2001, we attempted to drill the Leon #2 well to the Wolfcamp formation at approximately 15,700 feet. A blowout occurred while we were drilling at a depth of 15,878 feet. The well was successfully controlled and eventually plugged and abandoned. We believe that insurance will cover most of the cost of the blowout as well as the majority of the cost of the replacement well. We started drilling the replacement well, the Leon #3, in February 2002.

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 drilled a well during 2001 that was being evaluated at year-end. We plan to drill an infill well during 2002.

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 26 wells, 19 of which we operate. Production is from the Abo formation at depths from 3,700 to 4,500 feet. Five infill wells were drilled during 2001, of which four were successful and are waiting on pipeline connection. We plan to drill three additional infill wells during 2002.

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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 79% in 58 producing wells, 49 of which we operate. We plan to complete 20 exploitation projects in the Garrington Field during 2002, which include recompletions, lift optimizations and facility expansions.

Pine Creek Field

        The Pine Creek Field is an oil and natural gas field located in Alberta, Canada. We hold working interests ranging from 66.7% to 100% in 30 producing wells, of which we operate. Pine Creek produces from Cretaceous formations at depths from 6,000 to 8,600 feet. We have identified five development locations to be drilled in this field during 2002.

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 87% in 33 producing wells, 32 of which we operate. We drilled four wells in the Caroline Field during 2001 and plan to drill two additional wells in 2002.

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 83% working interest in 33 wells and operate 29 of those wells. We plan to drill two wells and complete five exploitation projects in the Westward Ho Field during 2002.

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 six of seven wells in this field and our working interests range from 75% to 100%. We have identified four development locations to be drilled in 2002.

Our Interest in 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 interest in developed and undeveloped acreage at December 31, 2001:

(1)

Other includes Colorado, Kansas, Montana, North Dakota, Oklahoma and Wyoming.

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        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 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. In 1999, we received an unsolicited proposal to sell our interest in a property for approximately $20.1 million resulting in a net gain of approximately $5.6 million.

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 volume of the natural gas or NGLs we produce. At the Black Lake Field we operate a natural gas processing plant which 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 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 the natural gas we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the closing prices on the last three traded days for natural gas to be delivered one month in the future. We also sell a portion of our natural gas based on posted indexes in the areas of our producing properties. Our sales contracts are of a type common within the industry, and we 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 or to companies that will construct pipelines to our properties.

        We sell the NGLs we produce 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 negotiate a separate contract for each property. Typically, the prices we receive 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;

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•

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 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.

Canada

        Addison sells the majority of its oil to Plains Marketing Canada, L.P. at market sensitive prices less applicable tariffs, trucking and quality adjustments.

        Addison's natural gas is marketed primarily through a negotiated contract with Engage Energy America, LLC (Engage) at market sensitive prices less actual transportation and fuel costs. We have a firm delivery commitment to Engage for 5,200 Mmbtus per day through November 30, 2002. The remaining volumes are being sold to Engage under a natural gas sales contract that can be terminated with 30 days notice.

        Addison's NGLs are sold primarily to three different buyers under contracts which provide for index pricing less transportation and fraction fees.

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Revenues

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

(1)

Information is for United States only.

Our Principal Customers

        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 service area. Under current economic circumstances, however, if we were to lose a purchaser, we believe we could identify a substitute purchaser.

        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. During 1999, sales of oil and natural gas to two purchasers, Plains All American, Inc. and EOTT Energy Operating Limited Partnership, accounted for 36% and 27%, respectively, of our total oil and natural gas revenues.

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 those available to us. 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 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.

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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 Acts, 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.

        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. In this connection, 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 facilities that meet its traditional test of gathering status, it has the authority to exercise jurisdiction under the OCSLA over gathering facilities, if necessary, to permit non-discriminatory access 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 of 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 permit non-discriminatory access 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

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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 amends its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amends 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, it is not anticipated 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 countries, there are presently no such designations in effect. We own interest in federal onshore oil and gas leases. It is possible that some of our shareholders may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act.

        Our pipelines used 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) relating to 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 designed to permit access to and allowing copying of records and to make certain reports 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. It 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. Nonetheless, 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 operation.

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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 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 the (1) costs of remediating a release, (2) administrative and civil penalties or criminal fines, (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 obligations 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

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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. This development 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, including casing leaks of oil or other materials occur, we may incur penalties and costs for waste handling, remediation and third party actions for damages. Moreover, we are able to directly control the 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 cannot 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 were 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 premium costs. 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 premium costs 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.

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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 gas companies of similar size, the controls and regulations should be considered carefully by investors in the oil and gas industry. Outlined below are some of the principal aspects of legislation and regulations governing the oil and 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 and the issue of such a license requires governmental approval.

Pricing and Marketing—Natural Gas

        In Canada, producers of natural gas negotiate sales contracts directly with natural gas purchasers. 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 and the issue of such a license 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.

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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

        For crude oil, natural gas and related product production from Crown lands, the royalty regime is a significant factor in the profitability of such production operations. Royalties payable on 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 the type of product being produced, well productivity, geographical location and field discovery date.

        From time to time the provincial government of Alberta has established incentive programs for exploration and development. Such programs often provide for royalty reductions and royalty holidays, 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 27% 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 39%.

        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.

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        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 $210 per cubic meter. The ARTC rate is applied to a maximum of $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. On December 22, 1997, the Government of Alberta gave notice that they intended to review the ARTC program with the objective of setting out better target objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Government of Alberta announced that it would not be reducing the size of the program, but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying for the program.

        Crude 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 environmental 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 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 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.

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        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 use in the operation of our business. Substantially all of our properties are pledged as collateral under our U.S. and Canadian credit agreements.

Our Employees

        As of December 31, 2001, we employed 93 persons (68 in the United States and 25 in Canada) of which 13 were involved in field operations and 80 were engaged in office and 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, 54, 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, 59, 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., 41, 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, 48, 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, 47, became 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, 51, joined us in October 2001 and became the 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) and 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

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during the past 25 years. He most recently served as Vice President—Finance of Noble Denton & Associates, Inc., an offshore engineering and marine consulting company.

        W. Andy Bracken, CPA, 37, 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, 50, 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, 47, 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, 50, 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., 59, joined us as one of our Vice Presidents in February 2002. He has thirty-eight 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.

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." The present value of estimated future net revenues is an estimate of future net revenues from a property at December 31, 2001, at its acquisition

29

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, 2001, 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.

ITEM 2. PROPERTIES

General

        We lease approximately 13,400 square feet of office space in Dallas, Texas, 7,450 square feet in Denver, Colorado, and 5,000 square feet in Calgary, Alberta for our corporate offices. The leases expire December 31, 2005, September 30, 2004, and March 31, 2004, respectively, and require monthly rental payments of approximately $16,700, $11,700, and $7,800 respectively. In February 2002, we leased approximately 5,100 square feet of additional office space in Dallas for monthly rental payments of approximately $6,400. We also anticipate that we will need to relocate our Calgary, Alberta office during 2002 to meet increased needs resulting from recent acquisitions. We also have small offices in 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 2 of this annual report.

ITEM 3. LEGAL PROCEEDINGS

        We are a defendant in various lawsuits and other natural gas contract issues. We do not believe that any outcome of such lawsuits or other issues would have a material adverse effect on our financial position. During 2001, we were not a party to any material legal proceeding.

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

        During the last three months of the year ended December 31, 2001, 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, 2000 through December 31, 2001, based upon quotations periodically published on the Nasdaq NMS. All price quotations represent prices between dealers, without accounting for retail mark-ups, mark-downs or commissions, and may not represent actual transactions.

        The last bid price for our common stock was $15.49 on March 15, 2002.

Our Shareholders

        According to our transfer agent, Continental Stock Transfer & Trust Company, there were approximately 741 holders of record of our common stock on February 28, 2002 (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 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.

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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 which materially impact the comparability of this data between periods.

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(1)

Per share data has been restated to reflect the one-for-two reverse stock split effective March 31, 1998. The adoption of Financial Accounting Standards Board No. 128, "Earnings per Share," did not have a material impact on earnings per share amounts. We have neither declared nor paid any dividends on common stock during any of the periods presented.

(2)

The ratio of combined fixed charges and preference dividends to earnings is calculated by adding fixed charges, defined as the sum of interest expense and amortized deferred financing costs, to preference security dividends, defined as the amount of pre-tax earnings that are required to pay the dividends on outstanding preference securities, divided by earnings, defined as the sum of pre-tax income from continuing operations before minority interests, or income or loss from equity investees and fixed charges, less the minority interest in pre-tax income of subsidiaries that have not incurred fixed charges.

(3)

Capital expenditures are capitalized workovers, exploration, exploitation and plugging costs incurred and exclude property acquisition costs.

(4)

EBITDA is defined as net income, plus interest expense, income taxes, and depreciation, depletion and amortization expenses, and, for 2001, plus $60.2 million for impairments of oil and natural gas properties and the uncollectible value of Enron hedges offset by $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.

(5)

Cash flow represents cash flows from operating activities before changes in working capital.

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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 and market prices and future hedging activities, and other statements, including, in particular statements about our plans and forecasts under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business," 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. Among these forward-looking statements are statements regarding our anticipated performance in the year 2002, specifically statements relating to our net sales, gross profit, production, general and administrative expenses, production costs, and capital expenditures. We have based these forward-looking statements on our current assumptions, expectations 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 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. Current oil and natural gas prices have declined significantly during 2001 and at December 31, 2001 from the historically high levels at December 31, 2000. The valuations and estimated quantities of our oil and natural gas reserves at December 31, 2001, in this annual report are based upon these lower prices. Oil and natural gas prices at their current level, or a further 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.

2001 Performance

        The year ended December 31, 2001, was a very active year with respect to the implementation of our business strategy. During the year, we completed 13 acquisitions for net consideration of

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approximately $114.0 million and spent approximately $23.8 million on development and exploitation activities. Our acquisitions added approximately 128.2 Bcfe of proved reserves, resulting in an acquisition cost of $0.89 per Mcfe. Our largest acquisition during the year was the purchase of Addison Energy Inc., which also marked our entry into Canada. Our reserves grew by 72% from 171.5 Bcfe at December 31, 2000, to 294.5 Bcfe at December 31, 2001.

        In June 2001, we raised $105.1 million ($101.2 million net after fees and commissions) through a rights offering to our existing shareholders. We applied approximately $97.6 million of the proceeds to repay our bank loans. At year end, we had approximately $45.0 million of long-term debt outstanding, resulting in a debt to book capitalization ratio of 27%. At December 31, 2000, we had approximately $42.5 million of long-term debt outstanding, with a debt to book capitalization ratio of 46%. We had a total of approximately $57.7 million available for borrowing under our U.S. and Canadian credit agreements at December 31, 2001.

        Our production grew by 112% from 7.1 Bcfe in 2000 to 15.1 Bcfe in 2001, as a result of our acquisition, development and exploitation activities. During 2001, we experienced a general decline in the prices we received for oil, natural gas and NGLs. Our realized oil price, before hedge settlements, declined from an average of $26.95 per Bbl during the first quarter to an average of $18.07 per Bbl during the fourth quarter. Our realized natural gas price, before hedge settlements, declined from an average of $6.60 per Mcf during the first quarter to an average of $2.17 per Mcf during the fourth quarter. Our realized NGLs price declined from an average of $25.98 per Bbl during the first quarter to an average of $12.57 per Bbl during the fourth quarter. Production costs, including production and ad valorem taxes, increased on a per Mcfe basis from $1.32 in 2000 to $1.59 in 2001 mainly as a result of workovers and equipment repairs during the first six months of 2001 relating to production enhancement projects on the Central Resources properties we acquired on September 22, 2000, and the inclusion of production costs for the full year from these properties which have higher historic average per unit costs. During 2001, we experienced a general decline in our per unit production costs. Our production costs, including production and ad valorem taxes, declined from an average of $1.86 per Mcfe during the first quarter to an average of $1.42 per Mcfe during the fourth quarter.

        We also recorded non-cash income and expense items related to our hedging activities as well as non-cash write-offs of our oil and natural gas properties as further described in "Our Results of Operations—Comparison of Years Ended December 31, 2000 and 2001" below.

2002 Outlook

Commodity Prices

        During 2001, commodity prices declined from historically high levels at the beginning of the year to more moderate levels by year end. Our outlook for 2002 commodity prices is uncertain. Significant factors that will impact 2002 commodity prices include the extent to which members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations are able to manage oil supply through export quotas, the overall North American natural gas supply and demand fundamentals and the extent of any worldwide economic recovery, especially any economic recovery in the United States. Political events and turmoil in the Middle East as well as the U.S. war on terrorism may exacerbate commodity price volatility. We will continue to moderate our debt levels, follow cost management measures and strategically hedge oil and natural price risk to mitigate the impact of price volatility on our oil, natural gas and NGLs. We will continue to review our hedge position each time we make a material acquisition.

        As of December 31, 2001, we had a hedge in place covering 761,000 Bbls of our 2002 oil production under a swap contract with a weighted average fixed price to be received of $20.77 per Bbl. We have hedged approximately 57%-61% of our forecasted oil production for 2002. We also had hedges in place covering 7,365,000 Mmbtus of 2002 natural gas production under swap contracts with a weighted average fixed price to be received of $2.82 per Mmbtu. In March 2002, we increased our 2002 commodity hedge positions by entering into a hedge covering 150,000 Mmbtus of natural gas per

35

month with a fixed price to be received of $3.165 per Mmbtu, beginning in May 2002 through the end of 2002. With this increase in our natural gas hedge positions, we have hedged approximately 58%-63% of our forecasted natural gas production for 2002. We also entered into a hedge covering 455,000 Mmbtus of natural gas per month for all of 2003 with a fixed price to be received of $3.50 per Mmbtu. Additionally, at December 31, 2001, we had approximately $9.0 million remaining in accumulated other comprehensive income related to our terminated hedge contracts with Enron North America. Of this amount, approximately $7.0 million will be reclassified into earnings during 2002 and the balance of approximately $2.0 million will be reclassified into earnings in 2003. For more information regarding our hedging contracts as well as the accounting treatment of the terminated Enron Hedges, please review "Item 7A—Quantitative and Qualitative Disclosure About Market Risk".

First Quarter 2002

        Based on our current estimates, we expect that our first quarter production will be between 4.8 Bcfe and 5.1 Bcfe. We expect first quarter production costs, including production and ad valorem taxes, to average between $1.30 to $1.40 per Mcfe. Depreciation, depletion and amortization expense is expected to be between $0.80 to $0.85 per Mcfe and general and administrative expense is expected to be between $1.7 million and $1.8 million during the first quarter of 2002. Our interest expense is expected to be between $400,000 and $500,000.

Production Growth

        We currently forecast that our annual 2002 production will be between 23.3 Bcfe and 25.1 Bcfe. This estimate includes approximately 2.3 Bcfe to 2.8 Bcfe of production related to our pending Canadian acquisition which is expected to close in April 2002. For purposes of this forecast we have assumed that the pending Canadian acquisition closes in April 2002. If this transaction is delayed or terminated, this forecast could differ materially from our actual results.

Acquisitions and Capital Expenditures

        For 2002, we have budgeted up to $21 million for development efforts plus related facilities. Approximately 50% of our capital budget is allocated to the U.S. and approximately 50% is allocated to Canada. Our capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should our price expectations for our future production or rig availability change sufficiently, we may accelerate some projects or defer some projects and, consequently, may increase or decrease total 2002 and future capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from our estimates.

        We plan to fund our pending Canadian acquisition from borrowings under our current credit agreements. Although we have completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, we do not budget, nor can we reasonably predict, the timing or size of any acquisitions we do not describe in this report.

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 upon which our financial status depends. 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, impairment assessments, functional currency assessment, deferred tax asset valuations and our choice of accounting method.

        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, the application of which

36

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;

•

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.

        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 may result from lower market prices, which may make it uneconomic 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 gas properties for impairment.

Impairment of unproved oil and gas properties

        We periodically assess individually significant unproved oil and natural gas properties for impairment, on a project-by-project basis. Our assessment of the results of exploitation activities, commodity price outlooks, planned future sales or the expiration of all or a portion of the leases for potential projects impact the amount and timing of impairment provisions.

Assessments of functional currencies

        We determine the functional currencies of our subsidiaries based on an assessment of 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. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

Deferred tax asset valuations

        We periodically assess the probability of recovery of recorded deferred tax assets based on our assessment of future earnings outlooks by tax jurisdiction. These estimates are inherently imprecise since many assumptions are utilized in the assessments that may prove to be incorrect in the future.

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 to make judgments about estimates of future uncertainties.

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        We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. Once incurred, costs 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 is 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 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) exceeds the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects, and the lower of cost and 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 gas properties if there is a decline in oil or natural gas prices, or downward adjustments are made to our proved reserves.

Recently Issued Accounting Standards

        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 as 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 an accounting change for all cash flow hedges. Oil and natural gas revenues include net gains from the settlement of cash flow hedges of $6.9 million for the year ended December 31, 2001, and net losses of $1.1 million for the year ended December 31, 2000. During the year ended December 31, 2001, we recognized $3.5 million in other income for hedging ineffectiveness.

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        In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations," which addresses financial accounting and reporting for business combinations. SFAS No. 141 is effective for all business combinations completed after June 30, 2001. The adoption of SFAS No. 141 has not had a material impact on our financial position or results of operation.

        In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which addresses, among other things, the financial accounting and reporting for goodwill subsequent to an acquisition. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill shall be reviewed at least annually for impairment. SFAS No. 142 is required to be adopted on January 1, 2002. We do not believe the adoption of these provisions will impact our financial statements.

        SFAS No. 143, "Accounting for Asset Retirement Obligations," which was also issued by the FASB in June 2001, requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. We are currently evaluating the impact SFAS No. 143 will have on our financial position and results of operations.

        In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes other accounting pronouncements to eliminate certain exceptions and alternatives. We do not believe the adoption of these provisions will impact our financial statements.

Our Results of Operations

        The following tables present production and average unit prices and costs for the periods and geographics segments indicated:

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