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EXCO RESOURCES, INC. INDEX

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

FORM 10-Q

Commission File Number 0-9204

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

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

        The number of shares of common stock, par value $0.02 per share, outstanding at October 31, 2002 was 6,993,420 shares (excludes 248,434 treasury shares)

EXCO RESOURCES, INC.

INDEX

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands, except per share amounts)

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited, in thousands)

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited, in thousands)

See accompanying notes.

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EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2002
(Unaudited)

1.    Basis of Presentation

        In management's opinion, the accompanying consolidated financial statements contain all adjustments (consisting solely of normal recurring accruals) necessary to present fairly the financial position of EXCO Resources, Inc. as of December 31, 2001 and September 30, 2002, and the results of operations and cash flows for the three and nine month periods ended September 30, 2001 and 2002.

        We have prepared the accompanying unaudited financial statements pursuant to the rules and regulations of the Securities and Exchange Commission. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. You should read these financial statements in conjunction with our financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2001. The accompanying condensed consolidated financial statements include the financial statements of EXCO Resources, Inc., and its subsidiaries. The financial statements of Pecos-Gomez, L.P., which ceased operations during 2001 with all remaining assets distributed to the partners, have been consolidated proportionally based on EXCO's aggregate ownership interest in the partnership.

        The results of operations for the three and nine month periods ended September 30, 2002, are not necessarily indicative of the results we expect for the full year.

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

2.    Stock Transactions

        On June 29, 2001, we closed our rights offering to existing shareholders that resulted in the sale of 5,004,869 shares of 5% convertible preferred stock at $21.00 per share. We raised a total of approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions), through the exercise of 4,466,869 rights and the sale of 538,000 shares of preferred stock by dealer managers. We applied approximately $97.6 million of the offering proceeds to pay off acquisition financing, and have used the remaining proceeds for general corporate purposes. Each share of 5% convertible preferred stock is convertible into one share of our common stock, at the option of the holder, on or before June 30, 2003. Any share of 5% convertible preferred stock still outstanding on June 30, 2003, will be automatically converted into our common stock.

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

        During the three month period ended September 30, 2002, we acquired 88,000 shares of our common stock through several open market transactions. The total amount paid for the shares was approximately $1.3 million, or an average of $14.81 per share. For the nine month period ended September 30, 2002, we have acquired 188,500 shares of our common stock through open market

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transactions. The total amount paid for the shares was approximately $2.8 million, or an average of $14.87 per share. The shares may be reissued in the future through the exercise of stock options, under the board of directors compensation plan or for other corporate purposes. We made the last purchase of our common shares on July 30, 2002. We have suspended the purchase of shares of our common stock pending the outcome of our chairman's announced proposal to acquire all of the outstanding shares of our common and preferred stock that he does not already own (See Note 10.—Acquisition Proposal).

3.    Earnings Per Share

        Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share", requires presentation of two calculations of earnings per common share. Basic earnings per common share equals net income less preferred stock dividends divided by weighted average common shares outstanding during the period. Diluted earnings per common share equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents. Common stock equivalents are shares assumed to be issued if (1) outstanding stock options or warrants were in-the-money and exercised, and (2) our outstanding convertible preferred stock was converted to common stock.

        Since we reported a loss on common stock for the three and nine month periods ended September 30, 2001 and 2002, our common stock equivalents are considered to be anti-dilutive and are not considered in the diluted earnings per share calculation. Employee and director stock options and our convertible preferred stock would have increased the diluted weighted average number of shares outstanding by 447,000 shares and 5,004,869 shares, respectively, for the three month period ended September 30, 2002 and 458,000 shares and 5,004,869 shares, respectively, for the nine month period ended September 30, 2002.

4.    Oil and Natural Gas Properties

        We have recorded oil and natural gas properties at cost using the full cost method of accounting. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool.

        Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not proved reserves can be assigned to such properties. At December 31, 2001 and September 30, 2002, the $6.6 million and $5.2 million, respectively, in unproved oil and natural gas properties resulted from the allocation of a portion of the purchase price of Canadian properties to undeveloped acreage and to possible and probable reserves. We assess our unproved oil and natural gas properties on a quarterly basis. During the three and nine months ended September 30, 2002, we reclassified $178,000 and $1.5 million, respectively, from unproved oil and natural gas properties to proved oil and natural gas properties.

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

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

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

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

        As a result of low natural gas prices for Canadian production on June 30, 2002, we recorded a non-cash ceiling test write-down of $17.5 million pre-tax ($9.7 million after-tax) to the Canadian full cost pool during the quarter ended June 30, 2002. Natural gas prices were higher at September 30, 2002 so no additional write-down was required. During the three month and nine month periods ended 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).

5.    Geographic Operating Segment Information

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

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operating segment income tax expenses have been determined based on expected effective tax rates for the various tax jurisdictions where we have oil and natural gas producing activities.

6.    Credit Agreements

        On December 18, 2001, as part of the financing of the acquisition of the PrimeWest properties, see "Note 8. Acquisitions—PrimeWest Properties Acquisition", we entered into restated U.S. and Canadian

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

        U.S. Credit Agreement.    Our restated U.S. credit agreement provides for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $65.0 million. At September 30, 2002, we had approximately $12.3 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $52.4 million available for borrowing under our U.S. credit agreement. The borrowing base is to be redetermined as of November 1, 2002, and each May 1 and November 1 thereafter. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be either (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin.

        Canadian Credit Agreement.    Our restated Canadian credit agreement provides for borrowings of up to U.S. $157.5 million under a revolving credit facility with a borrowing base of U.S. $75.0 million. At September 30, 2002, we had approximately U.S. $70.1 million of outstanding indebtedness and approximately U.S. $4.9 million available for borrowing under our Canadian credit agreement. The borrowing base is to be redetermined as of November 1, 2002, and each May 1 and November 1 thereafter. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be either (i) the Canadian prime rate plus an applicable margin or (ii) the Banker's Acceptance rate plus an applicable margin.

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

•

maintain a ratio of our consolidated current assets to consolidated current liabilities of at least 1.0 to 1.0 at the end of any fiscal quarter;



•

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



•

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



•

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

        Additionally, the credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and prohibit the payment of dividends on our common stock. The U.S. credit agreement further required that we hedge at least 75% of our anticipated production from our U.S. proved developed producing reserves, within ten days of the time we entered into the agreement, for a period of up to 24 months. As of September 30, 2002, we were in compliance with the covenants contained in the U.S. and Canadian credit agreements.

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        Dividend Restrictions.    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. If there is a default under our credit agreements, we will not be able to pay dividends on the shares of our 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.

7.    Commodity Derivative Instruments and Hedging Activities

        In connection with the incurrence of debt related to our acquisition activities and to protect against commodity price fluctuations, management has adopted a policy of hedging oil and natural gas prices through the use of commodity futures, options and swap agreements. Effective January 1, 2001, we adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activity," which established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings. Hedge effectiveness is measured quarterly based on the change in 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 of our hedges. Oil and natural gas revenues for the three and nine months ended September 30, 2001 were increased $3.8 million and $3.1 million, respectively, from the settlement of cash flow hedges while oil and natural gas revenues for the three and nine month periods ended September 30, 2002 were decreased $2.4 million and $3.9 million, respectively, from the settlement of cash flow hedges. During the nine months ended September 30, 2001, we recognized an increase in the net derivative asset and an associated increase in accumulated other comprehensive income totaling approximately $15.9 million. For the nine months ended September 30, 2002, we recognized an increase in the net derivative liability and an associated decrease in other comprehensive income totaling approximately $9.4 million. During the nine month periods ended September 30, 2001 and 2002, we recognized $1.9 million and $4.9 million, respectively, in other income for income from derivative ineffectiveness and terminated hedges.

        The following table sets forth our oil and natural gas hedging activities as of September 30, 2002. Our contracts are swap arrangements for the sale of oil and natural gas based on NYMEX pricing. The market values at September 30, 2002 are estimated from quotes from the counterparties and represent the amounts that we would expect to pay to terminate the agreements on September 30, 2002. The

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stated volumes and strike prices are for the remaining portions of the individual contracts at September 30, 2002.

(1)

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

(2)

Bbls—Barrels.

(3)

Mmbtus—Million British thermal units.

(4)

On September 30, 2002, the average forward NYMEX oil prices for the remainder of 2002 and for calendar 2003 were $30.00 per Bbl and $25.93 per Bbl, respectively, and the average forward NYMEX natural gas prices for the remainder of 2002 and for calendar 2003 were $4.03 per Mmbtu and $4.06 per Mmbtu, respectively.

        At September 30, 2002, we had approximately $3.7 million in other comprehensive income related to hedges that, as a result of the bankruptcy of Enron North America Corp., were terminated during 2001. This amount will be reclassified into other income as shown in the following table (in thousands):

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8.    Acquisitions

STB Energy Properties Acquisition

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

Addison Energy Inc. Acquisition

        On April 26, 2001, we acquired all of the outstanding common stock of Addison Energy Inc., (Addison) which is headquartered in Calgary, Alberta, Canada. At the date of acquisition, Addison owned interests in 95 gross (85.0 net) wells located in Alberta and operated 91 of these wells. The properties included approximately 27,672 gross and 23,994 net developed acres and approximately 38,947 gross and 28,795 net undeveloped acres. As of January 1, 2001, estimated total proved reserves net to our interest acquired in this acquisition included 2.1 million Bbls of oil and natural gas liquids (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, which were in turn paid off with the proceeds from the issue of our convertible preferred stock.

Pecos-Gomez Properties Acquisition

        On July 3, 2001, Pecos-Gomez, L.P., of which we were the general partner (the Partnership) conveyed all of its oil and natural gas property interests in Pecos County, Texas, to its partners and began the process to dissolve the Partnership. Also on July 3, 2001, we acquired additional interests in the properties from two of the limited partners for $8.8 million (approximately $7.5 million after contractual adjustments). In addition, we received an assignment of the existing Partnership hedge contract. Borrowings under the Partnership credit facility of $3.9 million were also repaid at the time of the acquisition and the credit facility was canceled.

PrimeWest Properties Acquisition

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

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Pro Forma Results of Operations

        The following reflects the pro forma results of operations as though the acquisitions during 2001 of the STB Energy Properties, Addison Energy Inc. and the PrimeWest Properties, the related borrowings, and our 5% convertible preferred stock offering had been consummated on January 1, 2001.

Medicine River Properties Acquisition

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

9.    Recently Issued Accounting Standards

        SFAS No. 143, "Accounting for Asset Retirement Obligations," which was issued by the Financial Accounting Standards Board (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. Due to the significant number of operating facilities that we maintain, and the extensive number of documents that must be reviewed and estimates that must be made to assess the effects of SFAS No. 143, we have not yet determined the expected impact on our financial position of adoption of SFAS No. 143.

10.  Acquisition Proposal

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

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

        Our board of directors has established a special committee comprised of J. Michael Muckleroy and Stephen F. Smith to consider the proposal, to evaluate, negotiate and make a recommendation to the full board on the proposal. The special committee has retained Bracewell & Patterson, L.L.P. as its

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

        On August 7, 2002, litigation was filed in connection with Mr. Miller's proposed offer. The litigation was filed in the 160^th State District Court in Dallas County, Texas and is captioned Weiser v. EXCO Resources, Inc. et al., Cause No. 02-7065. The complaint was purportedly filed on behalf of our public shareholders and alleges that our current directors breached fiduciary duties owed to our shareholders in connection with Mr. Miller's offer. We are named as a defendant in the litigation.

        The litigation seeks declaratory and injunctive relief to enjoin our ability to engage in such a transaction with Mr. Miller and the recovery of any compensatory damages that would allegedly be sustained as a result of the transaction. We believe that the allegations contained in the complaint are without merit, and plan to vigorously contest and defend against the litigation.

        On August 12, 2002, litigation was filed in the 162^nd State District Court in Dallas County, Texas and is captioned Birnbaum v. EXCO Resources, Inc., et al, Cause No. 02-07396-I. The complaint was purportedly filed on behalf of our public shareholders and alleges that our current directors breached fiduciary duties owed to our shareholders in connection with Mr. Miller's offer. We are named as a defendant in the litigation.

        The litigation seeks declaratory and injunctive relief to enjoin our ability to engage in such a transaction with Mr. Miller and the recovery of any compensatory damages that would allegedly be sustained as a result of the transaction. We believe that the allegations contained in the complaint are without merit, and plan to vigorously contest and defend against the litigation.

        On October 23, 2002, T. W. Eubank executed a Joinder Agreement regarding Mr. Miller's proposal filed as an Exhibit to Mr. Miller's 13D on October 24, 2002. Mr. Miller and Mr. Eubank intend to contact certain shareholders, employees and directors of EXCO to determine if they are interested in participating in the Miller proposal. If Mr. Miller and Mr. Eubank believe that holders of 20% or more of EXCO's currently outstanding voting stock would be interested in participating in the transaction, then they will take steps to form a buyout group (Buyout Group) composed of themselves and such shareholders. If a Buyout Group is formed, the Buyout Group may be deemed to own 20% or more of our currently outstanding voting stock under Article 13 of the Texas Business Corporation Act (Article 13). Article 13 prevents a Texas corporation from engaging in a business combination with a person, or any affiliate or associate of a person, who is deemed under Article 13 to beneficially own 20% or more of such corporation's outstanding voting stock unless: (i) such business combination is approved by the corporation's board of directors prior to such person acquiring beneficial ownership of 20% or more of the corporation's outstanding voting stock; (ii) the acquisition of 20% or more of the corporation's outstanding voting stock is approved by the corporation's board of directors prior to such acquisition; or (iii) the business combination is approved by the affirmative vote of at least two-thirds of the corporation's outstanding voting shares not owned by such person or such person's affiliates or associates. Pursuant to a Share Acquisition Agreement dated October 14, 2002, EXCO has approved the acquisition of 20% or more of EXCO's outstanding voting stock by a Buyout Group for the Miller proposal. Mr. Miller and Mr. Eubank intend to ask each officer, director, or employee of EXCO who they approach about participating in the transaction to join the Share Acquisition Agreement before such persons are invited to participate and before such persons determine if they wish to participate in the Miller proposal.

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        In the event the special committee approves a transaction other than the Miller proposal (an Alternate Transaction) on terms that Mr. Miller and Mr. Eubank believe are superior to the Miller proposal, then Mr. Miller and Mr. Eubank currently intend to support such a transaction and sell their EXCO stock in such Alternate Transaction.

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

11.  Subsequent Events

Loss of well control—Miami Corp. #35 well

        On October 1, 2002, we were conducting workover operations to restore production in our Miami Corp. #35 well in the South Pecan Lake Field, Cameron Parish, Louisiana. A loss of well control occurred resulting in the release of approximately 20.0 Mmcf per day of natural gas and 2,800 barrels per day of formation water. No injuries or fires resulted from the loss of control. We contracted with well control specialists to assist with well control operations.

        Temporary production facilities have been installed on the well and all the natural gas from the well is now being sold. The estimated daily sales volume on November 7, 2002 was approximately 6.0 Mmcf (4.5 Mmcf net to our interest). Natural gas sales have been declining, in part, due to our efforts to restrict the production rates from this well. Produced water, currently estimated at approximately 2,350 barrels per day, is being routed to our disposal wells. We hold a 90.0% working interest and a 74.9% net revenue interest in the well. We cannot predict how long these production volumes will continue. Prior to commencement of the workover, the well had been shut-in for several years due to downhole wellbore problems.

        The condition of the downhole tubulars will not allow the well to be shut-in or safely produced for a long period of time. We are monitoring the flowing conditions of the well and we are reviewing the feasibility of a pump-in procedure to control the well. Our efforts to restrict the production rates from this well should improve our chances of being able to successfully control the well with the pump-in procedure. We are also planning a relief well drilling operation that may be required if the pump-in procedure is not feasible or if it is unsuccessful.

        Through November 7, 2002, our estimated expenditures to control the well have been approximately $1.7 million. The preliminary additional cost to control the well is estimated to be between $500,000 to $1.0 million if a pump-in control procedure is successful and between $4.8 million to $7.1 million if the drilling of a relief well is required. We believe our control of well insurance will reimburse us for up to $4.5 million of the cost to control the well.

        Due to the volumes of water being produced and the possibility that the water volumes will increase over time in these types of reservoirs, the remaining natural gas reserves from this well are uncertain and difficult to predict. Our proved reserves as of January 1, 2002 for this well prior to the loss of well control were 585 Mmcf of natural gas. We are unable to estimate the remaining reserves from this well at this time and the actual reserves could be higher or lower than previously estimated.

DJ Basin property acquisition

        On November 1, 2002, we acquired oil and natural gas properties located in the DJ Basin in Colorado. As of October 1, 2002, estimated total proved reserves net to our interest included

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approximately 2.1 Mmbbls of oil and NGLs and 13.5 Bcf of natural gas from 111 gross (103 net) wells. Net daily production in September 2002 was approximately 630 Bbls of oil and NGLs and 3.7 Mmcf of natural gas. The purchase price was approximately $22.0 million cash ($21.1 million after contractual adjustments), funded with $19.7 million of bank debt from our U.S. credit agreement and $1.4 million from surplus cash.

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Item 2.    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 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 production, production costs, depreciation, depletion and amortization expense, general and administrative expenses, interest expense, 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, whether as a result of new information, future events, or otherwise. These statements are not guarantees of future performance and involve risks and uncertainties that could cause our actual results to differ, perhaps materially, from our expectations in this report, including, but not limited to:

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estimates of reserves;



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market factors;



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



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results of future drilling;



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marketing activity;



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future production and costs;



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outcome of litigation; and



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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. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this Quarterly Report, and the risk factors in our Form 10-K for the year ended December 31, 2001.

        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. The valuations and estimated quantities of our oil and natural gas reserves at December 31, 2001, included in our Form 10-K for the year ended December 31, 2001, are based upon prices in effect at December 31, 2001. Oil and natural gas prices have changed since that time. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely,

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and they are likely to continue to be volatile. As a result of low natural gas prices for Canadian production on June 30, 2002, we recorded a non-cash ceiling test write-down of $17.5 million pre-tax ($9.7 million after-tax) to the Canadian full cost pool during the quarter ended June 30, 2002. Natural gas prices were higher at September 30, 2002, so no additional write-down was required. For a further description of this charge, see "Note 4—Oil and Natural Gas Properties" of Notes to Condensed Consolidated Financial Statements contained in this Quarterly Report.

2002 and 2003 Outlook

        The following discussion reflects our estimates and expectations for 2002, assuming we do not complete any additional acquisitions or divestitures during the remainder of 2002. This outlook could be materially impacted by any acquisition or disposition we might complete.

Commodity Prices

        During 2001, commodity prices declined from historically high levels at the beginning of the year to more moderate levels by year end. Significant factors that will impact commodity prices during the remainder of 2002 include the current military activity and political unrest in the Middle East, the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to manage oil supply through export quotas, weather and climate conditions and the overall North American natural gas supply and demand fundamentals. We will continue to moderate our debt levels, follow cost management measures and strategically hedge oil and natural gas price risk to mitigate the impact of price volatility on our oil, natural gas and NGL sales. We will continue to review our hedge positions each time we make a material acquisition.

        As of September 30, 2002, we had hedges in place covering a total of 222,000 Bbls of our remaining 2002 oil production under swap contracts with a weighted average fixed price to be received of $21.49 per Bbl. We have now hedged approximately 62 - 65% of our forecasted oil production for the remainder of 2002. We have hedges in place covering 62,600 Bbls of oil per month for all of 2003 with a weighted average fixed price to be received of $24.03 per Bbl and covering 20,000 Bbls of oil per month for all of 2004 with a fixed price to be received of $23.96 per Bbl. We also have hedges in place covering 2,269,000 Mmbtus of our remaining 2002 natural gas production under swap contracts with a weighted average fixed price to be received of $2.89 per Mmbtu. These hedges cover approximately 53 - 55% of our forecasted natural gas production for the remainder of 2002. We have a hedge in place 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.

        At September 30, 2002, we had approximately $3.7 million remaining in accumulated other comprehensive income related to our terminated hedge contracts with Enron North America Corp. Of this amount, approximately $1.6 million will be reclassified into earnings during the remainder of 2002 and the balance of approximately $2.1 million will be reclassified into earnings in 2003. For more information regarding our hedging contracts, please review "Part I—Item 3—Quantitative and Qualitative Disclosure About Market Risk".

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Fourth Quarter 2002

        Production during the fourth quarter of 2002 will be impacted by two different events: natural gas sales from the Miami Corp. #35 well and the November 1, 2002 purchase of oil and natural gas properties in the DJ Basin. We expect the range of our fourth quarter production to be:

        We currently estimate that our annual 2002 production will be between 22.9 Bcfe and 23.3 Bcfe and between 33.0 Bcfe and 36.0 Bcfe during 2003.

        The Miami Corp. #35 well experienced a loss of control on October 1, 2002 while workover operations were being conducted. Temporary production facilities were installed and natural gas sales began on October 12, 2002. Our share of natural gas sales volumes during October 2002 are estimated to be 172 Mmcf and we expect that our share of production for November 2002 will be from 60 Mmcf to 100 Mmcf. Daily natural gas sales during October and November 2002 have been declining, in part, due to efforts to restrict the production rates from this well in order to attempt to successfully control the well with a pump-in procedure. Production from this well could vary materially from our estimate due to our lack of ability to control the flow from the well, the uncertainty of the amount of the remaining reserves, as well as the timing of when we can ultimately control the well.

        Estimated production from the DJ Basin properties has been included in the above table beginning on November 1, 2002, which was the date we closed this acquisition.

        Our estimate of certain costs and expenses has been based upon the production estimate shown above. We expect fourth quarter production costs, including production and ad valorem taxes, to be between $1.20 and $1.30 per Mcfe. Depreciation, depletion and amortization expense is expected to be between $.78 and $.83 per Mcfe and general and administrative expense is expected to be between $.35 and $.40 per Mcfe. Our interest expense is expected to be between $1.1 and $1.4 million during the fourth quarter of 2002.

Acquisitions and Capital Expenditures

        For 2002, we estimate that we will spend between $25.0 million and $31.0 million for development efforts plus related facilities, of which $11 million to $17 million is expected to be spent in the U.S. and $14 million in Canada. We have included $2.0 million to $8.0 million in the U.S. budget for the loss of control on the Miami Corp. #35 well. Any insurance recoveries for the Miami Corp. #35 well control event are not expected to be received until 2003. Our capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected cost 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 future capital expenditures including the remainder of 2002. 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.

        Our well control insurance policy has expired and our insurance carrier declined to renew our policy. As a result of the claims we have made on our well control insurance policy related to the Miami Corp. #35, the Leon #2 and the drilling of the Leon #3 replacement well, as well as general market conditions for insurance, we have been unable to obtain new well control insurance coverage on terms acceptable to us. We have delayed projects that we believe contain operational risks and we may

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

        We funded our April 2002 Medicine River properties and our November 2002 DJ Basin properties acquisitions primarily with borrowings under our credit agreements. As a key element of our growth strategy, we are continuously evaluating and bidding upon potential acquisitions of properties and companies. Although we have completed several major 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

        We did not have any changes in our critical accounting policies or in our significant accounting estimates during the nine month period ended September 30, 2002, other than our ceiling test write-down on our Canadian full cost pool during the second quarter. Please see our Annual Report on Form 10-K for the year ended December 31, 2001 for a detailed discussion of our critical accounting policies.

        Under full cost accounting rules, we must compare the amount in our full cost pools (separate pools exist for the United States and Canada) to a ceiling test limit. In calculating future net revenues for the ceiling test limit, current prices and costs are generally held constant indefinitely. As a result of lower prices for Canadian natural gas at the end of the second quarter of 2002, we had a pre-tax, non-cash write-down of our oil and natural gas properties of $17.5 million ($9.7 million after-tax) from our Canadian full cost pool. Natural gas prices were higher at the end of the third quarter of 2002 so no additional write-down was required. These assumptions are not indicative of our expectations for future prices. Due to the volatility in oil and natural gas prices, it is possible that we will incur additional non-cash ceiling test write-downs in the future.

        See "Item 3. Quantitative and Qualitative Disclosure about Market Risk-Equity Price Risk" for a discussion of impairment expense that we have recognized on our investments in marketable securities.

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Our Results of Operations

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