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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

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YES ý    NO o

        The number of shares of common stock, par value $0.02 per share, outstanding at April 30, 2003 was 7,031,993 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)

3

EXCO RESOURCES, INC.


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

See accompanying notes.

4

EXCO RESOURCES, INC.

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

See accompanying notes.

5

EXCO RESOURCES, INC.

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

See accompanying notes.

6

EXCO RESOURCES, INC.

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

See accompanying notes.

7

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2003
(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, 2002 and March 31, 2003, and the results of operations and cash flows for the three month periods ended March 31, 2002 and 2003.

        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, 2002.

        The results of operations for the three month period ended March 31, 2003 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.

Stock Options

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

        We have elected to continue to utilize the accounting method prescribed by APB 25, under which no compensation cost has been recognized, and adopt the disclosure requirements of SFAS 123. As a result, SFAS 123 has no effect on our financial condition or our results of operations at March 31, 2002 and 2003. Stock based compensation expense reflected in the table below for the three months ended March 31, 2002 and 2003, is a result of options issued under our 1998 Stock Option Plan that were issued subject to our shareholders' approval and, for the three months ended March 31, 2003, options that were issued to the management and key employees of Addison.

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

2. Asset Retirement Obligations

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

        In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted the new rules on asset retirement obligations on January 1, 2003, for both our U.S. and Canadian operations. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.4 million, recognition of an asset retirement obligation liability of approximately $10.4 million, an increase in deferred income tax liability of approximately $690,000, and a cumulative effect of adoption that increased net income and stockholder's equity by approximately $255,000.

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        The following pro forma data summarizes our net income and net income per share as if we had adopted the provisions of SFAS 143 on January 1, 2002, including an associated pro forma asset retirement obligation on that date of $7.1 million:

        The following is a reconciliation of our asset retirement obligations at March 31, 2003 (in thousands of dollars):

        We have no assets that are legally restricted for purposes of settling asset retirement obligations.

3. Earnings Per Share

        SFAS No. 128, "Earnings per Share", requires presentation of two calculations of earnings per common share. Basic earnings per common share equals net income less preferred stock dividends divided by weighted average common shares outstanding during the period. Diluted earnings per

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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 5% convertible preferred stock was converted to common stock.

        The assumed conversion of our 5% convertible preferred stock to common stock is considered to be anti-dilutive for the three month period ended March 31, 2002 and is therefore not included in the diluted earnings per share calculation. Our 5% convertible preferred stock would have increased the diluted weighted average number of shares outstanding by 5,004,869 shares for the three months ended March 31, 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, 2002 and March 31, 2003, the $4.9 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 months ended March 31, 2003, we reclassified $94,000 from unproved oil and natural gas properties to proved oil and natural gas properties; however, due to the increase in the exchange rate of the Canadian dollar to the U.S. dollar, the balance of unproved oil and natural gas properties, expressed in U.S. dollars, has increased since December 31, 2002.

        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.

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        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.

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. Geographic operating segment income tax expenses have

12

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

       We have a U.S. credit agreement and a Canadian credit agreement. The U.S. credit agreement is with Bank One, NA, as administrative agent, BNP Paribas, as syndication agent, The Bank of Nova Scotia, as documentation agent, Bank One Capital Markets, Inc. as lead arranger and bookrunner, and

13

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. The credit agreements were amended on April 24, 2003, to extend the maturity date to July 31, 2004.

        U.S. Credit Agreement.    Our restated U.S. credit agreement provides for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $82.0 million. At March 31, 2003, we had approximately $34.0 million of outstanding indebtedness, letter of credit commitments of $310,000 and approximately $47.7 million available for borrowing under our U.S. credit agreement. The borrowing base is to be redetermined as of November 1, 2003, and each May 1 and November 1 thereafter. Borrowings under the U.S. credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties. At our election, interest on borrowings may be either (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin.

        As a result of our May 1, 2003 semi-annual borrowing base redetermination and in consideration of the merger agreement that we have entered into with EXCO Holdings Inc. and ER Acquisition, Inc., we have received a commitment letter from our lead bank to amend our U.S. credit agreement. The commitment provides for an increase in our U.S. borrowing base to $100.0 million. The U.S. borrowing base will be reduced to $92.5 million 90 days after the effective time of the merger. The borrowing base will be further reduced by $7.5 million every 90 days thereafter until the next scheduled borrowing base redetermination after the effective time of the merger. The amendment will also provide for an extension of the U.S. credit agreement maturity date to the third anniversary of the effective time of the merger. The commitment is subject to certain closing conditions outlined in the commitment letter.

        Canadian Credit Agreement.    Our restated Canadian credit agreement provides for borrowings of up to U.S. $157.5 million under a revolving credit facility with a borrowing base of U.S. $83.0 million. At March 31, 2003, we had approximately U.S. $74.2 million of outstanding indebtedness and approximately U.S. $8.8 million available for borrowing under our Canadian credit agreement. The borrowing base is to be redetermined as of November 1, 2003, 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.

        As a result of our May 1, 2003 semi-annual borrowing base redetermination and in consideration of the merger agreement that we have entered into with EXCO Holdings Inc. and ER Acquisition, Inc., we have received a commitment letter from our lead bank to amend our Canadian credit agreement. The commitment provides for an increase in our Canadian borrowing base to U.S. $100.0 million. The Canadian borrowing base will be reduced to U.S. $92.5 million 90 days after the effective time of the merger. The borrowing base will be further reduced by U.S. $7.5 million every 90 days thereafter until the next scheduled borrowing base redetermination after the effective time of the

14

merger. The amendment will also provide for an extension of the Canadian credit agreement maturity date to the third anniversary of the effective time of the merger. The commitment is subject to certain closing conditions outlined in the commitment letter.

        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 (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;



•

maintain a minimum consolidated tangible net worth of not less than $48.0 million (adjusted upward by 50% of 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. As of March 31, 2003, we were in compliance with the covenants contained in our U.S. and Canadian credit agreements.

        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 5% convertible preferred stock. Even if our credit agreements permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

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

15

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. Oil and natural gas revenues for the three months ended March 31, 2002 were increased $645,000 from the settlement of cash flow hedges while oil and natural gas revenues for the three month period ended March 31, 2003 were decreased $7.7 million from the settlement of cash flow hedges. For the three months ended March 31, 2002 and 2003, we recognized an increase in the net derivative liability and an associated decrease in other comprehensive income totaling approximately $8.2 million and $4.8 million, respectively. During the three month period ended March 31, 2002 and 2003, we recognized $2.2 million and $975,000, respectively, in other income for income from terminated hedges. During the three month period ended March 31, 2002 and 2003, we also reduced revenues by $115,000 and $2.5 million for the ineffective portion of the change in the fair value of our hedges.

        The following table sets forth our oil and natural gas hedging activities as of March 31, 2003. Our contracts are swap arrangements for the sale of oil and natural gas based on NYMEX pricing. The market values at March 31, 2003 are estimated from quotes from the counterparties and represent the amounts that we would expect to receive or pay to terminate the agreements on March 31, 2003. The stated volumes and strike prices are for the remaining portions of the individual contracts at March 31, 2003.

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.

16

4

On March 31, 2003, the average forward NYMEX oil prices for the remainder of 2003 and for calendar 2004 were $27.54 per Bbl and $24.79 per Bbl, respectively, and the average forward NYMEX natural gas prices for the remainder of 2003 and for calendar 2004 were $5.13 per Mmbtu and $4.63 per Mmbtu, respectively.

5

Weighted average.

        At March 31, 2003, we had approximately a $1.1 million gain 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):

8. Acquisitions and Dispositions

Medicine River Properties Acquisition.

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

DJ Basin Properties Acquisition.

        On November 1, 2002, we acquired oil and natural gas properties located in the DJ Basin in Colorado. As of October 1, 2002, estimated total proved reserves net to our interest included approximately 2.1 million Bbls of oil and NGLs, and 13.5 Bcf of natural gas from 111 gross (103 net) wells. Net daily production in September 2002 was approximately 630 Bbls of oil and NGLs, and 3.7 Mmcf of natural gas. The purchase price was approximately $22.0 million 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.

Other Acquisitions and Dispositions.

        During the three months ended March 31, 2003, we completed two oil and natural gas property acquisitions, one in Canada and one in the United States. Estimated total proved reserves net to our interest from these acquisitions included approximately 196,000 Bbls of oil and NGLs, and 3.7 Bcf of natural gas from 14 gross (5.8 net) wells. Net daily production from these properties is approximately 38 Bbls of oil and NGLs, and 742 Mcf of natural gas. The total purchase price for the acquisitions was

17

approximately $5.5 million funded with borrowings under our Canadian credit agreement and from surplus cash. In addition, we have also completed ten smaller acquisitions during this period for consideration that totaled approximately $600,000.

        During the first three months of 2003, we have sold six oil and natural gas properties in the United States. As of January 1, 2003, estimated total proved reserves net to our interest from these properties included approximately 565,000 Bbls of oil and NGLs, and 192,000 Mcf of natural gas. The total sales proceeds we received were approximately $3.1 million. During the first quarter of 2002, we recorded revenue of approximately $248,000, oil and natural gas production costs of $150,000 and depletion expense of $70,000 on these properties. During the first quarter of 2003, we recorded revenues of approximately $130,000, oil and natural gas production costs of $40,000 and depletion expense of $20,000.

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

        Pro forma financial information has not been provided because these acquisitions and dispositions were less than 20% of our total assets when purchased or sold.

9. Merger Agreement

        On March 11, 2003, we entered into an Agreement and Plan of Merger providing for the merger of ER Acquisition, Inc., a Texas corporation, and a wholly-owned subsidiary of EXCO Holdings Inc., a Delaware corporation, into EXCO Resources, Inc. EXCO Holdings Inc. is a newly formed corporation formed by our chairman and chief executive officer, Douglas H. Miller, and his buying group for the purpose of entering into the merger agreement. The merger agreement provides that holders of our common stock, other than EXCO Holdings Inc. and its subsidiaries, will receive cash of $18.00 per share and holders of our 5% convertible preferred stock will receive cash of $18.2625 per share if the transaction closes on or before June 15, 2003 and $18.00 per share thereafter. The preferred stock price difference is attributable solely to the dividend record date for the preferred stock. A majority of the equity capital for the merger will be provided by Cerberus Capital Management, L.P., a long-term investment based fund manager. Following the completion of the merger, ER Acquisition, Inc. will cease to exist as a separate entity, and we will continue as the surviving corporation of the merger and as a wholly-owned subsidiary of EXCO Holdings Inc. Upon completion of the merger transaction, our common stock and 5% convertible preferred stock would be delisted from trading on the NASDAQ National Market or any other exchange and our common stock and 5% convertible preferred stock would become eligible for termination of registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934. The transaction is subject to various conditions to closing. We currently expect to submit the merger agreement to our shareholders for their approval during the second or the third quarter of 2003. There can be no assurance this transaction will be approved or completed.

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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 2003, 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:

•

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;



•

outcome of litigation; 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, 2002.

        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, 2002, included in our Form 10-K for the year ended December 31, 2002, are based upon prices in effect at December 31, 2002. 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.

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Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Critical Accounting Policies

        We did not have any changes in our critical accounting policies or in our significant accounting estimates during the three month period ended March 31, 2003, other than our adoption of FAS 143, "Accounting for Asset Retirement Obligations." See "Note 2.—Asset Retirement Obligations" of the notes to our condensed consolidated financial statements above for a detailed discussion of this accounting policy and the impact on our financial statement from the adoption of this policy. Please see our Annual Report on Form 10-K for the year ended December 31, 2002 for a detailed discussion of our critical accounting policies.

        See "Part I—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:

(1)

All hedging results are shown in the United States because all hedging contracts have been entered into and all settlements have been received or made by EXCO.

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