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

FORM 10-K

Commission File Number 0-9204

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

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

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment of this Form 10-K. ý

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

        As of March 15, 2005, the Registrant had outstanding 1,000 shares of common stock, par value $.01 per share, which is its only class of stock. The Registrant's common stock is not traded on any exchange and, therefore, its aggregate market value and the value of shares held by non-affiliates cannot be determined as of the last business day of the Registrant's most recently completed fiscal quarter.

DOCUMENTS INCORPORATED BY REFERENCE
None

TABLE OF CONTENTS

EXCO RESOURCES, INC.

PART I

ITEM 1. BUSINESS

General

        EXCO Resources, Inc. (EXCO or the Company) is an independent energy company engaged in the acquisition, exploration, development and exploitation of oil and natural gas properties. Our primary areas of operations are onshore in Texas, Colorado, Ohio, Pennsylvania, West Virginia and, until February 10, 2005, Alberta, Canada. As of December 31, 2004, our Proved Reserves were approximately 686.0 Bcfe, of which 77% were natural gas and 90% were Proved Developed Reserves. As of December 31, 2004, the related PV-10 of our Proved Reserves was $1.2 billion, and the Standardized Measure of our Proved Reserves was $833.2 million. For the twelve months ended December 31, 2004, we produced 40.5 Bcfe of oil and natural gas, which translates to a Reserve Life of approximately 16.9 years. For the twelve month period ended December 31, 2004, we generated $178.0 million of revenues and other income.

        On July 29, 2003, we completed a "going private" transaction that resulted in all of our outstanding common stock being acquired by EXCO Holdings Inc., or EXCO Holdings, a holding company owned by certain members of our management and several institutional and other investors. This transaction resulted in a change in the valuation of our assets.

        On January 27, 2004, we acquired all of the outstanding common stock, options and warrants of North Coast Energy, Inc. (North Coast) for a purchase price of $167.8 million, and we assumed $57.0 million of North Coast's outstanding indebtedness. As a result, North Coast became one of our wholly-owned subsidiaries and continues to be an energy company focused on the acquisition, exploration, exploitation, development and production of natural gas reserves in the Appalachian Basin. The North Coast acquisition established a new core operating area for us in the Appalachian Basin, which positions us to benefit from the attractive qualities of the basin and to capitalize on consolidation opportunities in the area.

        On February 10, 2005, 1143928 Alberta Ltd., a wholly-owned subsidiary of NAL Oil & Gas Trust, an Alberta trust, purchased all of the issued and outstanding shares of common stock of Addison Energy Inc. (Addison), our wholly-owned subsidiary through which all of our Canadian operations were conducted, and two promissory notes that Addison owed to our wholly-owned subsidiary, Taurus Acquisition, Inc. (Taurus). The aggregate purchase price was Cdn. $553.3 million (U.S. $442.7 million) less the payment of the outstanding balance under Addison's credit facility of Cdn. $90.1 million (U.S. $72.1 million) and other adjustments as specified in the purchase agreement. See "—Developments Since December 31, 2004" and "Note 17. Subsequent Events" to our Consolidated Financial Statements for additional information.

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        The following table sets forth a summary of our Proved Reserves, the PV-10 of our Proved Reserves and Standardized Measure of our Proved Reserves as of December 31, 2004:

(1)

The Proved Reserves and the PV-10 of the Proved Reserves for EXCO and North Coast as of December 31, 2004 as used in this table were prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma, while the amount of estimated future abandonment costs, the PV-10 of those costs and the Standardized Measure used in this table were determined by EXCO. The Proved Reserves, the PV-10 and the Standardized Measure of the Proved Reserves for our Alberta, Canada properties and the amount of estimated future abandonment costs and the PV-10 of those costs used in this table were determined by EXCO.

(2)

The PV-10 data is based on December 31, 2004 NYMEX spot prices of $6.15 per Mmbtu for natural gas and $43.45 per Bbl for oil adjusted for historical differentials between NYMEX and local prices.

(3)

Mmbbl converted to Bcfe on a one Bbl to six Mcf conversion ratio.

(4)

EXCO includes our U.S. properties other than those held by North Coast.

        Our Present Value of Estimated Future Net Revenues, or PV-10, is an estimate of future net revenues from a property at the date indicated, after deducting production and ad valorem taxes, future capital costs, abandonment 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 the date indicated. The prices used do not reflect any adjustments for derivatives. We believe that the PV-10 before income taxes, while not in accordance with GAAP, 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.

        The Standardized Measure represents the PV-10, after giving effect to income taxes, and is calculated in accordance with FAS 69.

Business Strategy

        We intend to become a leading independent oil and natural gas acquisition, exploitation and production company. We plan to achieve reserve, production and cash flow growth by focusing on our competitive strengths and executing our business strategy as highlighted below.

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        Quality asset base.    We own and plan to maintain a geographically diversified reserve base. Our primary areas of operations are onshore in Texas, Colorado, Ohio, Pennsylvania, West Virginia and, until February 10, 2005, Alberta, Canada. Our reserves in these areas are generally characterized by:

•

established histories of production;



•

long reserve lives;



•

low finding and development expenditures;



•

high drilling success rates; and



•

a high concentration of natural gas.

        We seek to improve the overall quality of our asset base by exploiting our properties that have potential for value enhancement and growth, while disposing of marginal or non-strategic properties.

        Acquisition and exploitation of strategic assets.    We maintain a disciplined acquisition process to seek and acquire quality producing properties that have value enhancement potential through low-risk development drilling and exploitation projects, such as infill drilling, workovers, recompletions and secondary recovery projects. From time to time, we may also participate in drilling exploratory wells. From December 1997 to December 31, 2004, we completed 128 acquisitions for total consideration of approximately $664.2 million, of which $616.2 million was allocated to acquisition of Proved Reserves. We plan to focus our acquisition activities onshore in North America and target natural gas properties with established histories of production, low-risk drilling and exploitation opportunities and long reserve lives, such as the properties in the Appalachian Basin that were acquired in the North Coast acquisition. In addition, our extensive knowledge of our operating areas and our acquisition expertise position us to capitalize on and integrate strategic acquisition opportunities in our core areas. Due to industry trends of consolidation and asset rationalization, we believe we will continue to have opportunities to acquire oil and natural gas properties at attractive rates of return.

        Cost-focused operations.    At December 31, 2004, we operate properties that contain approximately 92%, or 94% pro forma for the sale of Addison, of our Proved Reserves. Having operating rights with respect to our properties permits us to manage our operating costs, capital expenditures and the timing of development and exploitation of our properties. Using our estimate of Proved Reserves at the time of the acquisitions, we acquired 657.8 Bcfe of Proved Reserves in 128 acquisitions between December 1997 and December 31, 2004. Between January 1, 2000 and December 31, 2004, we invested approximately $776.1 million in acquisition, development, exploitation and exploration activities, adding 840.9 Bcfe to our Proved Reserves. During the same period we drilled 261 developmental wells and 7 exploratory wells, achieving a drilling success rate of 93% and 86%, respectively. We expect further improvement of our corporate efficiencies through the development and operation of a larger asset base from acquisitions, the disposition of high operating cost properties and further development of and exploitation of our existing asset base.

        Experienced, incentivized management team.    With an average industry work experience in excess of 24 years, our management team has considerable experience in acquiring and operating oil and natural gas properties. Since our management team first purchased a significant ownership interest in EXCO in December 1997 and assumed its current position as our senior management, we have achieved substantial growth in our reserves, production and cash flow through a strategy of acquiring producing properties with development and exploitation potential. From December 31, 1997 to December 31, 2004, we increased our Proved Reserves from 4.7 Bcfe to 686.0 Bcfe. In addition, members of our management team and key employees own approximately 16% of the voting capital stock of our parent company, EXCO Holdings.

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        Comprehensive commodity price risk management program.    We employ a comprehensive commodity price risk management program which better enables us to execute our business plan over an entire commodity price cycle. In connection with the incurrence of debt related to our acquisition activities, our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve more predictable cash flows. For example, in connection with the additional reserves that we acquired in the North Coast acquisition, we entered into additional commodity price risk management contracts during 2004.

Developments During 2004

        North Coast Acquisition.    On January 27, 2004, we acquired all of the outstanding common stock, options and warrants of North Coast Energy for a purchase price of $167.8 million, and we assumed $57.0 million of North Coast's outstanding indebtedness. As a result, North Coast became one of our wholly-owned subsidiaries and continues to be an energy company focused on the acquisition, exploration, exploitation, development and production of natural gas reserves in the Appalachian Basin. The North Coast acquisition established a new core operating area for us in the Appalachian Basin, which positions us to benefit from the attractive qualities of the basin and to capitalize on consolidation opportunities in the area.

        Private Placements.    On January 20, 2004, we completed the private placement of $350.0 million aggregate principal amount of 7¹/4% senior notes due 2011, or senior notes, pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended, or the Securities Act, at a price of 100% of the principal amount. The net proceeds of this offering were used to acquire North Coast, pay down debt under our credit facilities and North Coast's credit facility, repay our senior term loan in full and pay fees and expenses associated with these transactions.

        On April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of 7¹/4% senior notes due 2011 pursuant to Rule 144A, having the same terms and governed by the same indenture as the senior notes issued on January 20, 2004. The senior notes issued on April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. The net proceeds of this offering were used to repay substantially all of our Canadian debt under the Canadian credit facility and pay fees and expenses associated with the offering.

        Amended and Restated Credit Facilities.    Concurrent with the closing of the North Coast acquisition, we amended and restated our credit facilities. The amended and restated credit facilities provided for a maximum committed amount of $439.4 million and an initial borrowing base of $225.0 million. Our April 2004 amendment to the amended and restated credit facilities permitted, among other things, the issuance of an additional $100.0 million of senior notes on April 13, 2004 and provided for a reduction in the borrowing base under the amended and restated credit facilities to $200.0 million. In June 2004, our borrowing base was increased to $250.0 million.

        Acquisitions and Dispositions (other than North Coast).    During the year ended December 31, 2004, we completed 11 oil and natural gas property acquisitions in Canada and 6 in the United States, not including North Coast. Estimated total Proved Reserves net to our interest from these acquisitions included approximately 2.1 Mmbbls of oil and NGLs and 69.2 Bcf of natural gas. The total purchase price for the acquisitions was approximately $131.8 million funded with borrowings under our U.S. and Canadian credit agreements and from surplus cash.

        During the year ended December 31, 2004, we completed 21 sales of oil and natural gas properties in the United States. As of January 1, 2004, estimated total Proved Reserves, net to our interest from these properties included approximately 5.2 Mmbbls of oil and NGLs and 27.9 Bcf of natural gas. The total sales proceeds we received were approximately $51.9 million. During 2003, we recorded revenue of approximately $16.3 million and oil and natural gas production costs of $6.9 million on these

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properties. During 2004, we recorded revenue of approximately $12.1 million and oil and natural gas production costs of $4.6 million on these properties through the date of their respective disposition.

        Pro forma financial information has not been provided because management believes the acquisitions, other than North Coast, and dispositions were not material.

Developments Since December 31, 2004

        Sale of Addison.    On January 17, 2005, our board of directors approved the Share and Debt Purchase Agreement (the Addison Purchase Agreement), dated effective January 12, 2005, among 1143928 Alberta Ltd., a corporation organized under the laws of the Province of Alberta (Purchaser) and a wholly-owned subsidiary of NAL Oil & Gas Trust, an Alberta trust, EXCO and Taurus. The Addison Purchase Agreement provided that EXCO would sell to Purchaser all of the issued and outstanding shares of common stock of Addison. The Addison Purchase Agreement also provided that Taurus would sell to Purchaser a promissory note in the amount of U.S. $98.8 million and a promissory note in the amount of Cdn. $108.3 million (U.S. $79.3 million) (collectively, the Addison Notes), each of which were issued by Addison in favor of Taurus. This transaction closed on February 10, 2005.

        The aggregate purchase price for the Addison stock and the Addison Notes was Cdn. $553.3 million (U.S. $442.7 million). Of this amount, Cdn. $90.1 million (U.S. $72.1 million) was used to repay in full all outstanding balances under Addison's credit facility, while Cdn. $56.2 million (U.S. $45.0 million) was withheld and will be remitted to the Canadian government for potential income taxes that we may owe resulting from the sale of the stock. The net cash proceeds may only be utilized by us in accordance with the terms of the indenture governing the senior notes. In addition, $120.6 million of these proceeds are pledged as collateral under the senior notes. The purchase price is subject to further adjustment based upon, among other items, the final determination of Addison's working capital balance as of February 1, 2005.

        Addison Dividend.    On February 9, 2005, Addison made an earnings and profits dividend (as calculated under U.S. tax law) to EXCO in an amount of Cdn. $74.5 million (U.S. $59.6 million). Addison funded this dividend by an additional drawdown on its bank credit facility. The dividend was subject to Canadian tax withholding of Cdn. $3.7 million (U.S. $3.0 million). See "Note 17. Subsequent Events" to the Consolidated Financial Statements for additional information.

        Commodity Price Risk Management Activities.    In January and March 2005, we closed several of our commodity price risk management contracts upon the payment of $67.6 million to our counterparties, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production. We also entered into new commodity price risk management contracts at higher prices. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation—Our Liquidity, Capital Resources and Capital Commitments—Commodity Price Risk Management Activities" for more information on these new contracts.

        Strategic Alternatives We are Considering.    We are evaluating a number of strategic alternatives in light of the recent sale of Addison. We sold Addison for approximately $442.7 million, of which EXCO, as of March 29, 2005, holds approximately $273.3 million in cash after, among other things, the payment of taxes, the repayment of secured bank debt and payments related to the closing of several commodity price risk management contracts.

        The strategic alternatives being evaluated include, among other things: (1) an issuance of EXCO Holdings' equity securities; (2) a leveraged recapitalization of EXCO Holdings, which would include an equity buyout; (3) a spin-off of EXCO's Appalachian properties into a master limited partnership; (4) payment of a dividend to EXCO Holdings' shareholders; or (5) no restructuring or recapitalization and retention of the cash from the sale of Addison to continue our acquisition and development

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program. We caution, however, that no assurance can be given that any of these strategic alternatives, or any transaction, will be pursued or, if a transaction is pursued, that it will be consummated.

Forward-Looking Statements

        The statements contained in this annual report regarding our future financial and operating performance and results, business strategy, market prices, future commodity price risk management activities, plans and forecasts and other statements that are not historical facts are forward-looking statements, as defined in Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. 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" and 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 condition 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 or financial condition to materially differ from our expectations in this annual report, including, but not limited to:

•

estimates of reserves;



•

market factors, including demand for our production;



•

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



•

results of future drilling and acquisitions;



•

marketing and commodity price risk management activities;



•

future production and costs;



•

our ability to arrange financing;



•

our ability to service our indebtedness; and



•

all the other factors described herein under "Risk Factors."

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

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

Risk Factors

        The risk factors noted in this section and other factors noted throughout this annual report, including those risks identified in "Item 7. Management's Discussion and Analysis of Financial

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Condition and Results of Operation," describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this annual report.

Our reduced operating cash flow resulting from the Addison disposition may put a strain on our cash flow from operations.

        Our reduced operating cash flow following the Addison disposition may cause us to reduce capital expenditures including exploitation and development projects. These reductions may limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations and results of operations in the future. The effects of our reduced operating cash flow will be exacerbated by our high level of debt. See "Risks Relating To Our Indebtedness—We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt, including our senior notes."

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 beyond our control. The NYMEX spot prices for crude oil and natural gas at the close of business on December 31, 2003 were $32.52 per Bbl and $6.19 per Mmbtu and at December 31, 2004 were $43.45 per Bbl and $6.15 per Mmbtu. In addition, natural gas prices in the DJ Basin in Colorado, which accounted for approximately 5% of our natural gas production during the twelve months ended December 31, 2004, have been and may continue to be subject to lower market prices primarily due to higher transportation costs and capacity restraints. For the twelve months ended December 31, 2004, natural gas constituted 72%, or 82% pro forma for the sale of Addison, of our total production. Factors that affect the prices we receive for our oil and natural gas include:

•

the level of domestic production;



•

the availability of imported oil and natural gas;



•

actions taken by foreign oil and natural gas producing nations;



•

the cost and availability of transportation and pipeline systems with adequate capacity;



•

the cost and availability of other competitive fuels;



•

fluctuating and seasonal demand for oil and natural gas;



•

conservation and the extent of governmental price controls and regulation of production;



•

weather;



•

foreign and domestic government relations; and



•

overall economic conditions.

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

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Our commodity price risk management program may cause us to forego additional future profits or result in our making cash payments.

        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 commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements 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. Commodity price risk management arrangements may expose us to the risk of financial loss in some circumstances, including the following:

•

the counterparty to the commodity price risk management contract may default on its contractual obligations to us;



•

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



•

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

        Our commodity price risk management activities could have the effect of reducing our revenues. During 2004, we made cash settlement payments on our commodity price risk management contracts totaling $35.9 million. As of December 31, 2004, the net unrealized loss on our commodity price risk management contracts was $54.2 million. See "Item 1. Business—Developments Since December 31, 2004—Commodity Price Rise Management Activities" and see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation—Our Liquidity, Capital Resources and Capital Commitments—Derivative Financial Instruments" for more information about our commodity price risk management arrangements.

We may be unable to acquire or develop additional reserves.

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

We have joint and several liability for tax and ERISA liabilities attributable to members of Nuon Energy & Water's tax group.

        Prior to our acquisition of North Coast, North Coast was controlled by Nuon Energy & Water Investments, Inc. (Nuon Energy & Water), a subsidiary of n.v. NUON, a Dutch company with limited liability.

        North Coast and its subsidiaries are part of Nuon Energy & Water's consolidated, combined or unitary group for tax and ERISA purposes for tax years 2003 and 2004, and as a result, North Coast and its subsidiaries are jointly and severally liable for the taxes and ERISA liabilities of all members within that group. There is a risk that a federal, state, local or foreign taxing or other governmental authority may file a claim against North Coast and its subsidiaries for taxes and/or ERISA liabilities attributable to Nuon Energy & Water's consolidated, combined or unitary group for 2003 or 2004. Such taxes and/or ERISA liabilities may be significant and may include taxes associated with the North Coast acquisition. As set forth in the North Coast acquisition agreement, if such a claim is asserted, Nuon Energy & Water has agreed to be responsible for, and to indemnify us for, all taxes or ERISA liabilities

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attributable to Nuon Energy & Water and any of its affiliates other than North Coast and its subsidiaries, for any liability imposed on North Coast and its subsidiaries due to their inclusion in Nuon Energy & Water's consolidated, combined or unitary group, including any tax liability of North Coast as a result of North Coast making an election under Section 338(h)(10) of the Internal Revenue Code. Nuon Energy & Water's parent, n.v. NUON, has entered into an unconditional, unsecured guaranty agreement with us to guaranty Nuon Energy & Water's performance of its obligations under the North Coast acquisition agreement (specifically the tax indemnification provisions), the stock tender agreement and the escrow agreement. Both Nuon Energy & Water's indemnity and n.v. NUON's guaranty are unsecured obligations. There is a risk that neither entity will honor its obligations. Furthermore, neither entity may have any assets in the United States against which we could collect any final judgment we might be awarded.

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

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

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 of our issuance of the senior notes and the pledge of substantially all of our assets as collateral under our credit facilities, it may be difficult for us in the foreseeable future to obtain financing on an unsecured basis or to obtain additional secured financing other than purchase money indebtedness. If we are unable to obtain additional capital on satisfactory terms and conditions, we may lose opportunities to acquire oil and natural gas properties and businesses.

We may not be successful in managing our growth.

        The pursuit of additional acquisitions is a key part of our strategy. Our growth could strain our managerial, 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 may not be able to successfully integrate acquired oil and natural gas properties into our operations or achieve desired profitability.

We may encounter marketing obstacles.

        Our ability to market our oil and natural gas production will depend upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities. We are primarily dependent upon third parties to transport our products. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation and, prior to our disposition of Addison, Canadian regulation of oil and natural gas

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production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

We may have purchase price adjustments related to the sale of Addison in future years.

        We have agreed with 1143928 Alberta Ltd., the purchaser of the Addison stock and the Addison Notes, to make adjustments to the purchase price in the future if any of the following adjustments affect periods prior to February 1, 2005:

•

an adjustment arises from a Crown royalty audit commenced not later than December 31, 2009 and certain notice requirements are satisfied;



•

an adjustment arises from a joint venture audit commenced not later than February 28, 2007 and certain notice requirements are satisfied; or



•

an adjustment arises from a Thirteen Month Adjustment (as defined in the Addison Purchase Agreement) if claimed by February 10, 2006, and certain notice requirements are satisfied.

We agreed to indemnify 1143928 Alberta Ltd. for any breaches of the representations and warranties we made in the Addison Purchase Agreement.

        We may become liable for losses that 1143928 Alberta Ltd. incurs as a result of our breach of any of the representations and warranties we made in the Addison Purchase Agreement. We may not have sufficient cash available to implement our growth strategy if we are required to indemnify 1143928 Alberta Ltd. pursuant to the terms of the Addison Purchase Agreement.

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.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, development, exploration and exploitation activities.

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

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

        As of December 31, 2004, we do not operate wells that represent approximately 8%, or 6% pro forma for the sale of Addison, of the PV-10 of our Proved Reserves. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

•

the timing and amount of capital expenditures;



•

the operators' expertise and financial resources;

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•

the approval of other participants in drilling wells; and



•

the selection of suitable technology.

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

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

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

•

fires, explosions and blowouts;



•

pipe failures;



•

abnormally pressured formations; and



•

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

        These events may result in substantial losses to us from:

•

injury or loss of life;



•

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



•

pollution or other environmental damage;



•

environmental clean-up responsibilities;



•

regulatory investigation;



•

penalties and suspension of operations; or



•

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

        As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these losses or liabilities. Furthermore, insurance coverage

11

may not continue to be available 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 could require us to make large unbudgeted cash expenditures that could materially impact our cash flow.

        Our well control insurance policy, which covered drilling and workovers on our U.S. properties, excluding the North Coast properties, expired on March 10, 2005, and we have decided not to renew this policy. The terms quoted, including the premiums and deductibles, were not acceptable based on the types of wells that we are currently planning to drill or workover during the next policy year. We believe that the rates quoted are higher than rates quoted to other companies as a result of claims made on our well control insurance policy during 2001 and 2002. We plan to continue our current drilling and workover plans without well control insurance at this time.

        North Coast maintains a separate well control policy which is in effect through May 9, 2005 and applies only on the wells that we anticipate encountering high pressure formations. We may not be able to renew North Coast's well control policy at commercially acceptable premiums or at all.

We may experience production curtailments.

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

Repercussions from terrorist activities or armed conflict could harm our business.

        Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

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

        Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent.

Our business depends on Douglas H. Miller, our CEO.

        We are substantially dependent upon the skills of Mr. Douglas H. Miller. Mr. Miller has extensive experience in acquiring, financing and restructuring oil and natural gas companies. We do not have an employment agreement with Mr. Miller or maintain key man insurance. The loss of the services of Mr. Miller could hinder our ability to successfully implement our business strategy.

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Our principal shareholder is in a position to affect our ongoing operations, corporate transactions and other matters.

        EXCO Holdings, as our sole shareholder, has the right to elect our board of directors. For so long as EXCO Acquisition LLC, an affiliate of Cerberus Capital Management, LP, owns at least 20% of the issued and outstanding shares of EXCO Holdings, it has the right to elect a majority of the board of directors of EXCO Holdings. The interests of EXCO Acquisition LLC and its affiliates may conflict with the interests of the holders of our senior notes. In particular, EXCO Acquisition LLC may cause a change of control at a time when we do not have sufficient funds to repurchase our senior notes under the terms of our indenture.

We may have write-downs of our asset values.

        Prior to our going private transaction, we recorded pre-tax, non-cash ceiling test write-downs as follows: (a) during 2001, $28.7 million of our United States full cost pool and $20.9 million of our Canadian full cost pool and (b) during the second quarter of 2002, $17.5 million of our Canadian full cost pool. Depending upon oil and natural gas prices in the future, we may be required to write-down the value of our oil and natural gas properties and may have to impair goodwill 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. Future non-cash ceiling test write-downs would negatively affect our earnings and net worth.

We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas.

        Our ability to collect the proceeds from the sale of oil and natural gas from our customers depends on the payment ability of our customer base, which includes several significant customers. See "—Our Principal Customers" for more information on our customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. In addition, in recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our oil and natural gas production. This reduction in potential customers has reduced market liquidity and, in some cases, has made it difficult for us to identify creditworthy customers. We also sell a portion of our natural gas directly to end users. While we monitor the creditworthiness of our customers and, from time to time, demand adequate assurances of performance if the creditworthiness of our customers is in question, we may experience a material loss as a result of the failure of our customers to pay us for prior purchases of our oil or natural gas.

Competition in our industry is intense, and many of our competitors have greater financial, technological and other resources than we have.

        The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are currently experiencing difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We are unable to predict how such shortages and price increases will affect our development and exploitation program. Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and, as a result, we may not be able to compete satisfactorily. Many large oil

13

companies have been actively marketing some of their existing producing properties for sale to independent producers. We may not be successful in acquiring any of these properties.

There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected.

        While we continue to take action to assure compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Risks Relating to Our Indebtedness

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt, including our senior notes.

        As of March 15, 2005, we had total debt of approximately $452.9 million, including $2.9 million of premium related to our senior notes issued on April 13, 2004.

        Our level of debt could have important consequences, including the following:

•

it may be more difficult for us to satisfy our obligations with respect to our senior notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the indenture governing our senior notes and the agreements governing our other indebtedness;



•

we may have difficulty borrowing money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;



•

the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;



•

we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;



•

we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;

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•

we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices; and



•

our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

        Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our earnings will be sufficient to allow us to pay the principal and interest on our debt, including our senior notes, and meet our other obligations. If we do not have enough money to service our debt, we may be required but unable to refinance all or part of our existing debt, including our senior notes, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. Further, failing to comply with the financial and other restrictive covenants in our U.S. credit agreement and the indenture governing our senior notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

        Together with our subsidiaries, we may be able to incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. Although the indenture governing our senior notes contains restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. On March 15, 2005, we had approximately $144.7 million of additional borrowing capacity under our U.S. credit facility, subject to specific requirements, including compliance with financial covenants. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially increase.

We have invested a substantial amount of cash received from the sale of Addison in short-term commercial paper that is subject to interest rate risk and default risk.

        As of March 29, 2005, we had approximately $273.3 million of cash. After the sale of Addison and in compliance with the indenture governing our senior notes, we invested approximately $255.5 million of cash from the sale of Addison in short-term commercial paper having an average maturity of 30 days or in overnight funds at JPMorgan Securities Inc. These investments are subject to interest rate risks and default risks.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

        Our ability to make payments on and to refinance our indebtedness, including our senior notes, and to fund planned capital expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas.

        Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us under our credit facility in an amount sufficient to enable us to pay our indebtedness, including our senior notes, or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on

15

commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, including payments on our senior notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

        Our credit facility and the indenture governing our senior notes contain a number of significant covenants that, among other things, restrict our ability to:

•

dispose of assets;



•

incur or guarantee additional indebtedness and issue certain types of preferred stock;



•

pay dividends on our capital stock;



•

create liens on our assets;



•

enter into sale or leaseback transactions;



•

enter into specified investments or acquisitions;



•

repurchase, redeem or retire our capital stock or subordinated debt;



•

merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;



•

engage in specified transactions with subsidiaries and affiliates; or



•

pursue other corporate activities.

        Also, our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and, as a result, we may not be able to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit facility and the indenture governing our senior notes.

        A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit facility and our senior notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit facility and our senior notes. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

We conduct a material portion of our operations through our subsidiaries and may be limited in our ability to access funds from these subsidiaries to service our debt, including our senior notes.

        We conduct a material portion of our operations through our subsidiaries and depend to some degree upon dividends and other intercompany transfers of funds from our subsidiaries to meet our debt service and other obligations, including our senior notes. In addition, the ability of our subsidiaries to pay dividends and make other payments to us may be restricted by, among other things, applicable corporate and other laws, transfer pricing regulations, potentially adverse tax consequences and agreements of our subsidiaries. Although the indenture governing our senior notes limits the ability of our subsidiaries to enter into consensual restrictions on their ability to pay dividends and make other payments, the limitations are subject to a number of significant qualifications and exceptions. If we are unable to access the cash flow of our subsidiaries, we may have difficulty meeting our debt obligations.

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Our Oil, Natural Gas and NGL Reserves

        The following table summarizes our Proved Reserves at the dates shown, and was prepared in accordance with the rules and regulations of the SEC:

(1)

EXCO includes our U.S. properties other than those held by North Coast.

(2)

Mbbl converted to Mmcfe on a one Bbl to six Mcf conversion ratio.

(3)

The PV-10 data is based on December 31, 2004 NYMEX spot prices of $6.15 per Mmbtu for natural gas and $43.45 per Bbl for oil adjusted for historical differentials between NYMEX and local prices.

(4)

The Standardized Measure represents the PV-10, after giving effect to income taxes, and is calculated in accordance with FAS 69.

        The reserve estimates presented as of December 31, 2002, 2003 and 2004 for the United States and the reserve estimates as of December 31, 2002 and 2003 for Canada have been prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The reserve estimates for Canada as of December 31, 2004 have been prepared by our engineers. For 2002, the estimate of our PV-10 and Standardized Measure is based upon the report on our Canadian and U.S. Proved Reserves as prepared by Lee Keeling and Associates, Inc. For 2003, the estimate of our PV-10 and Standardized Measure is based upon our estimate of future abandonment costs and the report on our Canadian and U.S. Proved Reserves as prepared by Lee Keeling and Associates, Inc. For 2004, the estimate of our PV-10 and Standardized Measure is based upon our estimate of future abandonment costs, the Canadian reserve estimates prepared by our engineers and the report on our U.S. Proved Reserves as prepared by Lee Keeling and Associates, Inc. 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,

17

capital expenditures, taxes and availability of funds. These reports should not be construed as the current market value of our 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 18. Supplemental Information Relating to Oil and Natural Gas Producing Activities" to our Consolidated Financial Statements for additional information regarding our oil, natural gas and NGL reserves, including the PV-10 and our Standardized Measure.

Our Production, Prices and Expenses

        The following table summarizes for the periods indicated, our revenues (before cash settlements of derivative financial instruments), net production of oil, natural gas and NGLs sold, 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. Revenues shown in this table do not reflect the impact of derivatives that were treated as hedges for the year ended December 31, 2002 and for the 209 day period from January 1, 2003 to July 28, 2003 in order to show revenues on a consistent basis for the three years presented. Oil and natural gas revenues for the year ended December 31, 2002 and for the 209 day period from January 1, 2003 to July 28, 2003 as shown on the consolidated statements of operations have been reduced by $7.7 million and by $14.5 million, respectively, for cash settlements paid on hedges.

(1)

EXCO includes our U.S. properties other then those held by North Coast.

(2)

Excludes the effects of derivative cash settlements.

Our Interest in Productive Wells

        The following table quantifies as of December 31, 2004 our productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells. 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

18

well is not a physical well, but is 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, 2004, we owned interests in 12 gross wells with multiple completions.

        As of December 31, 2004, we were the operator of 4,627 gross (4,199.8 net) wells, which represented approximately 92% of the PV-10 (as of December 31, 2004) of our Proved Reserves.

Our Drilling Activities

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

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

        The drilling activities in the United States referenced in the above table were primarily conducted in Texas, Colorado, Louisiana, Kansas, Ohio, Pennsylvania and West Virginia. The drilling activities in Canada referenced in the above table were conducted in Alberta. As of December 31, 2004, we owned a 100% working interest in two wells being drilled in Pennsylvania and working interests of 99.6% and 100% in two wells being drilled in Texas. As of February 28, 2005, we owned a 100% working interest in two wells being drilled in Pennsylvania, an 87.3% working interest in one well being drilled in Texas and a 100% working interest in one well being drilled in Colorado.

Summary of Our Development and Exploitation Projects

        We are currently pursuing an active development and exploitation strategy in the United States. For the year 2005, we have budgeted up to $55.9 million for development drilling, exploration, recompletions,

20

production facilities and other exploitation related projects to implement this strategy, of which $25.8 million is for North Coast activities.

        Set forth below are highlights of our planned activities for 2005.

EXCO Fields

Wattenberg Field

        The Wattenberg Field is a natural gas field located in Weld County, Colorado. We acquired these properties during 2002. We hold working interests ranging from less than 3% to 100% in 115 producing wells, of which we operate 111 wells. The wells produce primarily from the Codell formation at a depth of approximately 7,000 feet. We currently plan to drill 8 wells and perform workover operations on 4 wells during 2005.

Oak Hill Field

        The Oak Hill Field is a natural gas field located in Rusk County, Texas. We acquired these properties during 2004. We hold working interests ranging from 74% to 100% in 35 producing operated wells. The wells produce primarily from the Cotton Valley formation at a depth ranging from 10,400 to 11,100 feet. We currently plan to drill 9 wells during 2005.

Minden Field

        The Minden Field is a natural gas field located in Rusk County, Texas. We acquired these properties in January 2005. We hold working interests of 100% in 14 producing operated wells. The wells produce primarily from the Upper Cotton Valley formation at a depth ranging from 9,100 to 10,800 feet. We currently plan to drill 6 wells during 2005.

North Coast Areas/Fields

Ravenswood Area

        The Ravenswood Area is located in West Virginia. We operate 579 wells, which represent 99% of our reserves at Ravenswood. Production in the Ravenswood area is primarily from Mississippian and Devonian formations at depths of 2,500 to 4,400 feet. We currently plan to drill 15 wells during 2005.

Maben Area

        The Maben Area is located in southwest West Virginia. We operate 311 wells, which represent 99% of our reserves in the Maben area. Maben produces from Mississippian and Devonian formations at depths ranging from 1,500 to 5,500 feet. We currently plan to drill 6 wells during 2005.

Adamsville Area

        The Adamsville Area is located in southern Ohio. We operate 214 wells, which represent 99% of the reserves we own in the Adamsville area. Adamsville produces from the Clinton reservoir and the Knox series at depths from 3,000 to 6,200 feet. We currently plan to drill 11 wells during 2005.

Northwest Pennsylvania Area

        The Northwest Pennsylvania Area of the Appalachia Basin includes the Jamestown, Corry and Allegheny National Forest fields. We operate 461 wells, which represent 100% of the reserves we have in the area. Production is from the Medina and Devonian formations at depths from 1,600 to 4,900 feet. We currently plan to drill 42 development wells during 2005.

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Pine Glen Field

        The Pine Glen Field is located in central Pennsylvania. We operate 228 wells which represent 100% of our reserves in the field. Production is primarily from the Venango, Bradford, and Elk formation at depths from 1,800 to 4,600 feet. We currently plan to drill 24 wells during 2005.

Our Developed and Undeveloped Acreage

        Developed acreage are those acres spaced or assignable to producing wells. Undeveloped acreage are those acres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The following table sets forth the developed and undeveloped acreage for us at December 31, 2004:

        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.

        The undeveloped "held by production" acreage in many cases represents potential additional drilling opportunities through down spacing and drilling of proved undeveloped and probable locations in the same formation(s) already producing in a given oil or natural gas field without the necessity of purchasing additional leases or producing properties.

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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. During 2004, we received proceeds of $51.9 million from the sale of non-core properties in the United States.

Our Principal Customers

        During the year ended December 31, 2004, no single purchaser accounted for 10% or more of our total oil and natural gas revenues. Our top eight purchasers accounted for approximately 36% of our total oil and natural gas revenues. During the year ended December 31, 2003, sales of oil to Plains All American, Inc. and affiliates and sales of natural gas to Nexen Marketing U.S.A., Inc. and to Coral Canada U.S. Inc. accounted for 16.6%, 12.9% and 11.4%, respectively, of our total oil and natural gas revenues. In most of our operating areas, if we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser's service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser.

Competition

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

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

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

Applicable 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

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

        Our sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of oil by pipelines are regulated by the FERC under the Interstate Commerce Act. FERC has implemented a simplified and generally applicable rate-making methodology for interstate oil pipelines to fulfill the requirements of Title VII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates.

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

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

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

U.S. Federal Taxation

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

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U.S. Environmental Regulations

        The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are 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 environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain of our activities, limit or prohibit other activities because of protected areas or species, can impose certain substantial liabilities for the clean-up of pollution, impose certain reporting requirements, regulate remedial plugging operations to prevent future contamination and can require substantial expenditures for compliance. We cannot predict what effect future regulaton or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

        Under CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing or remediating a release; (2) administrative, civil or criminal fines or penalties; or (3) OPA specified damages, such as loss of use, and natural resource damages. The extent of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters.

        CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability for costs of investigation and remediation and for natural resource damages, 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, clean-up costs are usually allocated among various persons. These classes of persons, or so-called potentially responsible parties (PRPs), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action. Liability can arise from conditions on properties

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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. We cannot assure you that the exemption will be preserved in any future amendments of the act. Such amendments could have a significant impact on our costs or operations. 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 at a future date. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA. We also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. Certain states have comparable statutes. In the event contamination is discovered at a site on which we are or have been an owner or operator, we could be liable for costs of investigation and remediation and natural resource damages.

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

        Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Smaller sources may qualify for exemption from permit requirement or existing authorizations such as permits by rule or general permits. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

        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 may 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 result.

        If in the course of our routine oil and natural gas operations surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for waste handling, remediation and third party actions for damages. Moreover, we are only able to directly control the operations of the wells that we operate. Notwithstanding our lack of control over wells owned by us but

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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.

        In 2003, DOT through RSPA adopted new requirements for certain shippers of hazardous materials. These have both training and security planning requirements that may apply to our operations. We do not believe that the costs that will be incurred by us for compliance will be significant, but cannot guarantee that result or predict the ultimate cost to us.

        There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. States, such as Texas, also have coastal management programs, which provide for, among other things, the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. Coastal management programs also may provide for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the state coastal management plan. In the event our activities trigger these programs, this review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by 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 complying with environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed and are subject to interpretation, we are unable to predict the ultimate cost of compliance or the extent of liability risks. We are also unable to assure you that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with environmental laws and regulations in the future. If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

OSHA and Other Regulations

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

Canadian Laws and Regulations

General

        The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. The provincial government of Alberta has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, the prevention of waste and other matters. Although it is not expected that these controls and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar

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size, the controls and regulations should be considered carefully by investors in the oil and natural gas industry. Outlined below are some of the principal aspects of legislation and regulations governing the oil and natural gas industry. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing—Oil

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

Pricing and Marketing—Natural Gas

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

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

Pipeline Capacity

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

The North American Free Trade Agreements

        The North American Free Trade Agreement, NAFTA, among the governments of Canada, the U.S. and Mexico became effective on January 1, 1994. 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 resources 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; or

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•

disrupt normal channels of supply.

        All three countries are prohibited from imposing minimum export or import price requirements.

Land Tenure

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

Royalties and Incentives

        In addition to federal regulation, each province in Canada has legislation and regulations that govern land tenure, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on 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 depends in part on prescribed reference prices, the type of product being produced, well productivity, geographical location and field discovery date.

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

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

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

        In Alberta, certain producers of oil or natural gas are also entitled to a credit against the royalties payable to the Alberta Crown by virtue of the Alberta royalty tax credit program (ARTC). The ARTC program is based on a price-sensitive formula, and the ARTC rate varies between 75%, at prices for oil below Cdn. $100 per cubic meter, and 25%, at prices above Cdn. $210 per cubic meter. The ARTC rate is applied to a maximum of Cdn. $2.0 million 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

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ARTC. The ARTC rate is established quarterly based on the average "par price," as determined by the Alberta Resource Development Department for the previous quarterly period.

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

Canadian Environmental Regulation

        Prior to February 10, 2005, our operations included the exploration, production and development of oil and natural gas in Alberta, Canada. As a result, we may continue to be subject to environmental regulation, including provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and natural gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. In addition, 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. We could incur material fines and penalties or liabilities for pollution damage and clean-up costs as a result of violations of, or liabilities under, environmental laws and regulations.

        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.

        On December 17, 2002, Canada ratified the Kyoto Protocol, thereby committing to a 6% reduction in greenhouse gas emissions below 1990 levels within the 2008-2012 commitment periods. The Climate Change Plan for Canada was released in November 2002, outlining the approach the Government of Canada intends to take to implement its emissions reduction commitment. Natural Resources Canada, an arm of the federal government, established the Large Final Emitters Group to serve as the focal point for government discussions with industry sectors in the implementation of the Climate Change Plan for Canada. In addition to other targeted measures set out in the Plan, it established a three-pronged approach to address emissions from large industrial emitters: targets for reductions established through covenant with a regulatory or financial backstop (55 megatonne (Mt) reduction); access to a domestic emissions trading system, domestic offsets and international permits to provide flexibility; and complementary measures (an additional 11 Mt reduction). The Large Final Emitters Group will negotiate agreements with large industrial emitters to reduce greenhouse gas emissions through 2012, using the mechanisms described above. As a result of Canada's ratification of the Kyoto Protocol, reductions in greenhouse gases from our operations may be required, which could result in increased capital expenditures and/or reductions in the production of oil and natural gas.

        We believe that we are in material compliance with applicable environmental laws and regulations.

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

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adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

        Our properties are generally burdened by:

•

customary royalty and overriding royalty interests;



•

liens incident to operating agreements; and



•

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

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

Our Employees

        As of December 31, 2004, we employed 284 persons (238 in the United States and 46 in Canada) of which 131 were involved in field operations and 153 were engaged in technical, office or administrative activities. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be good. We also utilize the services of independent consultants on a contract basis.

Certain Financial Information Regarding Our Former Canadian Operations

        See "Note 10. Geographic Operating Segment Information and Oil and Natural Gas Disclosures" to our Consolidated Financial Statements for certain information regarding our former Canadian operations.

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 one Bbl of oil or NGLs to six Mcf of natural gas.

        Btu.    British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

        Completion.    The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

        Infill Drilling.    Drilling of a well between known producing wells to better exploit the reservoir.

        Mbbl.    One thousand stock tank barrels.

        Mcf.    One thousand cubic feet of natural gas.

        Mcfe.    One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

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        Mmbbl.    One million stock tank barrels.

        Mmbtu.    One million British thermal units.

        Mmcf.    One million cubic feet of natural gas.

        Mmcfe/d.    One million cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas per day.

        Mmmbtu.    One billion British thermal units.

        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.

        NYMEX.    New York Mercantile Exchange.

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

        Present Value of Estimated Future Net Revenues or PV-10.    The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, after deducting production and ad valorem taxes, future capital costs, abandonment 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 the date indicated, 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.

        Proved Developed Reserves.    Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

        Proved Reserves.    The estimated quantities of oil, natural gas and natural gas liquids which geological engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

        Proved Undeveloped Reserves.    Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

        Reserve Life.    The estimated productive life of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this annual report, reserve life is calculated by dividing the Proved Reserves (on a Mcfe basis) at the end of the period by production volumes for the previous 12 months.

        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.

        Standardized Measure of Discounted Future Net Cash Flows or the Standardized Measure.    Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end Proved Reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes are computed by applying the

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statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

Available Information

        We do not currently maintain an active Internet website. Accordingly, we do not make our filings with the SEC available on or through a website. We will provide paper copies of our filings (excluding exhibits) free of charge upon request. Please mail your request to: EXCO Resources, Inc., 12377 Merit Drive, Suite 1700, LB 82, Dallas, TX 75251, Attention: Investor Relations. You may also call us at (214) 368-2084 and ask to speak to Investor Relations.

ITEM 2. PROPERTIES

Corporate Offices

        We lease approximately 33,500 square feet of office space in Dallas, Texas, for our corporate offices. The lease expires December 31, 2011, and requires monthly rental payments of approximately $33,200. We own a building in Twinsburg, Ohio that houses North Coast's corporate offices. The building contains approximately 12,000 square feet of office and warehouse space. We also have small offices for technical and field operations in Texas, Oklahoma, Colorado, Ohio and West Virginia. We have omitted information related to Addison's office lease in Calgary, Alberta due to the sale of Addison in February 2005.

Other

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

ITEM 3. LEGAL PROCEEDINGS

        In the ordinary course of business, we are periodically a party to lawsuits. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a materially adverse effect on our results of operations or financial condition. However, future costs associated with legal proceedings may be material to our operating results and liquidity.

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

        On November 18, 2004, our sole shareholder, EXCO Holdings, executed a written consent electing Messrs. Vincent J. Cebula, Jeffrey Serota and Robert H. Niehaus to our board of directors. Messrs. Cebula, Serota and Niehaus joined Messrs. Douglas H. Miller, Stephen F. Smith, T. W. Eubank, J. Douglas Ramsey, Richard E. Miller and Lenard Tessler on our board of directors.

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PART II