Unless the context requires otherwise, references to "EXCO," "EXCO Resources," "Company," "we," "us," and "our" are to EXCO Resources, Inc. and its consolidated subsidiaries.

Forward-looking statements

This quarterly report contains forward-looking statements, as defined in
Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

• our future financial and operating performance and results;

• our business strategy;

• market prices;

• our future derivative financial instrument activities; and

• our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words "may," "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, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this quarterly report, including, but not limited to:

• fluctuations in prices of oil and natural gas;

• imports of foreign oil and natural gas, including liquefied natural gas;

• future capital requirements and availability of financing;

• continued disruption of credit and capital markets and the ability of financial institutions to honor their commitments;

• estimates of reserves and economic assumptions;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

• exploratory risks, including our Haynesville/Bossier shale play in East Texas/North Louisiana and the Marcellus and Huron shale plays in Appalachia;

• risks associated with the operation of natural gas pipelines and gathering systems;

• discovery, acquisition, development and replacement of oil and natural gas reserves;

• cash flow and liquidity;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• marketing of oil and natural gas;

• developments in oil-producing and natural gas-producing countries;

• litigation;

• competition;

• general economic conditions, including costs associated with drilling and operations of our properties;

• environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases;

• receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;

• decisions whether or not to enter into derivative financial instruments;

• events similar to those of September 11, 2001;

• actions of third party co-owners of interests in properties in which we also own an interest;

• fluctuations in interest rates; and

• our ability to effectively integrate companies and properties that we acquire.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2008.

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, the availability of capital from our revolving credit facilities and liquidity from capital markets. Declines in oil or natural gas prices may have a material adverse affect on 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 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.

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, we have midstream operations in the East Texas/North Louisiana area. Our assets in East Texas/North Louisiana are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries and together they are collectively referred to as EXCO Operating.
Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating's debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources' debt. This structure allows us to maintain two credit agreements: one at EXCO Resources, or the EXCO Resources Credit Agreement, which currently has a borrowing base of $1.175 billion and one at EXCO Operating, or the EXCO Operating Credit Agreement, which currently has a borrowing base of $1.3 billion. We expect to continue to grow by leveraging our management team's experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and exploitation projects, entering into beneficial joint development agreements, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. At times, we also look at strategic asset sales and joint development agreements to support our strategy of growth. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments, and manage our capital structure.

Oil and natural gas prices have historically been volatile. On June 30, 2009, the spot market price for natural gas at Henry Hub was $3.89 per Mmbtu, a 70.3% decrease from June 30, 2008. The price of oil has also shown significant volatility, with a $69.79 per Bbl spot market price for oil at Cushing, Oklahoma at June 30, 2009, a 50.1% decrease from June 30, 2008. During the

six months ended June 30, 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $46.34 per Bbl and $4.07 per Mcf, respectively, compared with the six months ended June 30, 2008 average realized prices of $109.21 per Bbl and $9.87 per Mcf, respectively. It is impossible to predict the duration or outcome of these price declines or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity.

Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions.

At the end of the first quarter of 2009, we revised our expected capital expenditure estimate to approximately $500.0 million. We do not budget for acquisitions as these transactions are opportunistic in nature. In light of our drilling and completion results in our Haynesville shale area, we expect to increase our development drilling and leasing activities in East Texas/North Louisiana. Although our level of activity will increase, our expected capital expenditures will remain at approximately $500.0 million for 2009 as a result of the pending sale to an affiliate of BG Group, plc, or BG Group, as discussed below, which contains a provision in which BG Group will fund 75% of our capital expenditures on certain drilling and completion activities up to $400.0 million.

While we are actively pursuing the sale of additional non-strategic assets, our future growth will depend upon our ability to continue to identify and add oil and natural gas reserves in excess of production at a reasonable cost. We plan to maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

In line with management's goals for 2009, during the second quarter of 2009 we completed the sale of certain non-strategic assets, resulting in net cash proceeds of approximately $51.4 million after customary closing and post closing adjustments. We have an active, ongoing program to sell additional non-strategic assets and have reached agreements to close on certain asset sales in the third quarter of 2009 for total proceeds of approximately $390.0 million, subject to customary closing and post-closing adjustments.

The largest dispositions we expect to close in the third quarter were announced in June. On June 28, 2009 we entered into two definitive agreements for the sale of our Norge Marchand Unit in Grady County, Oklahoma, other selected Oklahoma, Kansas and Texas Panhandle assets, or the Mid-Continent Agreement, and our Gladewater area and Overton Field assets in Gregg, Upshur and Smith Counties, Texas, or the East Texas Agreement, to Encore Operating, L.P., or Encore, totaling $375.0 million. The sales are expected to close in August 2009, subject to customary closing and post closing adjustments, and will be effective as of April 1, 2009. Net proceeds will be used to pay down our outstanding debt.

On June 29, 2009 we entered into a definitive agreement with BG Group for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which includes most of our oil and natural gas assets in East Texas/North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), and for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We will receive $655.0 million in cash at closing, subject to customary closing and post-closing adjustments, pursuant to this transaction. BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, we will not be required to repay any of this funding. The joint development transaction is expected to close in August 2009 and will have an effective date of January 1, 2009. In addition, on August 5, 2009, we entered into a definitive agreement regarding the sale of 50% of our midstream assets within the AMI. Proceeds from the sale of the midstream assets will be $249.0 million subject to customary closing and post-closing adjustments. We expect to use the net proceeds from the transactions with BG Group to pay off our $300.0 million senior unsecured term credit agreement, or Term Credit Agreement, and use the remaining proceeds to pay down outstanding debt under our revolving credit agreements.

In connection with the asset sales closed in the second quarter of 2009, we liquidated certain of our derivative contracts to stay in compliance with our debt agreements, resulting in gains of approximately $17.4 million. These gains are recorded in "Gain (loss) on derivative financial instruments" on our condensed consolidated statements of operations. We applied these receipts, along with a portion of the net receipts of the assets sales, to pay down outstanding debt under our revolving credit agreements.

In connection with our divestiture transactions, we received cash deposits of $57.7 million, of which $37.5 million was deposited into an escrow account and is included in "Restricted cash" on the condensed consolidated balance sheets. These funds will be released upon the closing of the sales.

Critical accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill,

asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2008.

Recent accounting pronouncements

On June 29, 2009, the Financial Accounting Standards Board, or the FASB, issued FASB Statement No. 168, "FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles-a Replacement of FASB Statement No. 162," or SFAS No. 168. SFAS No. 168 establishes "The FASB Accounting Standards Codification," or Codification, which will become the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date of SFAS No. 168, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. SFAS No. 168 is effective for interim and annual periods ending after September 15, 2009.

On June 12, 2009, the FASB issued FASB Statement No. 167, "Amendments to FASB Interpretation No. 46(R)," or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), "Consolidation of Variable Interest Entities," and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity's purpose and design and a company's ability to direct the activities of the entity that most significantly impact the entity's economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of June 30, 2009, we do not have any variable interest entities and as such, the final rule will not have an effect on our financial statements and disclosures.

On June 12, 2009, the FASB issued FASB Statement No. 166, "Accounting for Transfers of Financial Assets," or SFAS No. 166. SFAS No. 166 is a revision to FASB Statement No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a "qualifying special-purpose entity," changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

On May 28, 2009, the FASB issued FASB Statement No. 165, "Subsequent Events," or SFAS No. 165. SFAS No. 165 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. SFAS No. 165 is effective for interim and annual periods ending after June 15, 2009.

On April 9, 2009, the FASB issued Staff Position FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly," or FSP FAS 157-4. FSP FAS 157-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph 19 of FASB SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." FSP FAS 157-4 is effective for interim periods ending after June 15, 2009. See "-Note 9. Derivative financial instruments and fair value measurements" to our Notes to Condensed Consolidated Financial Statements for the impact to our disclosures.

On April 9, 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, "Interim Disclosures about Fair Value of Financial Instruments," or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 amend Statement of Financial Accounting Standards, or SFAS, No. 107, "Disclosures about Fair Value of Financial Instruments," to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. The staff position also amends APB Opinion No. 28, "Interim Financial Reporting" to require fair value disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 was effective for interim periods ending after June 15, 2009. See "-Note 9. Derivative financial instruments and fair value measurements" to our Notes to Condensed Consolidated Financial Statements for the impact to our disclosures.

On April 1, 2009, the FASB issued FASB Staff Position No. 141(R)-1, "Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies," or FSP 141(R)-1. FSP 141(R)-1 amends and clarifies FASB SFAS No. 141 (revised 2007), "Business Combinations," or SFAS No. 141, to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a

business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.

In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities," or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company's strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See "-Note 9. Derivative financial instruments and fair value measurements" in our Notes to Condensed Consolidated Financial Statements for the impact to our disclosures.

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:

• Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

• Permits the use of new technologies for determining oil and natural gas reserves;

• Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

• Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

• Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

• Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

We are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and disclosures.

Our results of operations

A summary of key financial data for the three and six months ended June 30, 2009 and 2008 related to our results of operations is presented below:

                                                            Three months ended                                          Six months ended                Year to date
                                                                 June 30,                  Quarter change                   June 30,                       change
(dollars in thousands, except per unit prices)             2009             2008             2009-2008               2009               2008             2009-2008
Production:
Oil (Mbbls)                                                    485              545                    (60 )            1,012              1,053                  (41 )
Natural gas (Mmcf)                                          33,608           32,621                    987             66,792             64,670                2,122
Total production (Mmcfe) (1)                                36,518           35,891                    627             72,864             70,988                1,876
Oil and natural gas revenues before derivative
financial instrument activities:
Oil                                                     $   27,197       $   65,981       $        (38,784 )     $     46,893       $    114,998       $      (68,105 )
Natural gas                                                119,055          362,755               (243,700 )          271,567            638,581             (367,014 )

Total oil and natural gas                               $  146,252       $  428,736       $       (282,484 )     $    318,460       $    753,579       $     (435,119 )

Midstream operations:
Midstream revenues (before intersegment
eliminations)                                           $   29,618       $   39,574       $         (9,956 )     $     62,207       $     56,657       $        5,550
Midstream operating expenses (before intersegment
eliminations)                                               20,345           27,624                 (7,279 )           46,389             37,590                8,799

Midstream operating profit (before intersegment
eliminations)                                                9,273           11,950                 (2,677 )           15,818             19,067               (3,249 )
Intersegment eliminations                                   (8,050 )         (7,818 )                 (232 )          (16,032 )          (15,070 )               (962 )

Midstream operating income (loss) (after
intersegment eliminations)                              $    1,223       $    4,132       $         (2,909 )     $       (214 )     $      3,997       $       (4,211 )

Oil and natural gas derivative financial
instruments:
Cash settlements (payments) on derivative financial
instruments                                             $  142,139       $  (90,380 )     $        232,519       $    240,568       $    (87,365 )     $      327,933
Non-cash change in fair value of derivative
financial instruments                                     (173,156 )       (572,273 )              399,117            (50,201 )         (916,482 )            866,281

Total derivative financial instrument activities        $  (31,017 )     $ (662,653 )     $        631,636       $    190,367       $ (1,003,847 )     $    1,194,214

Average sales price (before cash settlements of
derivative financial instruments):
Oil (per Bbl)                                           $    56.08       $   121.07       $         (64.99 )     $      46.34       $     109.21       $       (62.87 )
Natural gas (per Mcf)                                         3.54            11.12                  (7.58 )             4.07               9.87                (5.80 )
Natural gas equivalent (per Mcfe)                             4.00            11.95                  (7.95 )             4.37              10.62                (6.25 )
Costs and expenses:
Oil and natural gas operating costs (2)                 $   39,032       $   40,710       $         (1,678 )     $     79,718       $     73,781       $        5,937
Production and ad valorem taxes                              9,362           21,433                (12,071 )           21,794             40,743              (18,949 )
Gathering and transportation                                 4,055            3,700                    355              7,952              6,831                1,121
Depletion                                                   48,093          105,166                (57,073 )          123,077            209,079              (86,002 )
Depreciation and amortization                                7,087            6,115                    972             13,897             11,419                2,478
General and administrative (3)                              22,488           19,657                  2,831             43,035             42,284                  751
Interest expense, net, including impacts of interest
rate swaps                                                  46,891           20,273                 26,618             83,023             56,293               26,730
. . .