Exco Resources 10K 2005 Annual report

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TABLE OF CONTENTS
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2005
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from to

Commission File Number 0-9204

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

Texas (State or other jurisdiction of incorporation or organization)		74-1492779 (I.R.S. Employer Identification No.)
12377 Merit Drive, Suite 1700, LB 82 Dallas, Texas (Address of principal executive offices)		75251 (Zip Code)

Registrant's telephone number, including area code:(214) 368-2084

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, $0.001 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES o NO ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o NO ý

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

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO ý

As of March 15, 2006, the registrant had 104,004,089 outstanding shares of common stock, par value $.001 per share, which is its only class of stock. As of the last business day of the registrant's most recently completed second fiscal quarter, the registrant's common stock was not traded on any public securities market and, therefore, the aggregate market value of its common equity held by non-affiliates cannot be determined as of such date.

DOCUMENTS INCORPORATED BY REFERENCE
None

TABLE OF CONTENTS


PART I
	Item 1.	Business
	Item 1A.	Risk Factors
	Item 1B.	Unresolved Staff Comments
	Item 2.	Properties
	Item 3.	Legal Proceedings
	Item 4.	Submission of Matters to a Vote of Security Holders
PART II
	Item 5.	Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
	Item 6.	Selected Financial Data
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operation
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
	Item 8.	Financial Statements and Supplementary Data
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
	Item 9A.	Controls and Procedures
	Item 9B.	Other Information
PART III
	Item 10.	Directors and Executive Officers of the Registrant
	Item 11.	Executive Compensation
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	Item 13.	Certain Relationships and Related Transactions
	Item 14.	Principal Accountant Fees and Services
PART IV
	Item 15.	Exhibits and Financial Statement Schedules

EXCO RESOURCES, INC.

PART I

ITEM 1. BUSINESS

General

EXCO Resources, Inc., a Texas corporation incorporated in October 1955, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our operations are focused in key North American oil and natural gas areas including Appalachia, East Texas, Mid-Continent, Permian and the Rockies. As of December 31, 2005, our Proved Reserves were approximately 444.6 Bcfe, of which 91% were natural gas and 80% were Proved Developed Reserves. As of December 31, 2005, the related PV-10 of our Proved Reserves was $1.4 billion, and the Standardized Measure of our Proved Reserves was $930.3 million. For the twelve months ended December 31, 2005, we produced 23.6 Bcfe of oil and natural gas, which translates to a Reserve Life of approximately 18.8 years. For the twelve month period ended December 31, 2005, we generated $202.9 million of oil and natural gas revenues. On February 14, 2006, as more fully described below, we acquired TXOK Acquisition, Inc., or TXOK. Our pro forma Proved Reserves as of December 31, 2005, including those of TXOK are 668.3 Bcfe with a PV-10 of Proved Reserves of $2.3 billion and a Standardized Measure of Proved Reserves of $1.6 billion.

Unless the context requires otherwise, references in this annual report to "EXCO," "we," "us," and "our" are to EXCO Resources, Inc., or EXCO Resources, its consolidated subsidiaries and EXCO Holdings Inc., or EXCO Holdings, our former parent company, which was acquired by and into which EXCO Holdings II, Inc., or Holdings II, merged in October 2005. On February 14, 2006, EXCO Holdings merged with and into EXCO Resources.

Financial information presented in this annual report includes three separate periods of accounting. Information related to the period beginning January 1, 2003 to July 28, 2003 is referred to as public predecessor and represents the accounting period prior to our going private transaction. For more information about our going private transaction, see "—Significant transactions during 2003 and 2004." The period beginning July 29, 2003 to December 31, 2003, the year ended December 31, 2004 and the period beginning January 1, 2005 to October 2, 2005 is referred to as the private predecessor. The private predecessor period represents the accounting period following the going private transaction up to the Equity Buyout. For more information about the Equity Buyout, see "—Significant transactions during 2005 and 2006." The period beginning October 3, 2005 and ending December 31, 2005 is referred to as successor.

All reserve and other non-financial operating data described as being presented on a pro forma basis excludes data relating to our former Canadian subsidiary, Addison Energy Inc., or Addison, that we sold in February 2005, but includes data relating to ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C., collectively ONEOK Energy, acquired in September 2005 by TXOK, which became our wholly-owned subsidiary on February 14, 2006. For a description of these and other significant events involving EXCO, see "—Significant transactions during 2005 and 2006." We have provided definitions for some of the oil and natural gas industry terms used in this annual report in the "Glossary of selected oil and natural gas terms" beginning on page 24.

Our business strategy

We plan to achieve reserve, production, and cash flow growth by executing our strategy as highlighted below:

•: Exploit our multi-year, development inventory

We have a multi-year inventory of development drilling locations and exploitation projects. This inventory consists of step-out drilling, infill drilling, workovers, and recompletions. From

January 1, 2003 to December 31, 2005, we have drilled 226 wells and completed 217 wells resulting in a 96% drilling success rate. We have identified over 2,000 drilling locations and exploitation projects across our properties on a pro forma basis.

•: Seek acquisitions that meet our strategic and financial objectives

We maintain a disciplined acquisition process to seek and acquire properties that have established production histories and value enhancement potential through development drilling and exploitation projects. Our January 2004 acquisition of North Coast in the Appalachian Basin and the acquisition of TXOK in the East Texas and the Mid-Continent areas are examples of this strategy.
•: Actively manage our portfolio and associated costs

We regularly review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of properties with higher operating costs and properties that are not within our core geographic operating areas. We also seek to opportunistically divest properties in areas in which acquisitions and investment economics no longer meet our objectives, most notably evidenced by the sale of our Canadian operations for $443.3 million in February 2005.
•: Maintain financial flexibility

We employ the use of debt along with a comprehensive commodity price risk management program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure.

Our strengths

We have a number of strengths that we believe will help us successfully execute our strategy.

•

Experienced management team with significant employee ownership

Our management team has led both public and private oil and natural gas companies over the past 20 years and has an average of over 26 years of industry experience in acquiring, developing, and exploiting oil and natural gas properties. Our management team first purchased a significant ownership interest in us in December 1997, and since then we have achieved substantial growth in reserves and production. Since the beginning of 1998, we have increased our Proved Reserves from 4.7 Bcfe to 668.3 Bcfe on a pro forma basis, and our average daily production increased from less than 1 Mmcfe per day in 1997 to 117.1 Mmcfe per day in December 2005, on a pro forma basis. Importantly, as of March 15, 2006, our management team and employees (excluding our outside directors) own approximately 12.4% of our fully-diluted capital stock, which aligns their objectives with those of our shareholders.

•

High quality asset base in attractive regions

We own and plan to maintain a geographically diversified reserve base. Our principal operations are in the Appalachia, East Texas, Mid-Continent, Permian, and Rockies areas. Our properties are generally characterized by:

•: long reserve lives;
•: a multi-year inventory of development drilling and exploitation projects;
•: high drilling success rates; and
•: a high natural gas concentration.

•: Operational control

We operate a significant portion of our properties, which permits us to manage our operating costs and better control capital expenditures as well as the timing of development and exploitation activities. As of December 31, 2005, we were the operator of wells which represented 88% of our pro forma Proved Reserves.

Significant transactions during 2003 and 2004

Going private transaction. On July 29, 2003, EXCO Resources consummated a going private transaction pursuant to which it became a wholly-owned subsidiary of EXCO Holdings. Prior to July 29, 2003, EXCO Resources had registered equity securities that were publicly traded on the NASDAQ National Market. Prior to the going private transaction, EXCO Holdings had no assets, liabilities or operations other than those nominal to its formation. Accordingly, EXCO Resources was deemed the predecessor entity to EXCO Holdings through July 28, 2003.

North Coast acquisition. On January 27, 2004, we acquired North Coast Energy, Inc. (North Coast) for a purchase price of $225.1 million, including the assumption of $57.1 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, 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 positioned us to benefit from the attractive qualities of the basin and to capitalize on consolidation opportunities in the area.

On January 20, 2004, we issued $350.0 million principal amount of our 7¹/4% senior notes, or senior notes, due January 15, 2011 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. Approximately $168.3 million of the proceeds of the issuance of the senior notes was used to finance the acquisition of outstanding common stock, options and warrants of North Coast along with associated fees and expenses. Of the remaining proceeds, $113.8 million was used to repay a portion of our debt under our U.S. credit agreement, North Coast's credit facility indebtedness and accrued interest and fees, $50.1 million was used to repay in full principal and interest on our senior term loan, approximately $10.6 million was used to pay fees and costs associated with the offering, with the remainder, approximately $7.2 million, available for general working capital purposes.

On April 13, 2004, we issued an additional $100.0 million principal amount of our senior notes pursuant to Rule 144A at a price of 103.25% of the principal amount having the same terms and governed by the same indenture as the senior notes issued on January 20, 2004. Of the total proceeds of $103.3 million, approximately $98.8 million was used to repay substantially all of our outstanding indebtedness under our Canadian credit agreement, approximately $1.2 million was used for fees and expenses associated with the offering, with the remainder, approximately $3.3 million, available for general working capital purposes.

Significant transactions during 2005 and 2006

Sale of Addison. On February 10, 2005, we sold Addison, our former wholly-owned subsidiary through which all of our Canadian operations were conducted, for an aggregate purchase price of Cdn. $551.3 million ($443.3 million). Of this amount, Cdn. $90.1 million ($72.1 million) was used to repay in full all outstanding balances under Addison's credit facility, while Cdn. $56.2 million ($45.2 million) was withheld and was remitted to the Canadian government for estimated income taxes resulting from the sale of the stock. Prior to the sale of Addison, on February 9, 2005, Addison made an earnings and profits dividend (as calculated under U.S. tax law) to us in an amount of Cdn. $74.5 million ($59.6 million). The dividend was subject to Canadian tax withholding of Cdn. $3.7 million

($3.0 million). See "Note 3. Sale of Addison Energy Inc." of the notes to the consolidated financial statements for additional information.

TXOK acquisition. On September 16, 2005, Holdings II formed TXOK for the purpose of acquiring ONEOK Energy. Prior to TXOK's acquisition of ONEOK Energy, we owned all of the issued and outstanding common stock of TXOK and BP EXCO Holdings LP, an entity controlled by Mr. Boone Pickens, one of our directors, held all of the outstanding shares of TXOK preferred stock. On September 27, 2005, TXOK completed the acquisition of ONEOK Energy for an aggregate purchase price of approximately $642.9 million, or $634.8 million after contractual adjustments. Effective upon closing, ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C. became wholly-owned subsidiaries of TXOK. We purchased an additional $20.0 million of common stock of TXOK on October 7, 2005, which investment represented an 11% equity interest and a 10% voting interest in TXOK. The preferred stock of TXOK held by BP EXCO Holdings LP represented the remaining 89% equity interest and 90% voting interest of TXOK.

TXOK funded the acquisition of ONEOK Energy with (i) $20.0 million in private debt financing, $15.0 million of which was provided by Mr. Boone Pickens, one of our directors, which has since been repaid; (ii) the issuance of $150.0 million of the 15% Series A Convertible Preferred Stock of TXOK, or the TXOK preferred stock, to BP EXCO Holdings LP, an entity controlled by Mr. Pickens; (iii) approximately $308.8 million of borrowings under the revolving credit facility of TXOK, or the TXOK credit facility; and (iv) $200.0 million of borrowings under the second lien term loan facility of TXOK, or the TXOK term loan.

On February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights of TXOK. The redemption price for the TXOK preferred stock was (a) cash in the amount of approximately $163.4 million and (b) 388,889 shares of common stock of EXCO Resources. Once the TXOK preferred stock was redeemed, our acquisition of TXOK, or the TXOK acquisition, was complete and it became our wholly-owned subsidiary. The properties TXOK acquired in the TXOK acquisition included 1,057 gross (453.1 net) producing oil and natural gas wells in Texas and Oklahoma at December 31, 2005. TXOK has Proved Reserves, estimated as of December 31, 2005, of approximately 223.7 Bcfe of oil and natural gas, and 151 miles of natural gas gathering lines. The acquired properties produced an average of 970 Bbls of oil per day and 46.9 Mmcf of natural gas per day during 2005. For more information about the TXOK acquisition, see "Item 13. Certain relationships and related transactions—TXOK acquisition."

Equity Buyout. On October 3, 2005, Holdings II, an entity formed by our management, purchased 100% of the outstanding equity securities of EXCO Holdings in an equity buyout, or Equity Buyout, for an aggregate price of approximately $699.3 million, resulting in a change of control and a new basis of accounting. To fund the Equity Buyout, Holdings II raised $350.0 million in interim debt financing, including $0.7 million for working capital, from a group of lenders and $183.1 million of equity financing from new institutional and other investors as well as stockholders of EXCO Holdings. In addition, current management and other stockholders of EXCO Holdings exchanged $166.9 million of their EXCO Holdings common stock for Holdings II common stock. EXCO Holdings' majority stockholder sold all of its EXCO Holdings common stock for cash. Promptly following the completion of the Equity Buyout, Holdings II merged with and into EXCO Holdings. As a result of the merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of EXCO Holdings common stock and all shares of EXCO Holdings common stock held by Holdings II were cancelled. For more information about the Equity Buyout, see "Item 13. Certain relationships and related transactions—Equity Buyout."

Following completion of the Equity Buyout, Stephen F. Smith became our Vice Chairman, President and Secretary and Harold L. Hickey became our Vice President and Chief Operating Officer. See "Item 10. Directors and executive officers of the registrant."

Repurchase of senior notes pursuant to a change of control tender offer. In connection with the Equity Buyout, we were required to offer to repurchase our senior notes for a purchase price of 101%. As a result, we repurchased $5.3 million principal amount of senior notes on December 13, 2005.

Initial public offering. On February 14, 2006, EXCO Resources completed its initial public offering, or IPO, of 50,000,000 shares of its common stock for aggregate net proceeds to EXCO Resources of $617.5 million after underwriters' discount. J.P. Morgan Securities Inc., Bear, Stearns & Co. Inc. and Goldman, Sachs & Co. acted as joint book running managers for the IPO.

The net proceeds from the IPO, together with cash on hand and additional borrowings under EXCO's credit agreement, were used as follows:

•: $359.8 million to repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred in connection with the Equity Buyout;
•: $163.4 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends and redemption premium, issued to a related party in connection with the acquisition of ONEOK Energy;
•: $375.5 million to repay $171.8 million in principal plus accrued and unpaid interest of $0.9 million under the TXOK credit facility ($137.0 remained outstanding under this facility following the IPO) and $200.0 million in principal plus accrued and unpaid interest of $2.8 million under the TXOK term loan, both loans having been incurred in connection with the acquisition of ONEOK Energy; and
•: $4.4 million to pay fees and expenses in connection with the IPO.

Concurrent with the consummation of the IPO, including the redemption of the TXOK preferred stock, EXCO Holdings merged with and into EXCO Resources, with EXCO Resources as the surviving corporation. The outstanding shares of EXCO Holdings common stock were cancelled as a result of the merger and such shares were exchanged for the same number of shares of EXCO Resources common stock. As a result of the merger, TXOK became a wholly-owned subsidiary of EXCO Resources and TXOK and its subsidiaries became guarantors under the indenture governing our senior notes. EXCO Resources also became a guarantor under the TXOK credit facility and TXOK likewise became a guarantor under EXCO Resources' credit agreement.

On February 21, 2006, EXCO Resources issued 3,615,200 additional shares of its common stock pursuant to an exercise by the underwriters of their over-allotment option for net proceeds to EXCO Resources of approximately $44.7 million. The net proceeds were used to reduce outstanding indebtedness under EXCO Resources' credit agreement.

Summary of geographic areas of operation

The following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2005 on a pro forma basis:

Areas		Total proved reserves (Bcfe)(1)	PV-10 (in millions) (1)(2)		Average December daily net production (Mmcfe/d)	Reserve life (years)(8)
Appalachia		281.0	$	967.7	39.0	19.7
East Texas(3)		162.3		594.5	35.4	12.6
Mid-Continent(3)		115.2		477.4	27.0	11.7
Permian		57.9		156.0	7.5	21.2
Rockies		46.8		122.9	6.7	19.1
Other		5.1		14.8	1.5	9.3

	Total	668.3	$	2,333.3	117.1	15.6

Areas		Identified drilling locations(4)	Identified exploitation projects(5)	Total gross acreage	Total net acreage(6)
Appalachia		1,089	123	664,450	626,628
East Texas(7)		260	169	56,509	31,841
Mid-Continent(7)		187	188	179,065	105,150
Permian		80	32	47,755	27,395
Rockies		53	65	56,440	29,978
Other		5	8	7,543	4,055

	Total	1,674	585	1,011,762	825,047

(1): The total Proved Reserves and PV-10 of the Proved Reserves as used in this table were prepared by Lee Keeling and Associates. The Proved Reserves and PV-10 for each area were determined by our internal engineers.
(2): The PV-10 data used in this table is based on December 31, 2005 NYMEX spot prices of $11.23 per Mmbtu for natural gas and $61.04 per Bbl for oil, in each case adjusted for historical differentials between NYMEX and local prices. Market prices for oil and natural gas are volatile. See "Item 1A. Risk factors—Risks relating to our business." We believe that PV-10 before income taxes, while not a financial measure 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 because the tax characteristics of comparable companies can differ materially. The total Standardized Measure for our Proved Reserves as of December 31, 2005 was $1.6 billion on a pro forma basis. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with SFAS 69. The amount of estimated future abandonment costs, the PV-10 of these costs and the Standardized Measure were determined by us.

The following table provides a reconciliation of our PV-10 to our Standardized Measure as of December 31, 2005 on a pro forma basis:

(in millions)
PV-10	$	2,333.3
Future income taxes		(1,703.8	)
Discount of future income taxes at 10% per annum		991.6

Standardized Measure	$	1,621.1

(3): The table above includes the following information for TXOK:

Areas		Total Proved Reserves (Bcfe)	PV-10 (in millions)		Average December daily net production (Mmcfe/d)	Reserve Life (years)(8)
East Texas		127.2	$	481.3	26.2	13.3
Mid-Continent		96.5		427.3	25.0	10.6

	Total	223.7	$	908.6	51.2	12.0

(4): Identified drilling locations represent total gross drilling locations identified and scheduled by our management as an estimation of our multi-year drilling activities on existing acreage. Of the total locations shown in the table, 756 are classified as proved. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See "Item 1A. Risk factors—Risks relating to our business."
(5): Identified exploitation projects represent total gross exploitation projects, such as workovers, recompletions, and other non-drilling activities, identified and scheduled by our management as an estimation of our multi-year exploitation projects on existing acreage. Of the total exploitation projects shown in the table, 284 are classified as proved. Our actual exploitation projects may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, and other factors. See "Item 1A. Risk factors—Risks relating to our business."
(6): Includes 33,529, 38,411 and 46,629 net acres with leases expiring in 2006, 2007 and 2008, respectively.
(7): The table above includes the following information for TXOK:

Areas		Identified drilling locations	Identified exploitation projects	Total gross acreage	Total net acreage
East Texas		173	166	48,292	25,230
Mid-Continent		178	160	135,204	79,766

	Total	351	326	183,496	104,996

(8): For purposes of this table, the reserve life is calculated by dividing the Proved Reserves (on a Mmcfe basis) at the end of the period by the daily production volumes for the month then ended, which production volume is annualized by multiplying by 365.

Our development and exploitation project areas

Appalachia

The Appalachian Basin includes portions of the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee, and covers an area of over 185,000 square miles. It is the most mature oil and natural gas producing region in the United States, first establishing oil production in 1859. The Appalachian Basin is strategically located near high energy demand areas with limited supply. As a result, the natural gas from the area typically commands a higher well head price relative to other North American areas.

Although the Appalachian Basin has sedimentary formations indicating the potential for deposits of oil and natural gas reserves up to depths of 30,000 feet or more, most production in this area has been derived from relatively shallow, low porosity and permeability sand and shale formations at depths of 1,000 to 6,000 feet. Operations in the area are generally characterized by long reserve lives, high drilling success rates and a large number of low productivity wells in these shallow formations. In the Appalachian Basin, there are more than 200,000 producing wells and 3,100 operators, with most being relatively small, private enterprises. Our operations in the area primarily include development drilling on our existing acreage, as well as the acquisition of properties with established production and growth opportunities. We believe that the number of wells and operators presents a significant consolidation opportunity.

Central Pennsylvania Area

The Central Pennsylvania Area stretches across six counties in central Pennsylvania. At December 31, 2005, we had Proved Reserves of 74.6 Bcfe and 852 gross producing wells. We operate 100% of our Proved Reserves in this area. Production is primarily from the Upper Devonian, Venango, Bradford, and Elk formations at depths from 1,800 to 4,600 feet. We currently plan to drill 84 wells during 2006.

Ravenswood Area

The Ravenswood Area is located in the western portion of West Virginia. At December 31, 2005, we had Proved Reserves of 46.7 Bcfe and 587 gross producing wells. We operate 98% of our Proved Reserves in this area. Production in the Ravenswood area is primarily from the Mississippian and Devonian formations at depths of 2,500 to 4,400 feet. We currently plan to drill eight wells during 2006.

Maben Area

The Maben Area is located in southwest West Virginia. At December 31, 2005, we had Proved Reserves of 34.5 Bcfe and 316 gross producing wells. We operate 100% of our Proved Reserves in this area. In Maben, we produce from the Mississippian and Devonian formations at depths ranging from 1,500 to 5,500 feet. Our drilling activity targets seven separate shallow formations, with a typical well completed in two or more horizons. We currently plan to drill six wells during 2006.

Adamsville Area

The Adamsville Area is located in south central Ohio. At December 31, 2005, we had Proved Reserves of 11.6 Bcfe and 342 gross producing wells. We operate 99% of our Proved Reserves in this area. Adamsville produces from the Clinton reservoir and the Knox series at depths from 3,000 to 6,300 feet. We currently plan to drill five wells during 2006.

Jamestown Area

The Jamestown Area is located in western Pennsylvania. At December 31, 2005, we had Proved Reserves of 17.3 Bcfe. We operate 123 gross producing wells which represent 100% of our Proved Reserves in the area. Production is primarily from the Medina Sandstone formation at depths of 4,500 to 5,100 feet. We currently plan to drill 31 wells during 2006.

East Texas

The East Texas area is a part of the Cotton Valley Sand trend, which covers parts of the East Texas Basin and the Northern Louisiana Salt Basin. The TXOK acquisition significantly enhanced our position in this area. We are targeting tight sand reservoirs along the Cotton Valley Sand trend at depths of 6,500 to 12,000 feet. Operations in the area are generally characterized by long-lived reserves, high drilling success rates and wells with relatively high initial production rates. Due to the tight nature of the reservoirs, development programs in the area are mostly focused on infill development drilling. Many areas have been down spaced to 80-acres per well, with some areas having economically established 40 acre spacing.

Cotton Valley Area

Within our Cotton Valley Area, we are active in Rusk, Upshur and Gregg Counties in Texas primarily across four fields—Oak Hill, Minden, Glenwood and White Oak. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 161.4 Bcfe and 467 gross producing wells. We operate 97% of our pro forma Proved Reserves in this area. We are focused on developing the Lower Cotton Valley (Taylor) and Upper Cotton Valley sands at depths of 10,400 to 11,000 feet, the Pettit Lime at depths of 7,000 to 8,500 feet and Travis Peak Sands at depths of 7,800 to 9,000 feet. Our natural gas is gathered through our own gathering lines in these fields. On a pro forma basis we currently plan to drill 44 wells during 2006.

Mid-Continent

Our Mid-Continent area includes parts of Oklahoma, southwestern Kansas and the Texas Panhandle. The major properties in the Mid-Continent area were acquired in the TXOK acquisition and are located in the Anadarko Shelf and Anadarko Basin of Oklahoma. The Mid-Continent area is characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than in our other operating areas. Similar to our other operating areas, the Mid-Continent area contains a number of fields with long production histories. We also recognize the potential for additional attractive acquisition opportunities, as this area contains a number of smaller operators seeking liquidity opportunities and some larger companies seeking to divest non-core assets.

Mocane-Laverne Field

Our Mocane-Laverne Field, which was acquired in the TXOK acquisition, is located in Beaver, Harper and Ellis Counties of Oklahoma. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 46.3 Bcfe and we had 479 gross producing wells. We operate 77% of our pro forma Proved Reserves. At Mocane-Laverne, we are targeting eight productive formations at depths from 2,500 to 9,000 feet. On a pro forma basis we currently plan to drill 24 wells during 2006.

Cement Field

Our Cement Field, which was acquired in the TXOK acquisition, is located in Caddo and Grady Counties of Oklahoma. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 25.5 Bcfe and we had 131 gross producing wells, all operated by others. Production in the Cement field is primarily from multi-pay Pennsylvanian formations at depths of 4,500 to 18,000 feet. On a pro forma basis we currently plan to participate in the drilling of 17 wells during 2006.

Chitwood Field

Our Chitwood Field, which was acquired in the TXOK acquisition, is near our Cement Field in Grady County, Oklahoma. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 24.7 Bcfe and we had 50 gross producing wells. We operate 65% of our pro forma Proved Reserves. At

Chitwood, we are targeting four productive formations at depths of 15,000 to 17,600 feet. On a pro forma basis we currently plan to drill seven wells during 2006.

Permian

The Permian Basin is located in West Texas and the adjoining area of southeastern New Mexico. Though the Permian Basin is better known as a mature oil focused basin exploited with waterflood and other enhanced oil recovery techniques, our activities are focused on conventional gas properties. With the use of 3-D seismic, we are targeting prolific natural gas reservoirs with potential for multi-pay horizons. The properties are characterized by long reserve lives and low operating costs.

Vinegarone Field

Our Vinegarone Field is located in Val Verde County, Texas. At December 31, 2005, we had Proved Reserves of 29.6 Bcfe and 26 gross producing wells. We operate 99% of the Proved Reserves in the field. Production in the Vinegarone field is primarily from the Pennsylvanian Strawn formation at depths of 10,000 to 10,500 feet. We currently plan to drill three wells during 2006.

Gomez Field

Our Gomez Field is located in Pecos County, Texas. At December 31, 2005, we had Proved Reserves of 10.5 Bcfe and 12 gross producing wells, all operated by others. At Gomez, we are primarily targeting the Ellenberger, Devonian, Wolfcamp and Atoka formations at depths of from 15,000 to 22,000 feet. We currently plan to participate in the drilling of three wells during 2006.

Rockies

The Rockies is a well known oil and natural gas province which encompasses several oil and natural gas basins. Our activities are currently focused on the Wattenberg Field of the Denver-Julesberg Basin of northeastern Colorado. Though the Wattenberg Field has been under extensive development since the early 1970s, improvements in fracturing technology have enhanced recoveries from these tight sand reservoirs and supported continued active development of the field. Operations in the area are generally characterized by high drilling success rates and low cost wells with significant potential for refracs.

Wattenberg Field

The Wattenberg Field encompasses more than 1,000 square miles, between 20 and 55 miles northeast of Denver, Colorado. At December 31, 2005, we had Proved Reserves of 36.3 Bcfe and 125 gross producing wells. Our activities at Wattenberg are focused on a portion of the field in which the primary productive reservoirs are in the Codell and Niobrara formations and in selected deeper "J" Sand formations. These formations cover large areas of the field and are found at depths of approximately 6,500 to 8,500 feet. We currently plan to drill 10 wells and perform exploitation operations on eight wells during 2006.

Our oil, natural gas and NGL reserves

The following tables summarize historical information regarding Proved Reserves at December 31, 2003, 2004 and 2005 and historical and pro forma information at December 31, 2005 and exclude

information with respect to Canada as a result of the sale of Addison in February 2005. The historical information was prepared in accordance with the rules and regulations of the SEC.

		At December 31,				At December 31, 2005(2)
		2003		2004		EXCO		TXOK		Pro forma
Oil (Mmbbls)
	Developed		7.8		6.0		5.5		3.1		8.6
	Undeveloped		2.7		1.2		1.3		1.1		2.4

	Total		10.5		7.2		6.8		4.2		11.0

Natural gas (Bcf)
	Developed		124.0		318.2		324.4		164.2		488.6
	Undeveloped		32.2		43.2		79.4		34.3		113.7

	Total		156.2		361.4		403.8		198.5		602.3

Natural Gas Liquids (Mmbbls)
	Developed		0.7		0.2		—		—		—
	Undeveloped		0.1		—		—		—		—

	Total		0.8		0.2		—		—		—

	Total equivalent reserves (Bcfe)		224.0		405.8		444.6		223.7		668.3

Pre-tax Present Value, discounted at 10% (PV-10) (in millions)(1)
	Developed	$	274.2	$	640.9	$	1,183.5	$	742.7	$	1,926.2
	Undeveloped		69.5		57.0		241.2		165.9		407.1

	Total	$	343.7	$	697.9	$	1,424.7	$	908.6	$	2,333.3

Standardized Measure (in millions)		$	234.1	$	473.4	$	930.3	$	690.8	$	1,621.1

(1): The PV-10 data does not include the effects of income taxes or commodity price risk management activities, and is based on the following NYMEX spot prices, in each case adjusted for historical differentials between NYMEX and local prices.

	NYMEX spot price
Date	Natural gas (per Mmbtu)		Oil (per Bbl)
December 31, 2003	$	6.19	$	32.52
December 31, 2004		6.15		43.45
December 31, 2005		11.23		61.04

(2): Beginning with December 31, 2005 reserves, NGL's are not considered a material component of our reserves, and are no longer tracked as a separate category.

We believe that PV-10 before income taxes, while not a financial measure 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 because the tax characteristics of comparable companies can differ materially. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is

calculated in accordance with SFAS No. 69. The following table provides a reconciliation of our PV-10 to our Standardized Measure:

	At December 31,						At December 31, 2005
(in millions)	At December 31,						At December 31, 2005
(in millions)	2003			2004			EXCO			TXOK			Pro forma
PV-10	$	343.7		$	697.9		$	1,424.7		$	908.6		$	2,333.3
Future income taxes		(254.7	)		(582.5	)		(1,282.5	)		(421.3	)		(1,703.8	)
Discount of future income taxes at 10% per annum		145.1			358.0			788.1			203.5			991.6

Standardized Measure	$	234.1		$	473.4		$	930.3		$	690.8		$	1,621.1

The total reserve estimates presented as of December 31, 2003, 2004 and 2005 have been prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The estimate of our PV-10 and Standardized Measure is based upon our estimate of future abandonment costs and the report on our 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, capital expenditures, production and ad valorem 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 "Note 20. Supplemental information relating to oil and natural gas producing activities—continuing operations (unaudited)" of the notes to the consolidated financial statements for additional information regarding our oil, natural gas and NGL reserves, and our Standardized Measure.

Our production, prices and expenses

The following tables summarize for the periods indicated, 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 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 209 day period from January 1, 2003 to July 28, 2003 as shown on the consolidated statements of

operations have been reduced by $14.5 million for cash settlements paid on hedges. These tables exclude information with respect to Canada as a result of the sale of Addison in February 2005.

		Public predecessor		Private predecessor
(in thousands, except production and per unit amounts)		For the 209 day period from January 1, 2003 to July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003
Sales:
Oil:
	Revenue(1)	$	13,874	$	8,477
	Production sold (Mbbl)		461		294
	Average sales price per Bbl(1)	$	30.08	$	28.83
Natural Gas:
	Revenue	$	21,300	$	12,751
	Production sold (Mmcf)		4,424		3,127
	Average sales price per Mcf(1)	$	4.81	$	4.08
Natural gas liquids:
	Revenue(1)	$	803	$	539
	Production sold (Mbbl)		35		24
	Average sales price per Bbl	$	22.77	$	22.29
Costs and Expenses:
	Average production cost per Mcfe	$	1.54	$	1.46
	General and administrative expense per Mcfe	$	1.53	$	0.76
	Depreciation, depletion and amortization per Mcfe	$	0.69	$	1.07

		Private predecessor
		Year ended December 31, 2004
(in thousands, except production and per unit amounts)		US (excluding Appalachia)		Appalachia(2)
Sales:
Oil:
	Revenue(1)	$	20,966	$	3,728
	Production sold (Mbbl)		538		100
	Average Sales price per Bbl(1)	$	38.97	$	37.28
Natural Gas:
	Revenue(1)	$	44,193	$	71,262
	Production sold (Mmcf)		8,355		10,505
	Average Sales price per Mcf(1)	$	5.29	$	6.78
Natural Gas Liquids:
	Revenue(1)	$	1,844		—
	Production sold (Mbbl)		60		—
	Average Sales price per Bbl (1)	$	30.73		—
Costs and Expenses:
Average production cost per Mcfe		$	1.41	$	1.02
General and administrative expense per Mcfe		$	0.96	$	0.35
Depreciation, depletion and amortization per Mcfe		$	1.17	$	1.31

		Private predecessor						Successor
		for the 275 day period ended October 2, 2005						for the 90 day period ended December 31, 2005
(in thousands, except production and per unit amounts)		US (excluding Appalachia)		Appalachia		Total		US (excluding Appalachia)		Appalachia		Total
Sales:
Oil:
	Revenue(1)	$	15,100	$	4,428	$	19,528	$	4,875	$	1,791	$	6,666
	Production sold (Mbbl)		290		85		375		85		31		116
	Average Sales price per Bbl(1)	$	52.07	$	52.09	$	52.07	$	57.35	$	57.77	$	57.47
Natural Gas:
	Revenue(1)	$	39,523	$	73,217	$	112,740	$	18,294	$	45,000	$	63,294
	Production sold (Mmcf)		6,339		9,043		15,382		1,947		3,153		5,100
	Average Sales price per Mcf(1)	$	6.23	$	8.10	$	7.33	$	9.40	$	14.27	$	12.41
Natural Gas Liquids:
	Revenue(1)	$	553	$	—	$	553	$	101	$	—	$	101
	Production sold (Mbbl)		18		—		18		2		—		2
	Average Sales price per Bbl(1)	$	30.72	$	—	$	30.72	$	50.50	$	—	$	50.50
Costs and Expenses:
Average production cost per Mcfe		$	1.39	$	1.13	$	1.25	$	1.85	$	1.31	$	1.54
General and administrative expense per Mcfe(3)		$	9.68	$	1.06	$	5.04	$	1.96	$	0.42	$	1.07
Depreciation, depletion and amortization per Mcfe		$	1.39	$	1.40	$	1.39	$	2.30	$	2.51	$	2.42

(1): Excludes the effects of derivative cash settlements and commodity price risk management activities.
(2): The data presented for Appalachia only reflect revenues, production, costs and expenses since the date of our acquisition of North Coast on January 27, 2004.
(3): General and administrative expense for the 275 day period from January 1, 2005 to October 2, 2005 includes $73.7 million of non-recurring bonus expense and non-cash stock-based compensation in connection with the Equity Buyout—See "Significant transactions during 2005 and 2006." Excluding these non-recurring items, the general and administrative expense would be $0.88 per Mcfe for the 275 day period from January 1, 2005 to October 2, 2005.

Our interest in productive wells

The following table quantifies as of the dates indicated information regarding 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 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. This table excludes information with respect to Canada as a result of the sale of Addison in February 2005. The information is presented on a pro forma basis.

		Pro forma at December 31, 2005
		Gross wells(1)			Net wells
Areas		Gross wells(1)			Net wells
Areas		Oil	Gas	Total	Oil	Gas	Total
Appalachia		408	4,289	4,697	403.4	3,916.5	4,319.9
East Texas(2)		15	456	471	13.1	275.2	288.3
Mid-Continent(2)		210	630	840	86.9	231.7	318.6
Permian		106	119	225	12.5	73.3	85.8
Rockies		67	140	207	35.0	125.2	160.2
Other		21	7	28	11.9	4.4	16.3

	Total	827	5,641	6,468	562.8	4,626.3	5,189.1

(1): As of December 31, 2005 on a pro forma basis, we owned interests in five gross wells with multiple completions.
(2): The pro forma information at December 31, 2005 above includes the following information for TXOK, which owns interests in four gross wells with multiple completions:

		Gross wells			Net wells
Areas		Gross wells			Net wells
Areas		Oil	Gas	Total	Oil	Gas	Total
East Texas		5	392	397	3.2	216.4	219.6
Mid-Continent		96	564	660	39.2	194.3	233.5

	Total	101	956	1,057	42.4	410.7	453.1

As of December 31, 2005 on a pro forma basis, we were the operator of 5,556 gross (4,969.2 net) wells, which represented approximately 88% of our pro forma Proved Reserves as of December 31, 2005.

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.

The following tables summarize 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. These tables exclude information with respect to

Canada as a result of the sale of Addison in February 2005. The information for the year ended December 31, 2005 is presented on an actual basis and therefore excludes TXOK's drilling activities.

		Development wells
		Gross			Net
		Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2003
	Total	12	3	15	8.9	1.3	10.2

Year ended December 31, 2004
	U.S. (excluding Appalachia)	20	2	22	15.4	1.3	16.7
	Appalachia	71	—	71	70.0	—	70.0

	Total	91	2	93	85.4	1.3	86.7

Year ended December 31, 2005
	U.S. (excluding Appalachia)	19	1	20	18.4	0.5	18.9
	Appalachia	85	1	86	82.7	1.0	83.7

	Total	104	2	106	101.1	1.5	102.6

		Exploratory wells
		Gross			Net
		Productive	Dry	Total	Productive	Dry	Total
Year ended December 31, 2003
	Total	—	—	—	—	—	—

Year ended December 31, 2004
	U.S. (excluding Appalachia)	—	—	—	—	—	—
	Appalachia	6	1	7	6.0	1.0	7.0

	Total	6	1	7	6.0	1.0	7.0

Year ended December 31, 2005
	U.S. (excluding Appalachia)	—	—	—	—	—	—
	Appalachia	4	1	5	2.7	0.2	2.9

	Total	4	1	5	2.7	0.2	2.9

The drilling activities in the United States referenced in the above table were primarily conducted in Texas, New Mexico, Louisiana, Colorado, Kansas, Ohio, Pennsylvania and West Virginia. As of December 31, 2005, we owned a 100% working interest in one well being drilled in Pennsylvania, one well in Texas, two wells in Colorado and a 50% working interest in one well being drilled in West Virginia. In addition, we had 100% working interest in two wells in Texas, six wells in Pennsylvania, one well with a 50% working interest in West Virginia and one well with a 25% working interest in Tennessee in the process of being completed. As of February 28, 2006, we owned a 100% working interest in two wells being drilled in Pennsylvania, 100% working interest in one well being drilled in Ohio, and 100% working interest in one well being drilled in West Virginia. In addition, we had three 100% working interest wells being completed in Texas and one 98.7% working interest well being completed in Colorado.

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 our developed and undeveloped acreage on a pro forma basis, at December 31, 2005 and excludes Canada as a result of the sale of Addison in February 2005:

		Pro forma at December 31, 2005
		Developed acreage		Undeveloped acreage
Areas		Developed acreage		Undeveloped acreage
Areas		Gross	Net	Gross	Net
Appalachia		349,848	329,343	314,602	297,285
East Texas(1)		51,659	29,364	4,850	2,477
Mid-Continent(1)		155,674	90,621	23,391	14,529
Permian		39,116	22,228	8,639	5,167
Rockies		42,096	23,077	14,344	6,901
Gulf Coast		6,070	3,420	1,473	635

	Total	644,463	498,053	367,299	326,994

(1): The pro forma information at December 31, 2005 above includes the following information for TXOK:

		Developed acreage		Undeveloped acreage
Areas		Developed acreage		Undeveloped acreage
Areas		Gross	Net	Gross	Net
East Texas		44,617	23,360	3,675	1,870
Mid-Continent		117,096	69,111	18,108	10,655

	Total	161,713	92,471	21,783	12,525

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. In Appalachia, we have 33,360, 28,485 and 42,747 net acres with leases expiring in 2006, 2007 and 2008, respectively. Leases expiring over the next three years in the other geographic areas are immaterial.

The undeveloped "held by production" acreage in many cases represents potential additional drilling opportunities through down spacing and drilling of proved undeveloped and unproved 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.

Sales of producing properties and undeveloped acreage

We regularly review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of properties with higher operating costs and properties that are not within our core geographic operating areas. We also seek to opportunistically divest properties in areas in which acquisitions and investment economics no longer meet our objectives, most notably evidenced by the sale of our Canadian operations for $443.3 million. During 2004, we received proceeds of $51.9 million from the sale of properties in the United States. During the year ended December 31, 2005, we received proceeds of $45.3 million from the sale of properties in the United States.

Our principal customers

Western Gas Resources accounted for approximately 10.0% of total revenues for the same 209 day period. For the 156 day period from July 29, 2003 to December 31, 2003, sales to ONEOK Gas Marketing, Inc., Plains All American, Inc., and Western Gas Resources accounted for 10.0%, 13.2%, and 12.7% of total revenues, respectively.

Competition

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. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.

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 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, or 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.

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, or BLM, or Minerals Management Service 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, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, or the 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 amends the HLPSA in several important respects. The Pipeline Safety Act requires the Research and Special Programs Administration of DOT, or the RSPA, 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. The Research and Special Program Improvements Act of 2004, or RSPIA, further amends the HLPSA, and transfers the authority of the RSPA to the newly-formed Pipeline and Hazardous Materials Safety Administration of DOT, or the PHMSA. In October 2005, the PHMSA proposed new regulations regarding the definition of, and safety standards for, gas gathering pipelines, which propose to establish a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We do not yet know whether new regulations might arise out of this rulemaking process will impose new or additional requirements on our pipelines. If so, we could incur significant expenses.

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.

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, or OPA;
•: the Clean Water Act, or CWA;
•: the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA;
•: the Resource Conservation and Recovery Act, or RCRA;
•: the Clean Air Act, or CAA; and

•: the Safe Drinking Water Act, or 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 regulation 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, or 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 cost of such action. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third party disposal facilities where wastes from operations were sent. Although CERCLA, as amended, currently exempts petroleum (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. 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 of 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 forgo 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 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.

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 current environmental laws and regulations. As these laws and regulations are frequently changed and are subject to interpretation, our assessment regarding the cost of compliance or the extent of liability risks may change in the future. 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, or 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.

Title to our properties

When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local mineral records. We do conduct title investigations and, in most cases, obtain a title opinion of local counsel before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

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 agreement.

Our employees

As of December 31, 2005, we employed 314 persons of which 145 were involved in field operations and 169 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.

Forward-looking statements

This annual report contains 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. 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 commodity price risk management 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 annual report, including, but not limited to:

•: fluctuations in prices of oil and natural gas;
•: future capital requirements and availability of financing;
•: estimates of reserves;
•: geological concentration of our reserves;
•: risks associated with drilling and operating wells;
•: 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;
•: competition;
•: general economic conditions;
•: governmental regulations;
•: receipt of amounts owed to us by purchasers of our production and counterparties to our commodity price risk management contracts;
•: hedging decisions, including 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; and

•: fluctuations in interest rates.

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, you should keep in mind the risk factors and other cautionary statements in this annual report. The risk factors noted in this annual report and other factors noted throughout this annual report provide examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. Please see "Item 1A. Risk factors" for a discussion of certain risks of our business and an investment in our common stock.

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.

Mmbbl. One million stock tank barrels.

Mmbtu. One million British thermal units.

Mmcf. One million cubic feet of natural gas.

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

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

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, without giving effect to commodity price risk management activities, 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 a financial measure 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 because the tax characteristics of comparable companies can differ materially.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units

can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. An operation within an existing well bore to make the well produce oil and/or gas from a different, separately producible zone other than the zone from which the well had been producing.

Reserve Life. The estimated productive life, in years, 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 Mmcfe 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 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.

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Workovers. Operations on a producing well to restore or increase production.

Available Information

We make our filings with the SEC available on our website atwww.excoresources.com.

ITEM 1A. 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 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.

Risks relating to our business

Fluctuations in oil and natural gas prices, which have been volatile at times, may adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or future indebtedness and obtain additional capital on attractive terms.

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. We are particularly dependent on prices for natural gas. As of December 31, 2005, 90% of our pro forma Proved Reserves were 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. 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;
•: political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
•: the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•: 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 revenues and our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms depend substantially upon oil and natural gas prices.

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 expose us to the risk of financial loss and may limit our ability to benefit from increases in oil and natural gas prices in some circumstances, including the following:

•: the counterparty to the commodity price risk management contract may default on its contractual obligations to us;
•: there may be 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 and the value of our common stock, and making it more difficult for us to pay dividends on our common stock. During the years ended December 31, 2004 and 2005, we made cash settlement payments on our commodity price risk management contracts totaling $26.1 million and $85.0 million, respectively. As of December 31, 2005, a $1 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments for the year ended December 31, 2005 of approximately $14.4 million. As of December 31, 2005, the net unrealized loss on our commodity price risk management contracts was $134.6 million. During 2005, we terminated 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. In connection with the TXOK acquisition, we assumed additional commodity price risk management contracts that TXOK had entered into covering a significant portion of its estimated future production. We may continue to incur significant unrealized losses in the future from our commodity price risk management activities to the extent market prices continue to increase and our derivatives contracts remain in place. See "Item 7. Management's discussion and analysis of financial condition and results of operations—Our liquidity, capital resources and capital commitments—Commodity price risk management activities."

We will face risks associated with the TXOK acquisition relating to difficulties in integrating operations, potential disruptions of operations, and related negative impact on earnings.

The TXOK acquisition represents a significant increase in our reserves and production. The TXOK acquisition is the largest acquisition that we have completed to date. The Proved Reserves in the TXOK acquisition represent approximately 33.5% of our pro forma Proved Reserves as of December 31, 2005. In addition, on a pro forma basis as of December 31, 2005, we added 1,057 gross (453.1 net) wells to our consolidated portfolio of wells, including approximately 525 gross operated wells, which materially increased the number of wells we currently operate. All of these factors present significant integration challenges for us. In addition to the other general acquisition risks described elsewhere in this section, the magnitude of the TXOK acquisition could strain our managerial, financial, accounting, technical, operational and administrative resources, disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards as well as our internal controls and procedures. In addition, since we will acquire only one field office in connection with the TXOK acquisition, we may be unable to open field or other offices on terms acceptable to us required to accommodate the employees we hired in connection with the TXOK acquisition. We may not be successful in overcoming these risks or any other problems encountered in connection with the TXOK acquisition, all of which could negatively impact our results of operations and our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.

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 and attractiveness 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 be unable to locate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.

We may not identify all risks associated with the acquisition of oil and natural gas properties, which may result in unexpected liabilities and costs to us.

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, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and other similar factors. Ordinarily, our review efforts are focused on the higher-valued properties. For example, in both the North Coast and TXOK acquisitions we did not review title or production data for, or physically inspect, every well we acquired. Even a detailed review of 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. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity. The indemnifications we received in the North Coast and TXOK acquisitions are subject to floors and caps and do not cover all these types of risks. In addition, the entity from which we acquired North Coast is a foreign entity. As a result, we may face difficulties or incur additional expenses in enforcing a judgment obtained in a U.S. court against such entity for any breach of its obligations to provide indemnity to us.

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 agreement, it may be difficult for us in the foreseeable future to obtain debt 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 and, therefore, unable to implement our growth strategy.

We may not be successful in managing our growth, which could adversely affect our operations and net revenues.

The pursuit of additional acquisitions is a key part of our strategy. We face challenges in growing our managerial, financial, accounting, technical, operational and administrative resources to keep up with the pace of the growth of our business and our significant corporate transactions such as the Equity Buyout and our IPO. For example, our rapid growth and significant transactions over the past two years have strained, and could continue to strain, our financial, tax and accounting staff. The North Coast and TXOK acquisitions substantially increased the size and scope of our business from an operational, personnel, financial reporting and accounting perspective. Our growth could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards as well as internal controls and procedures. 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, as well as adversely affect our ability to satisfy our

disclosure and other obligations. We may also be unable to successfully integrate acquired oil and natural gas properties into our operations or achieve desired profitability.

If we are unable to successfully address the material weakness in our internal control over financial reporting, or any other control deficiencies, our ability to report our financial results on a timely and accurate basis and to comply with disclosure and other requirements may be adversely affected.

We are not currently required to comply with Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make an assessment of the effectiveness of our internal control over financial reporting for that purpose. However, in connection with the 2004 and the 2005 audits of the financial statements of EXCO Resources, we reported a material weakness in Item 9A of our annual report on Form 10-K.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Our management has concluded that as of December 31, 2005, we did not maintain effective controls over the preparation and review of the quarterly and annual tax provision and the related financial statement presentation and disclosure of income tax matters. Specifically, our controls were not adequate to ensure the completeness and accuracy of the tax provision and the deferred tax balances, including the timing and classification of recording the tax impact of an extraordinary dividend. This control deficiency resulted in the restatement of our consolidated financial statements for the quarters ended June 30, 2005 and September 30, 2005 and audit adjustments to the consolidated financial statements for the years ended December 31, 2004 and 2005, affecting income tax expense and the deferred tax liability accounts. Additionally, this control deficiency could result in a misstatement in the aforementioned tax accounts that would result in a material misstatement to the annual or interim financial statements that would not be prevented or detected. Accordingly, management has concluded that this deficiency in internal control over financial reporting is a material weakness.

In 2005 and through the date of this annual report, we implemented additional controls including more stringent reviews of the quarterly tax provision, hired additional finance and accounting personnel and expanded the scope of work of the outside consulting firm that we use to review our quarterly and annual tax provision. However, in a recent evaluation carried out under the supervision and with the participation of our senior management, our Chief Executive Officer and Chief Financial Officer, who is also our Chief Accounting Officer, concluded that our disclosure controls and procedures continued to be ineffective as of December 31, 2005 as a result of the material weakness identified as of December 31, 2004.

In connection with the preparation of our quarterly report on Form 10-Q for the third quarter ended September 30, 2005, we reconsidered our position with respect to technical correction notices from the IRS related to the tax provision made on an extraordinary dividend received from our former wholly-owned Canadian subsidiary. Accordingly, we restated our financial statements for the quarter ended June 30, 2005 and September 30, 2005, to reflect the tax benefit in the earlier quarter and to classify the benefit as a component of continuing rather than discontinued operations in the September 30, 2005 quarter. We also reclassified a Canadian tax benefit resulting from a tax rate change in the three and six month periods ended June 30, 2004 and the nine months ended September 30, 2004 from discontinued to continuing operations. In view of these restatements, we continue to evaluate the effectiveness of our processes, procedures and controls, with continued emphasis on accounting for income taxes.

In connection with their audit as of December 31, 2004, our independent registered public accounting firm made recommendations to our management concerning adding additional accounting staff and implementing an internal audit function. Deficiencies in these areas may have contributed to accounting adjustments made in our financial statements and could, in the future, contribute to

accounting adjustments. Accordingly, we have hired a new controller, added other finance and accounting personnel and are finalizing the implementation of an internal audit function to be conducted, under our supervision, by an outside consulting firm.

We will continue to monitor the effectiveness of these and other processes, procedures and controls and will make any further changes management determines appropriate, including to effect compliance with Section 404 of the Sarbanes-Oxley Act of 2002 when we are required to make an assessment of internal control over financial reporting under Section 404 for fiscal 2007. The steps we have taken and will take in the future may not remediate the material weakness. In addition, we may identify additional material weaknesses or other deficiencies in our internal control over financial reporting in the future.

Any material weaknesses or other deficiencies in our internal control over financial reporting may affect our ability to comply with SEC reporting requirements and NYSE listing standards or cause our financial statements to contain material misstatements, which could negatively affect the market price and trading liquidity of our common stock, cause investors to lose confidence in our reported financial information, as well as subject us to civil or criminal investigations and penalties.

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

While we have taken actions designed to address 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, such as growth of the company or increased transaction volume, 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.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

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. We experienced production curtailments in the Appalachian Basin during 2004 and 2005 resulting from capacity restraints and short term shutdowns of certain pipelines for maintenance purposes. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas 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 impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our common stock and our ability to pay dividends on our company stock.

There are risks associated with our drilling activity that could impact the results of our operations.

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. Additionally, seismic technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The costs of drilling and completing wells are 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. We have experienced some delays in contracting for drilling rigs and increasing costs to drill wells. All of these risks could adversely affect our results of operations and financial condition.

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

Our future success will depend on the success of our acquisition, development, and exploitation activities. Our decisions to purchase, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained 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. Our estimates regarding the increase in our reserves and production resulting from the TXOK acquisition may prove to be incorrect, which could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

We cannot control the development of the properties we own but do not operate, which may adversely affect our production, revenues and results of operations.

As of December 31, 2005, on a pro forma basis, third parties operate wells that represent approximately 12% 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;
•: 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 or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, which may adversely affect our production, revenues and results of operations.

Our estimates of oil, natural gas and NGL reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves and our financial condition.

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 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, the amount of PV-10 described in this annual report, and our financial condition. In addition, our reserves or PV-10 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. Similarly, a decline in market prices for oil or natural gas may adversely affect our PV-10. Any of these negative effects on our reserves or PV-10 may decrease the value of our common stock.

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

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).

We have in the past experienced some of these events during our drilling operations. 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

may not continue to be available at commercially acceptable premium levels or at all. Due to cost considerations, from time to time we have declined to obtain coverage for certain drilling activities and have therefore been restricted from conducting these types of drilling activities during the period we were uninsured. 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 adversely impact our results of operations and cash flow.

Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.

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 substantially 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.

We may have write-downs of our asset values, which could negatively affect our results of operations and net worth.

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 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. We have in the past experienced ceiling test writedowns with respect to our oil and natural gas properties. Future non-cash ceiling test write-downs would negatively affect our results of operations and net worth.

We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting units, as defined, exceeds the fair value of those reporting units, an impairment charge will occur, which would negatively impact our 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. 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. 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.

We may experience a temporary decline in revenues if we lose one of our significant customers.

For the year ended December 31, 2005, sales of natural gas to an industrial customer accounted for 10.1% of our total oil and natural gas revenues. For the year ended December 31, 2004, one customer, Alliance Energy Services L.L.C., a wholly owned subsidiary of Constellation Energy Group, Inc., accounted for 10.6% of our total oil and natural gas revenues. In 2004, our top eight customers, including Alliance, accounted for approximately 39.2% of our total oil and natural gas revenues. The Alliance contract expired at the end of 2004. Beginning in January 1, 2005, we entered into a new agreement with Alcan Corporation and its subsidiary, Alcan Rolled Products-Ravenswood, LLC, the entity for whom Alliance had acted as purchasing agent. To the extent Alcan or any other significant customer reduces the volume of its natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas.

Competition in our industry is intense and we may be unable to compete in acquiring properties, contracting for drilling equipment and hiring experienced personnel.

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 has also been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We are often outbid by competitors in our attempts to acquire properties or companies. All of these challenges could make it more difficult to execute our growth strategy and increase our costs.

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.

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.

As of March 28, 2006, we had approximately $548.7 million of indebtedness, including $104.0 million of indebtedness which is subject to variable interest rates. Our total interest expense on an annual basis would be $38.3 million and would change by approximately $1.0 million for every 1% change in interest rates.

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 indebtedness, 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;
•: 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;
•: 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 be unable 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 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, 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 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 incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. The restrictions in our debt agreements on our incurrence of additional indebtedness 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. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially increase.

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 loans under our credit agreement, 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 in an amount sufficient to enable us to pay our indebtedness, including our senior notes and loans under our credit agreement, 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 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, 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 agreement 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 agreement 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 be unable 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 agreement 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 agreement and our senior notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit agreement and our senior notes. The accelerated debt would become immediately due and payable. If that should occur, we may be unable 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.

Risks relating to our common stock

Our stock price may fluctuate significantly.

Our common stock began trading on the New York Stock Exchange on February 9, 2006. An active trading market may not develop or be sustained. The market price of our common stock could fluctuate significantly as a result of:

•: actual or anticipated quarterly variations in our operating results;
•: changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;
•: announcements relating to our business or the business of our competitors;
•: conditions generally affecting the oil and natural gas industry;
•: the success of our operating strategy; and
•: the operating and stock price performance of other comparable companies.

Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common stock. In addition, the stock markets in general can experience considerable price and volume fluctuations.

Future sales of our common stock may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market after the IPO, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock.

As of March 15, 2006, we have 104,004,089 shares of common stock outstanding. Of these shares, 53,615,200 shares are freely tradable, unless any of these shares are held by our affiliates.

Many of our stockholders, including our executive officers and directors, are subject to agreements that limit their ability to sell our common stock held by them. These holders cannot sell or otherwise dispose of any shares of our common stock, subject to limited exceptions, for a period of at least 180 days after February 8, 2006 without the prior written approval of J.P. Morgan Securities Inc., which could, in its sole discretion, elect to permit resale of shares by these holders, including their affiliates, prior to the lapse of the 180 day period.

On October 3, 2005, we entered into a registration rights agreement with all of the holders of our common stock, which agreement was amended by the First Amended and Restated Registration Rights Agreement. A total of 50,388,889 shares of common stock is covered by this agreement. Any holder who is a party to this agreement has the right, commencing 180 days after completion of the IPO, to require us to register for resale up to one-third of its shares of common stock. All other parties to the registration rights agreement would then have the right to require us to register for resale up to one-third of their shares of common stock on the same registration statement. The same rights would exist commencing 365 days and 540 days after completion of the IPO for an additional one-third of their shares at each such anniversary. Following the IPO, these time and volume restrictions on resale registrations may be waived by J.P. Morgan Securities Inc. based on its evaluation of market and other conditions. In addition, at any time that we file a registration statement registering other shares, the holders of shares subject to the registration rights agreement can require that we include their shares in

such registration statement, subject to certain exceptions. The filing of any resale registration statement and the sale of shares thereunder may have a material adverse effect on the market price of our common stock.

The equity trading markets may be volatile, which could result in losses for our shareholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.

Our articles of incorporation permit us to issue preferred stock that may restrict a takeover attempt that you may favor.

Our articles of incorporation permit our board to issue up to 10,000,000 shares of preferred stock and to establish, by resolution, one or more series of preferred stock and the powers, designations, preferences and participating, optional or other special rights of each series of preferred stock. The preferred stock may be issued on terms that are unfavorable to the holders of our common stock, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our liquidation and the designation of conversion rights that entitle holders of our preferred stock to convert their shares into our common stock on terms that are dilutive to holders of our common stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult.

We have not paid dividends in the past and do not expect to pay dividends in the future, and any return on investment may be limited to the value of our stock.

We have never paid cash dividends on our common stock and do not anticipate paying cash dividends on our common stock in the foreseeable future. The payment of dividends will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant. If we do not pay dividends, our stock may be less valuable because a return on your investment will only occur if our stock price appreciates. In addition, our credit agreement and indenture governing our senior notes restrict the payment of dividends.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

Corporate offices

We lease approximately 33,500 square feet of office space in Dallas, Texas, for our corporate offices. On February 27, 2006 we amended this lease effective July 1, 2006 to obtain additional square footage and extend the expiration date from June 30, 2011 to June 30, 2013. The lease requires monthly rental payments of approximately $48,300. We lease an office in Akron, Ohio. The Akron office contains approximately 11,100 square feet and requires monthly rental payments of approximately $15,500. The Akron office lease expires December 15, 2012. We also have small offices for technical and field operations in Texas, Oklahoma, Colorado, Nebraska, Ohio and West Virginia. TXOK has entered into a lease agreement effective March 1, 2006, for approximately 22,700 square feet of office space in Tulsa, Oklahoma. The lease expires May 31, 2011, and requires monthly rental payments of approximately $24,500.

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

None.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market information for our common stock

Prior to February 14, 2006, we were 100% owned by EXCO Holdings. Effective February 9, 2006, our common stock began trading on a "when issued" basis on the New York Stock Exchange under the symbol "XCO". The closing price for our common stock was $12.00 on March 23, 2006.

Our shareholders

According to our transfer agent, Continental Stock Transfer & Trust Company, there were approximately 129 holders of record of our common stock on March 15, 2006 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders).

Our dividend policy

We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreement currently prohibits us from paying dividends on our common stock and the indenture governing our senior notes contains restrictions on our payment of dividends. Even if our credit agreement permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

Our equity compensation plan information

See "Item 12. Security ownership of certain beneficial owners and management and related stockholder matters—Equity compensation plan information" for a discussion of our equity compensation plans.

Use of proceeds from IPO

On February 8, 2006, our Registration Statement on Form S-1 (Registration No. 333-129935), as amended, was declared effective under the Securities Act. This Registration Statement registered the issuance and sale of shares of EXCO's common stock at a proposed maximum offering price of $825.0 million. On February 14, 2006, EXCO Resources completed its IPO of 50,000,000 shares of its common stock at $13.00 per share for aggregate net proceeds to EXCO Resources of $617.5 million, after underwriters' discount. J.P. Morgan Securities Inc., Bear, Stearns & Co. Inc. and Goldman, Sachs & Co. acted as joint book running managers for the IPO.

The net proceeds from the IPO, together with cash on hand and additional borrowings under EXCO's credit agreement, were used as follows:

•: $359.8 million to repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred in connection with the Equity Buyout;
•: $163.4 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends and redemption premium, issued to a related party in connection with the acquisition of ONEOK Energy;
•: $375.5 million to repay $171.8 million in principal plus accrued and unpaid interest of $0.9 million under the TXOK credit facility ($123.0 million remained outstanding under this

facility as of March 15, 2006) and $200.0 million in principal plus accrued and unpaid interest of $2.8 million under the TXOK term loan, both loans having been incurred in connection with the acquisition of ONEOK Energy; and

•: $4.4 million to pay fees and expenses in connection with the IPO.

Set forth below is a table indicating the sources and uses of funds in connection with the IPO:

Sources		Uses
(in millions)		Repay interim bank loan plus accrued interest		Redeem TXOK preferred stock plus dividends and redemption premium		Repay a portion of the TXOK credit facility including accrued interest		Repay TXOK term loan plus accrued interest		Fees and expenses		Total
Proceeds of the IPO after underwriting discounts and commissions		$	359.8	$	163.4	$	94.3	$	—	$	—	$	617.5
Cash			—		—		78.4		150.0		—		228.4
Our credit agreement			—		—		—		52.8		4.4		57.2

	Total	$	359.8	$	163.4	$	172.7	$	202.8	$	4.4	$	903.1

Since all of the net proceeds of the IPO were used to repay indebtedness and redeem the TXOK preferred stock, we did not have any net proceeds remaining to further expand or invest in our business or for other general corporate purposes.

EXCO Resources also granted the underwriters an option, exercisable for 30 days from February 8, 2006, to purchase an aggregate of 7,500,000 additional shares of common stock at the IPO price. On February 21, 2006, EXCO Resources issued 3,615,200 additional shares of its common stock at $13.00 per share pursuant to an exercise by the underwriters of their over-allotment option for net proceeds to EXCO Resources, after underwriters' discount, of approximately $44.7 million. The net proceeds were used to reduce outstanding indebtedness under EXCO Resources' credit agreement.

Expenses related to the IPO included an underwriting discount of approximately $34.8 million and other expenses of approximately $4.4 million.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected historical financial and operating data. You should read this financial data in conjunction with our "Management's discussion and analysis of financial condition and results of operation", our Consolidated Financial Statements, the notes to our Consolidated Financial Statements and the other financial information, included in this annual report. This information does not replace the Consolidated Financial Statements. We have completed numerous acquisitions and dispositions since 2001 that materially impact the comparability of this data between periods.

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

								Public predecessor			Private predecessor
(In thousands, except per share amounts)		2001			2002			209 day period from January 1 to July 28, 2003			156 day period from July 29 to December 31, 2003
Statement of Operations Data(1):
Revenues and other income:
	Oil and natural gas	$	53,017		$	34,287		$	22,403		$	21,767
	Commodity price risk management activities(2)		—			—			—			(10,800	)
	Other		5,541			6,599			(1,129	)		(161	)
	Gain on disposition of properties, equipment and other assets		136			—			—			—

	Total revenues and other income		58,694			40,886			21,274			10,806

Costs and expenses:
	Oil and natural gas production		21,394			19,018			11,380			7,331
	Depreciation, depletion and amortization		9,744			9,031			5,125			5,413
	Accretion of discount on asset retirement obligations(3)		—			—			320			205
	General and administrative		4,136			6,777			11,347			3,823
	Non-cash stock based compensation expense		—			—			—			—
	Equity buyout compensation expense		—			—			—			—
	Interest expense		2,660			1,191			1,058			1,921
	Impairment of oil and natural gas properties		28,646			—			—			—
	Impairment of marketable securities		—			1,136			—			—
	Uncollectible value of Enron hedges		10,669			—			—			—

	Total costs and expenses		77,249			37,153			29,230			18,693

Income (loss) before income taxes			(18,555	)		3,733			(7,956	)		(7,887	)
Income tax expense (benefit)			(54	)		(2,672	)		(181	)		(7,764	)

Income (loss) before discontinued operations and change in accounting principle			(18,501	)		6,405			(7,775	)		(123	)

Discontinued operations:
	Income (loss) from operations		(20,846	)		(11,382	)		13,534			6,217
	Gain on disposition of Addison Energy Inc		—			—			—			—
	Income tax expense (benefit)		—			(4,010	)		4,982			1,917

Income (loss) from discontinued operations:			(20,846	)		(7,372	)		8,552			4,300

Income (loss) before change in accounting principle			(39,347	)		(967	)		777			4,177
Cumulative effect of change in accounting principle, net of income tax			—			—			255			—

Net income (loss)			(39,347	)		(967	)		1,032			4,177
Dividends on preferred stock			2,653			5,256			2,620			—

Earnings (loss) on common stock		$	(42,000	)	$	(6,223	)	$	(1,588	)	$	4,177

Basic earnings (loss) per share from continuing operations		$	(3.00	)	$	0.16		$	(1.25	)

Basic loss per share—total		$	(5.96	)	$	(0.88	)	$	(0.19	)

Diluted earnings (loss) per share from continuing operations		$	(3.00	)	$	0.09		$	(1.25	)

Diluted loss per share—total		$	(5.96	)	$	(0.88	)	$	(0.19	)

Weighted average common and common equivalent shares outstanding:
	Basic		7,046			7,061			8,084
							��
	Diluted		7,046			12,533			8,084

Statement of Cash Flow Data:(2)
Net cash provided by (used in):
	Operating activities	$	25,916		$	31,660		$	20,418		$	21,720
	Investing activities		(133,771	)		(76,937	)		(23,520	)		(38,528	)
	Financing activities		102,130			45,928			9,982			14,964
Balance Sheet Data:(2)
	Current assets	$	21,121		$	26,198			n/a		$	31,569
	Total assets		191,056			241,174			n/a			505,030
	Current liabilities		13,322			33,193			n/a			45,188
	Long-term debt, less current maturities		44,994			97,943			n/a			—
	Shareholder's equity		120,379			99,894			n/a			183,869
	Total liabilities and shareholder's equity		191,056			241,174			n/a			505,030

(1): We have completed numerous acquisitions and dispositions since January 1, 2001 that materially impact the comparability of this data between periods.

(2): Commencing with the date of the going private transaction, we no longer account for derivative financial instruments using hedge accounting. Accordingly, any change in fair value is now recognized directly through the statement of operations. See "Item 7. Management's discussion and analysis of financial condition and results of operation—Critical accounting policies—Accounting for derivatives" for a description of this accounting method.
(3): We adopted SFAS 143, "Accounting for asset retirement obligations" on January 1, 2003. See "Summary of significant accounting policies—Deferred abandonment and asset retirement obligations" in the notes to our consolidated financial statements included in this annual report.

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (Continued)

					Private Predecessor			Successor
(In thousands, except per share amounts)		2004			275 day period from January 1 to October 2, 2005			90 day period from October 3, to December 31, 2005
Statement of Operations Data(1):
Revenues and other income:
	Oil and natural gas	$	141,993		$	132,821		$	70,061
	Commodity price risk management activities(1)		(50,343	)		(177,253	)		(256	)
	Other		1,141			7,075			2,365
	Gain on disposition of properties, equipment and other assets		—			—			—

	Total revenues and other income		92,791			(37,357	)		72,170

Costs and expenses:
	Oil and natural gas production		28,256			22,157			8,949
	Depreciation, depletion and amortization		28,519			24,687			14,071
	Accretion of discount on asset retirement obligations(3)		800			617			226
	General and administrative		15,275			15,628			4,018
	Non-cash stock based compensation expense		—			44,092			2,207
	Equity buyout compensation expense		—			29,624			—
	Interest expense		34,570			26,675			19,414

	Total costs and expenses		107,420			163,480			48,885

Income (loss) before income taxes			(14,629	)		(200,837	)		23,285
Income tax expense (benefit)			5,126			(63,698	)		7,321
Income (loss) before discontinued operations and change in accounting principle			(19,755	)		(137,139	)		15,964
Discontinued operations:
	Income (loss) from operations		36,274			(4,403	)		—
	Gain on disposition of Addison Energy, Inc.		—			175,717			—
	Income tax expense (benefit)		10,358			49,282			—

Income (loss) from discontinued operations:			25,916			122,032			—

Net income (loss)		$	6,161		$	(15,107	)	$	15,964

Statement of Cash Flow Data:(2)
Net cash provided by (used in):
	Operating activities	$	118,633		$	(81,020	)	$	7,740
	Investing activities		(381,325	)		338,089			(13,600	)
	Financing activities		283,452			(47,346	)		(5,280	)
Balance Sheet Data:(2)
	Current assets	$	75,848			n/a		$	340,506
	Total assets		922,052			n/a			1,507,637
	Current liabilities		105,695			n/a			471,380
	Long-term debt, less current maturities		487,453			n/a			461,802
	Shareholder's equity		203,751			n/a			342,681
	Total liabilities and shareholder's equity		922,023			n/a			1,507,637

(1): We have completed numerous acquisitions and dispositions since January 1, 2001 that materially impact the comparability of this data between periods.

(2): Commencing with the date of the going private transaction, we no longer account for derivative financial instruments using hedge accounting. Accordingly, any change in fair value is now recognized directly through the statement of operations. See "Item 7. Management's discussion and analysis of financial condition and results of operation—Critical accounting policies—Accounting for derivatives" for a description of this accounting method.
(3): We adopted SFAS 143, "Accounting for asset retirement obligations" on January 1, 2003. See "Summary of significant accounting policies—Deferred abandonment and asset retirement obligations" in the notes to our consolidated financial statements included in this annual report.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this annual report. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results and timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under "Risk factors" and elsewhere in this annual report.

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. We expect to continue to grow by leveraging our management team's experience, exploiting our multi-year inventory of development drilling locations and exploitation projects, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive commodity price risk management program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. For the three year period ended December 31, 2004, we spent in excess of $342.2 million on property and corporate acquisitions, excluding acquisitions in Canada. We spent an additional $103.2 million on property acquisitions during 2005.

As oil and natural gas prices have increased, we have seen an increase in demand for drilling rigs, field supplies and other related field services. This has resulted in increases in the costs of these goods and services and some difficulty in timely scheduling of drilling rigs and other field services required to perform operations on our properties. To date, however, we have not encountered any significant operational problems or delays as a result of the difficulty in scheduling these services. Also, the higher sales prices for oil and natural gas have more than offset the higher field costs. Given the inherent volatility of oil and natural gas prices, we plan our activities and budget based on conservative sales price assumptions, which are generally lower than the average sales prices currently being received, as well as conservative assumptions as to expected oil and natural gas production volumes. We have budgeted approximately $159.1 million in 2006, including TXOK capital projects, for our drilling, exploitation and operational expenditures. We have also budgeted approximately $7.0 million in 2006 for our additional corporate and acquisition-related expenditures and approximately $1.6 million for information technology expenditures. Our future earnings and cash flows are dependent upon our ability to manage our overall cost structure to a level that allows for profitable production.

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 develop and identify additional reserves and by acquisitions. Our future growth will depend upon our ability to continue to add oil and natural gas reserves in excess of production at a reasonable cost. We will maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

We also face the challenge of financing future acquisitions. Following completion of our IPO in February 2006, we amended our revolving credit agreement with our banking syndicate. The amended credit facility provides for a borrowing base of $750.0 million. At this point, we believe we will have adequate unused borrowing capacity under our revised credit agreement, in addition to cash flow from operations, to fund capital development and working capital needs for the next 12 months. Funding for future acquisitions may require additional sources of financing, which may not be available.

On July 29, 2003, we completed a "going private" transaction that resulted in all of our outstanding common stock being acquired by 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 for a purchase price of approximately $225.1 million, including the assumption of $57.1 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, 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 positioned 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, purchased all of the issued and outstanding shares of common stock of Addison and two intercompany notes that Addison owed to one of our subsidiaries, Taurus Acquisition, Inc. (now known as ROJO Pipeline, Inc., or ROJO). The aggregate purchase price was Cdn. $551.3 million ($443.3 million) after adjustments as specified in the purchase agreement.

On August 12, 2005, our management formed a new entity, Holdings II, to consummate a purchase of all of the shares of capital stock of EXCO Holdings, our parent company at that time. On October 3, 2005, Holdings II purchased 100% of the outstanding equity of EXCO Holdings for an aggregate purchase price of approximately $699.3 million, which resulted in a change of control at EXCO Holdings and a change in its board of directors. To fund this purchase, Holdings II incurred $350.0 million in indebtedness, including $0.7 million for working capital, under an interim bank loan and raised $183.1 million of equity financing from institutional and other investors. Current management and other stockholders of EXCO Holdings, who had an option to take cash or equity in Holdings II, exchanged EXCO Holdings capital stock for $166.9 million of Holdings II common stock. Promptly following the completion of these transactions, Holdings II merged with and into EXCO Holdings. See "Item 1. Business—Significant transactions during 2005 and 2006" for additional information.

On September 27, 2005, TXOK, a wholly-owned subsidiary of Holdings II, our former parent company, acquired all of the issued and outstanding equity interests of ONEOK Energy for a purchase price of $634.8 million after contractual adjustments. On February 14, 2006, upon closing of our IPO, we acquired TXOK by redeeming its preferred stock and assuming its debt. The acquisition will be accounted for using the purchase method of accounting in accordance with SFAS No. 141 "Accounting for Business Combinations." We are in the process of determining the fair value of the assets and liabilities of TXOK at this time. The TXOK acquisition significantly increased our multi-year inventory of development drilling locations and exploitation projects, and strengthened our position in the East Texas and Mid-Continent areas.

On February 14, 2006, EXCO Resources completed its IPO of 50,000,000 shares of its common stock for aggregate net proceeds to EXCO Resources of $617.5 million, after underwriters' discount. J.P. Morgan Securities Inc., Bear, Stearns & Co. Inc. and Goldman, Sachs & Co. acted as joint book running managers for the IPO.

The net proceeds from the IPO, together with cash on hand and additional borrowings under EXCO's credit agreement, were used as follows:

•: $359.8 million to repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred in connection with the Equity Buyout;

•: $163.4 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends and redemption premium, issued to a related party in connection with the acquisition of ONEOK Energy;
•: $375.5 million to repay $171.8 million in principal plus accrued and unpaid interest of $0.9 million under the TXOK credit facility ($123.0 million remained outstanding under this facility as of March 15, 2006) and $200.0 million in principal plus accrued and unpaid interest of $2.8 million under the TXOK term loan, both loans having been incurred in connection with the acquisition of ONEOK Energy; and
•: $4.4 million to pay fees and expenses in connection with the IPO.

Critical accounting policies

In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified the most critical accounting principles used in the preparation of our consolidated financial statements. We determined the critical principles by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our Proved Reserves, derivatives accounting, functional currency assessment, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.

We prepared our consolidated financial statements for inclusion in this report in accordance with accounting principles that are generally accepted in the United States, or GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Effective July 29, 2003, in connection with our going private transaction, we discontinued hedge accounting for derivative financial instruments. See "—Accounting for derivatives" for a discussion of this change. Upon closing of the Equity Buyout, we adopted SFAS No. 123(R). The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.

Estimates of Proved Reserves

The Proved Reserves data included in this annual report was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

•: the quality and quantity of available data;
•: the interpretation of that data;
•: the accuracy of various mandated economic assumptions; and

•: the judgment of the persons preparing the estimate.

Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

You should not assume that the present value of future net cash flows is the current market value of our estimated Proved Reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from Proved Reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Further, a discount rate of 10% may not be an accurate assumption of future interest rates.

Proved Reserves materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of Proved Reserves may result from lower market prices, and a decline may make it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties for impairment.

Proved Reserves are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Accounting for derivatives

We engage in commodity price risk management activities to protect against commodity price fluctuations and 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 a more predictable cash flow to fund our development and acquisition activities. These derivatives are not held for trading purposes.

Prior to our going private transaction, when we entered into hedging transactions, we formally documented all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. The process included linking all derivatives that were designated as cash flow hedges to forecasted transactions. We also formally assessed, both at the hedge's inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were highly effective in offsetting changes in cash flows of hedged items. When it was determined that a derivative was not highly effective as a hedge or that it ceased to be a highly effective hedge, we discontinued hedge accounting prospectively. Under hedge accounting, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings and the ineffective portion of any change in fair value of a derivative designated as a hedge is immediately recognized in earnings.

Effective July 29, 2003, in connection with our going private transaction, we discontinued hedge accounting for all existing derivatives. Currently, we do not designate derivative transactions as hedges for financial accounting purposes; accordingly, changes in the fair value of derivative financial instruments are recognized currently in our statement of operations. We do continue to designate derivative financial instruments as hedges for income tax purposes.

Assessments of functional currencies

We determine the functional currencies of our subsidiaries by assessing the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. We determined that the Canadian dollar was the functional currency of our international operations in Canada.

By disposing of Addison in February 2005, we no longer have operations in Canada. As a result, we do not anticipate that our assessment of functional currencies will have a significant impact on our results of operations and our financial position going forward.

Share-based payments

Prior to October 3, 2005, we accounted for share-based payments to employees using the intrinsic value method prescribed by APB No. 25, "Accounting for Stock Issued to Employees" and related interpretations. As such, we did not recognize compensation expense associated with employee stock options, as the options were granted at fair market value on the date of grant. Holdings II adopted the provisions of SFAS No. 123(R) upon its formation in August 2005. As a result of the Equity Buyout, we currently follow SFAS No. 123(R). At December 31, 2005, our employees and directors held options under the EXCO Holdings 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 4,973,073 shares of EXCO Holdings common stock at $7.50 per share. The options expire ten years from the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of grant. The adoption of SFAS No. 123(R) resulted in non-cash compensation of $3.2 million, of which $2.2 million is included in general and administrative expense and $1.0 million was capitalized as part of proved developed oil and natural gas properties. We elected to use the Black-Scholes model to calculate the fair value of

issued options. The gross fair value of the options using the Black-Scholes model for the October 5, 2005 awards was $11.4 million, or $2.29 per share. Based on historical data, we estimate that approximately $0.7 million of this fair value will be forfeited. Therefore, a total of $10.7 million of share-based compensation is required to be recognized, of which $2.2 million was expensed in 2005 with the remaining $7.5 million being recognized over the next 33 months.

For the 275 day period ended October 2, 2005, a non-recurring $44.1 million share-based compensation expense was recognized as a result of the Equity Buyout. This compensation charge was attributable to the Class B common shares of EXCO Holdings purchased by Holdings II. See "—Our results of operations, 2005 compared with 2004."

Accounting for oil and natural gas properties

The accounting for and disclosure of oil and natural gas producing activities requires that we choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties.

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. Once we incur costs, they are recorded in the full cost pool or in unevaluated properties. Unevaluated property costs are not subject to depletion. We review our unevaluated costs on an ongoing basis, and we expect these costs to be evaluated in one to three years and transferred to the full cost pool during that time. The full cost pool is comprised of lease and well equipment and exploration and development costs incurred plus intangible acquired proved leaseholds.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total amount of Proved Reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs that is attributable to our acquisition, exploration, exploitation and development activities.

To the extent that total capitalized oil and natural gas property costs (net of related deferred income taxes and accumulated depreciation, depletion and amortization) exceed the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects, plus the lower of cost or fair value of unproved properties, excess costs are charged to operations. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date even if oil or natural gas prices increase. We could be required to write down our oil and natural gas properties if there is a decline in oil or natural gas prices, or downward adjustments are made to our Proved Reserves.

In September 2004, the SEC released SAB No. 106 concerning the application of SFAS No. 143 "Accounting for Asset Retirement Obligations" by oil and natural gas producing companies following the full cost method of accounting. In SAB No. 106, the SEC addressed the impact of SFAS No. 143 on the ceiling test calculation and on the calculation of depreciation, depletion and amortization. SAB No. 106 became effective for us on January 1, 2005 and has not had a significant impact on our ceiling test calculation. Also, as a result of SAB No. 106, we now include the estimated asset retirement obligation that will result from future development activity in our calculation of depreciation, depletion and amortization. This change has not had a significant impact on our depreciation, depletion and amortization expense.

Prior to the issuance of SFAS No. 143, we included expected future cash flows related to the asset retirement obligations from certain properties in our ceiling test calculation. Under SFAS No. 143, we must now initially capitalize asset retirement costs by increasing long-lived oil and natural gas assets by the same amount as the asset retirement liability before discount. After adoption of SFAS No. 143, if we were to continue to calculate the full cost ceiling test by reducing expected future net revenues by

the cash flows required to settle the asset obligation, then the effect would be to "double-count" such costs in the ceiling test.

Goodwill

As a result of a change in control, the 2003 going private transaction has been accounted for using the purchase method of accounting pursuant to SFAS No. 141, "Business Combinations". As a result, EXCO Holdings' cost of acquiring EXCO Resources was allocated to the assets and liabilities acquired based upon estimated fair values. Therefore, our financial position and operating results subsequent to July 28, 2003 reflect a new basis of accounting and are not comparable to prior periods. In addition, tax basis was carried over from the formerly public company as a result of the merger. The going private purchase price was allocated to the assets acquired and liabilities assumed according to their estimated fair values. The purchase price allocation resulted in $51.1 million of goodwill being recorded, $24.2 million in our United States geographic operating segment and $26.9 million in the Canadian geographic operating segment. The goodwill amount related to the Canadian geographic operating segment was reclassified to assets of discontinued operations on our consolidated balance sheets at December 31, 2004 and was removed from the consolidated balance sheet during 2005, as a result of the sale of Addison on February 10, 2005. Changes in the balance of goodwill in our U.S. geographic operating segment from the date of the going private transaction to December 31, 2004 were the result of sales of oil and natural gas properties (based upon the relative fair value of our oil and natural gas properties prior to and after the sales) and the sale of a bankruptcy claim related to Enron Corp. In a 2005 letter to oil and natural gas companies, the SEC provided guidance concerning the treatment of goodwill in situations when a company sells less than 25% of its proved oil and natural gas reserves in a cost pool. The guidance indicated that such dispositions may trigger a need to evaluate goodwill for impairment under SFAS No. 142. As a result of this guidance, beginning January 1, 2005, we no longer reduce the balance of goodwill for property dispositions of less than 25% of our oil and natural gas reserves unless there is an indication that our goodwill is impaired as a result of the sale.

As a result of the Equity Buyout on October 3, 2005, which required the application of the purchase method of accounting pursuant to SFAS No. 141, goodwill of $220.0 million was recognized. Approximately $143.8 million was allocated to the Appalachia region operations and $76.2 million to the U.S. (excluding Appalachia) operations. We expect that we will record additional goodwill as a result of our acquisition of TXOK on February 16, 2006.

None of the goodwill is currently deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, "Goodwill and Intangible Assets," goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. There was no goodwill recorded as a result of the North Coast acquisition.

Asset retirement obligations

In June 2001, the Financial Accounting Standards Board, or FASB, issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted the new rules on asset retirement obligations on January 1, 2003. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $5.6 million, recognition of an asset retirement obligation liability of approximately $6.1 million and a cumulative effect of adoption that increased net income and shareholder's equity by approximately $0.3 million.

Accounting for income taxes

Income taxes are accounted for based upon the liability method of accounting in accordance with SFAS No. 109, "Accounting for Income Taxes.". We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. As a result of the Equity Buyout, our book basis of assets increased by approximately $380.3 million, while our tax basis carried over. The result was an increase to our deferred tax liability. Deferred taxes are recorded to reflect the tax benefit and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. Prior to the planned disposition of Addison, we considered Addison's earnings to be permanently reinvested for use in those operations and, consequently, deferred federal income taxes, net of applicable foreign tax credits, had not been provided on the undistributed earnings of Addison that were reinvested. As a result of the sale of Addison, we provided for deferred federal income taxes in the fourth quarter of 2004 on the undistributed earnings of Addison which is reflected as income tax expense of discontinued operations.

Recent accounting pronouncements

On December 16, 2004, FASB issued SFAS No. 123(R), "Share-Based Payment", which is a revision of SFAS No. 123, "Accounting for Stock-Based Compensation". SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows". Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) will require all share-based payments to employees, including grants of employee stock options, to be recognized in our consolidated statements of operations based on their estimated fair values. Pro forma disclosure is no longer an alternative.

Prior to October 3, 2005, we accounted for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. As such, we did not recognize compensation expense associated with employee stock options. Holdings II adopted the provisions of SFAS No. 123(R) upon its formation in August 2005. As a result of the Equity Buyout, we currently follow SFAS No. 123(R). At December 31, 2005, our employees and directors held options under the 2005 Incentive Plan to purchase 4,973,075 shares of EXCO Holdings common stock at $7.50 per share. The options expire ten years from the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of grant. The adoption of SFAS No. 123(R) resulted in non-cash compensation of $3.2 million, of which $2.2 million is included in general and administrative expense and $1.0 million was capitalized as part of proved developed oil and natural gas properties.

On June 1, 2005, the FASB issued FASB Statement No. 154, "Accounting Changes and Error Corrections" (SFAS No. 154), which will require entities that voluntarily make a change in accounting principle to apply that change retrospectively to prior periods' financial statements, unless this would be impracticable. SFAS No. 154 supersedes Accounting Principles Board Opinion No. 20, "Accounting Changes" (APB 20), which previously required that most voluntary changes in accounting principle be recognized by including in the current period's net income the cumulative effect of changing to the new accounting principle. SFAS No. 154 also makes a distinction between "retrospective application" of an accounting principle and the "restatement" of financial statements to reflect the correction of an error.

Another significant change in practice under SFAS No. 154 will be that if an entity changes its method of depreciation, amortization, or depletion for long-lived, nonfinancial assets, the change must be accounted for as a change in accounting estimate. Under APB 20, such a change would have been reported as a change in accounting principle. SFAS No. 154 applies to accounting changes and error corrections that are made in fiscal years beginning after December 15, 2005. Management has not

completed its assessment of the impact of SFAS No. 154, but does not anticipate any material impact from implementation of this accounting standard.

Our results of operations

Due to the application of purchase accounting for the going private transaction in July 2003 and the Equity Buyout in October 2005, our results of operations contain public predecessor, private predecessor and successor operations for those years. Because the application of purchase accounting can inhibit meaningful comparison of historical results before and after such transactions, we analyzed the impact of the going private transaction and the Equity Buyout on our statements of operations. We believe that our results of operations for 2003, 2004 and 2005 are comparable on an annual basis except as it relates to depreciation, depletion and amortization expenses resulting from a change in basis of the underlying properties in 2003 and 2005 and the discontinuation of hedge accounting for derivatives at the going private transaction in 2003. As a result we believe that the non-GAAP measurements for 2003 and 2005, discussed below, provide a more meaningful basis for comparing our results of operations.

The following is a discussion of our financial condition and results of operations for the years ended December 31, 2003, 2004 and 2005. Information presented for the 12 months ended December 31, 2003 represents the non-GAAP combined total for the 209 day period from January 1, 2003 to July 28, 2003 (public predecessor) and the 156 day period from July 29, 2003 to December 31, 2003 (private predecessor). Information presented for the 12 months ended December 31, 2005 represents the non-GAAP combined total for the 275 day period from January 1, 2005 to October 2, 2005 (private predecessor) and the 90 day period from October 3, 2005 to December 31, 2005 (Successor). Separate comparisons for results of operations for 2003 compared to 2004 and 2004 compared to 2005 are provided.

The comparability of our results of operations from year to year is impacted by:

•: the acquisition of North Coast on January 27, 2004;
•: property acquisitions and dispositions;
•: significant changes in the amount of our long-term debt including the issuance of our senior notes on January 20, 2004 in the amount of $350.0 million and on April 13, 2004 in the amount of $103.3 million (including applicable premium);
•: significant fluctuations in oil and gas prices which impact our oil and natural gas revenues and our commodity price risk management activities;
•: the "going private" transaction that occurred on July 29, 2003 and the resulting step-up in basis reflecting the purchase price;
•: the discontinued use of hedge accounting for all derivatives effective July 29, 2003; and
•: the Equity Buyout that occurred on October 3, 2005, the significant amount of debt incurred to finance the Equity Buyout and the resulting step-up in accounting basis.
•: compensation expenses related to the Equity Buyout.

General

The availability of a ready market for oil, natural gas and NGLs and the prices of oil, natural gas and NGLs are dependent upon a number of factors that are beyond our control. These factors include, among other things:

•: the level of domestic production and economic activity generally;
•: the availability of imported oil and natural gas;
•: actions taken by foreign oil producing nations;
•: the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;
•: the cost and availability of other competitive fuels, fluctuating and seasonal demand for oil, natural gas and refined products; and
•: the extent of governmental regulation and taxation (under both present and future legislation) of the production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of the oil, natural gas or NGLs from any producing well in which we have or may acquire an interest.

Marketing arrangements and backlog

We produce oil, natural gas and NGLs. We do not refine or process the oil we produce. With the exception of our Black Lake Field in Louisiana, which we sold in November 2004, we do not process a significant portion of the natural gas or NGLs we produce. At the Black Lake Field, we operated a natural gas processing plant that was 100% dedicated to production from the field.

We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers include utilities, natural gas marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions. We also gather natural gas for other producers for which we are compensated.

During the year ended December 31, 2004, an industrial purchaser, Alliance Energy Services L.L.C. accounted for 10.6% of our total oil and natural gas revenues. Under our end user contract in 2004 with Alliance, the purchaser was obligated to take all of the natural gas we could produce from a specified gathering system of ours up to 10,000 gross Mmbtu per day (which includes natural gas of other interest owners in the affected wells). We were obligated to use commercially reasonable efforts to supply that volume of natural gas from our wells hooked up to the gathering system subject to production declines experienced by the affected wells. The sales were priced monthly at the Columbia Gas Transmission Corp. Appalachia Index plus a specified premium. Our revenues under this contract

in 2004 aggregated $14.7 million. This contract was replaced with a contract with the actual end user, Alcan Rolled Products-Ravenswood, LLC, beginning January 1, 2005 through December 31, 2007. Under the new contract the end user will purchase all of the natural gas we can produce, subject to well production declines, from the specified gathering system up to 10,000 gross Mmbtu per day (which includes natural gas of other interest owners in the affected wells). The contract price is the monthly Columbia Gas Transmission Corp. Appalachia Index plus a specified premium. Our revenues under this contract in 2005 aggregated $20.6 million, or 10.1% of our total oil and natural gas revenues.

We sell our NGLs under both short-term and long-term contracts with specific purchasers for any NGLs that we may produce. We sell the NGLs to refiners and processors in the vicinity of our producing properties. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Typically, the prices we receive for NGLs are based on the Oil Price Information Service, or OPIS, index, less transportation and fractionating fees.

We may be unable to market all the oil, natural gas or NGLs we produce. If our oil, natural gas or NGLs can be marketed, we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil, natural gas and NGLs contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated.

2005 compared with 2004

Revenues and production

The following tables present our oil and natural gas revenues (before commodity price risk management activities), production and average unit sales price for the year ended December 31, 2004, the 275 day predecessor period ended October 2, 2005, the successor period ended December 31, 2005 and the non-GAAP combined totals for the 12 months ended December 31, 2005. The tables also show

the changes in these amounts between periods. The 2004 data presented for Appalachia only reflects revenues and production since the date of our acquisition of North Coast on January 27, 2004.

				Private predecessor				Successor
(in thousands, except production volumes)				Year ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005		For the 90 day period from October 3, 2005 to December 31, 2005		Non-GAAP combined 2005		Year to year change 2004-2005(a)
Oil and natural gas revenues before commodity price risk management activities:
	Oil revenues:
		U.S. (excluding Appalachia)		$	20,966	$	15,100	$	4,875	$	19,975	$	(991	)
		Appalachia			3,728		4,428		1,791		6,219		2,491

			Total	$	24,694	$	19,528	$	6,666	$	26,194	$	1,500

	Natural gas revenues:
		U.S. (excluding Appalachia)		$	44,193	$	39,523	$	18,294	$	57,817	$	13,624
		Appalachia			71,262		73,217		45,000		118,217		46,955

			Total	$	115,455	$	112,740	$	63,294	$	176,034	$	60,579

	Natural gas liquids revenues:
		U.S. (excluding Appalachia)		$	1,844	$	553	$	101	$	654	$	(1,190	)
		Appalachia			—		—		—		—		—

			Total	$	1,844	$	553	$	101	$	654	$	(1,190	)

	Total oil and natural gas revenues:
		U.S. (excluding Appalachia)		$	67,003	$	55,176	$	23,270	$	78,446	$	11,443
		Appalachia			74,990		77,645		46,791		124,436		49,446

			Total	$	141,993	$	132,821	$	70,061	$	202,882	$	60,889

Production:
	Oil (Mbbls):
		U.S. (excluding Appalachia)			538		290		85		375		(163	)
		Appalachia			100		85		31		116		16

			Total		638		375		116		491		(147	)

	Natural gas (Mmcf):
		U.S. (excluding Appalachia)			8,355		6,339		1,947		8,286		(69	)
		Appalachia			10,505		9,043		3,153		12,196		1,691

			Total		18,860		15,382		5,100		20,482		1,622

	Natural gas liquids (Mbbls):
		U.S. (excluding Appalachia)			60		18		2		20		(40	)
		Appalachia			—		—		—		—		—

			Total		60		18		2		20		(40	)

	Total production (Mmcfe):
		U.S. (excluding Appalachia)			11,943		8,187		2,469		10,656		(1,287	)
		Appalachia			11,105		9,553		3,339		12,892		1,787

			Total		23,048		17,740		5,808		23,548		500

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

			Private predecessor				Successor
			Year ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005		For the 90 day period from October 3, 2005 to December 31, 2005		Non-GAAP combined 2005		Year to year change 2004-2005(a)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl):
	U.S. (excluding Appalachia)		$	38.97	$	52.07	$	57.35	$	53.27	$	14.30
	Appalachia			37.28		52.09		57.77		53.61		16.33
		Total		38.71		52.07		57.47		53.35		14.64
Natural gas (per Mcf):
	U.S. (excluding Appalachia)			5.29		6.23		9.40		6.98		1.69
	Appalachia			6.78		8.10		14.27		9.69		2.91
		Total		6.12		7.33		12.41		8.59		2.47
Natural gas liquids (per Bbl):
	U.S. (excluding Appalachia)			30.73		30.72		50.50		32.70		1.97
	Appalachia			—		—		—		—		—
		Total		30.73		30.72		50.50		32.70		1.97
Total average sales price (per Mcfe):
	U.S. (excluding Appalachia)			5.61		6.74		9.42		7.36		1.75
	Appalachia			6.75		8.13		14.01		9.65		2.90
		Total		6.16		7.49		12.06		8.62		2.46

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

Our revenues from the sale of oil, natural gas and NGLs before cash settlements of derivative financial instruments, for the non-GAAP combined year of 2005 increased by $60.9 million, or 43% over the year ended December 31, 2004 due to the combination of higher product prices, which accounted for $56.0 million of the increase and higher volumes, which contributed $4.9 million to increase in total revenues.

Prices for natural gas increased by $2.47 per Mcf, to $8.59 per Mcf in non-GAAP combined 2005 from $6.12 per Mcf in 2004. Natural gas prices in Appalachia averaged $9.69 for non-GAAP combined 2005 compared with $6.78 in 2004 while our other U.S. properties averaged $6.98 per Mcf in non-GAAP combined 2005 compared with $5.29 per Mcf in 2004. Our average prices per Mcfe in non-GAAP combined 2005 were $8.62 per Mcfe, an increase of $2.46 per Mcfe, or 40% higher than the average price per Mcfe of $6.16 in 2004.

Our natural gas production volumes for non-GAAP combined 2005 were 20,482 Mmcf compared with natural gas production of 18,860 Mmcf in 2004, an increase of 9%. Natural gas production in the Appalachia region increased to 12,196 Mmcf in non-GAAP combined 2005 from 10,505 Mmcf in the prior year. The increase of 1,691 Mmcf reflects (i) increased volumes of 866 Mmcf as a result of having 26 days of additional volumes in non-GAAP combined 2005 as we acquired our Appalachia properties on January 27, 2004, (ii) increased production of 1,081 Mmcf from the acquisition of our Pinestone properties in Central Pennsylvania in November and December of 2004, and (iii) production volumes of 642 Mmcf from third quarter acquisitions of additional properties in Pennsylvania and Ohio. These increased volumes were partially offset by lower production volumes from our Knox Trend wells of 759 Mmcf and pipeline curtailments imposed upon us by natural gas pipeline companies resulting from capacity constraints and short-term shut downs for maintenance purposes.

Natural gas production from our other U.S. properties in non-GAAP combined 2005 was 8,286 Mmcf compared with production of 8,355 Mmcf in 2004, a decrease of 69 Mmcf. Natural gas production from our Oak Hill Field (acquired in July 2004) and Minden Field (acquired in

January 2005) increased production by 2,161 Mmcf. This increase was offset by the absence of production from properties sold in 2004 and 2005 of 1,494 Mmcf and an expected decline in production from our Miami Corp. #35-1 Well of 696 Mmcf.

Oil production volumes in non-GAAP combined 2005 were 491 Mbbls, of which 375 Mbbls, or 76% of total oil production, were from non-Appalachia wells. Oil production in 2004 was 638 Mbbls, of which 538 Mbbls, or 84% of total oil production were from non-Appalachia wells. In Appalachia, oil production remained relatively equal to the prior year while non-Appalachia volumes declined by 163 Mbbls during non-GAAP combined 2005. The decreased volumes are the result of property sales in 2004 and non-GAAP combined 2005 combined with general declines in production from our oil producing properties. Despite the lower volumes in non-GAAP combined 2005, our total oil revenues were $26.2 million compared with $24.7 million in the prior year, an increase of $1.5 million due primarily to higher oil prices.

The following tables present our commodity price risk management activities and our other income (expense) for the non-GAAP combined totals for the 12 months ended December 31, 2005, and the twelve months ended December 31, 2004. The table also shows changes in these amounts between periods.

		Private predecessor						Successor
(in thousands)		Year ended December 31, 2004			For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 3, 2005 to December 31, 2005			Non-GAAP combined 2005			Year to year change 2004-2005(a)
Commodity price risk management activities:
	Cash settlements on derivative financial instruments	$	(26,083	)	$	(62,842	)	$	(22,210	)	$	(85,052	)	$	(58,969	)
	Non-cash change in fair value of derivative financial instruments		(24,260	)		(114,411	)		21,954			(92,457	)		(68,197	)

	Total commodity price risk management activities	$	(50,343	)	$	(177,253	)	$	(256	)	$	(177,509	)	$	(127,166	)

Other income:
	Gain (loss) on sale of properties	$	—		$	367		$	33		$	400		$	400
	Gas gathering income		—			144			109			253			253
	Gain (loss) from foreign currency tranactions		(6	)		518			14			532			538
	Interest, dividends, processing and other, net		1,147			6,046			2,209			8,255			7,108

	Total other income (expense)	$	1,141		$	7,075		$	2,365		$	9,440		$	8,299

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

Our objective in entering into commodity price risk management contracts is to manage price fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our commodity price risk management activities consists of non-cash income or expenses due to changes in the fair value of our commodity price risk management contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

Our cash settlements of derivative financial instruments reduced revenue by an additional $59.0 million during the non-GAAP combined year ended December 31, 2005, versus 2004. The NYMEX oil and natural gas prices that are used to settle our hedges increased significantly over the oil and natural gas prices of our contracts. The increases in prices resulted in us making significant payments to our counterparties to settle our derivative financial instruments during the year and our revenues decreased as a result.

Our total commodity price risk management activities reduced revenue by $50.3 million during the twelve month period ended December 31, 2004 and by $177.5 million during the non-GAAP combined 12 month period ended December 31, 2005. Included in cash settlements on derivative financial instruments for the non-GAAP combined twelve month period ended December 31, 2005 are payments totaling $52.6 million made in January and March 2005 to the counterparties of certain of our contracts to terminate these contracts. In January and March 2005, we entered into new commodity price risk management contracts for increased volumes at higher underlying product prices.

For the twelve months ended December 31, 2004 and non-GAAP combined 2005, we recognized, as a reduction of revenue, $24.3 million and $92.5 million, respectively, from the change in the fair value of our derivative financial instruments. We expect that our revenues will continue to be significantly impacted in future periods by changes in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices and the volume of future oil and natural gas sales covered under our commodity price risk management program. For the non-GAAP combined twelve month period ended December 31, 2005, the following percentages of our oil and natural gas production were subject to derivative financial instruments: 53% and 74% of oil and natural gas production, respectively, were subject to swap agreements and 5% of natural gas production was subject to floor price agreements. As a result of the TXOK acquisition, we assumed additional commodity price risk management contracts that were entered into by TXOK to cover a portion of its production.

We expect to continue our comprehensive commodity price risk management program as part of our overall acquisition and financing strategy to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. In connection with our acquisitions, we typically hedge a portion of future production acquired in order to lessen the variability of our returns on shareholders' equity and to protect our shareholders' equity by supporting our ability to meet our debt service obligations and stabilize cash flows.

As of December 31, 2005, we had derivative financial instruments in place hedging 58% of our expected 2006 oil production and 76% of our expected 2006 natural gas production from proved developed producing reserves. These levels are consistent with our acquisition and financing strategy and average historical levels of hedged production. The aforementioned percentages exclude TXOK, which we acquired on February 14, 2006. As of December 31, 2005, TXOK had approximately 72% of its expected 2006 natural gas production subject to derivative financial instruments.

Effective April 13, 2004, Addison entered into a long-term note agreement with ROJO in the amount of $98.8 million. Addison used the proceeds of this borrowing to repay virtually all of its outstanding indebtedness under its Canadian credit agreement in April 2004. The indebtedness was repayable in U.S. dollars on January 15, 2011 or upon sale of substantially all of its oil and gas properties. It accrued interest at 7¹/4% per annum and contained similar terms and conditions to our senior notes. On February 10, 2005, we sold this intercompany note in the Addison disposition. Under the provisions of SFAS No. 52, "Foreign Currency Translation", Addison is required to recognize any foreign transaction gains or losses in its statement of operations when translating this liability from U.S. dollars to Canadian dollars. Gain or loss recognized by Addison is not eliminated when preparing our consolidated statement of operations. As a result, we recorded a non-cash foreign currency transaction gain of $10.8 million during the year ended December 31, 2004 and a non-cash foreign currency

transaction loss of $3.5 million during the 275 day period ended October 2, 2005, both of which are reflected in income from discontinued operations on our consolidated statements of operations.

The increase in other income during the non-GAAP combined twelve month period ended December 31, 2005 when compared to the same period in 2004 is primarily the result of interest income earned on the investment of the proceeds received from the sale of Addison.

Costs and expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production cost per Mcfe for the year ended December 31, 2004, the 275 day predecessor period ended October 2, 2005, the 90 day successor period ended December 31, 2005 and non-GAAP combined totals for the 12 months ended December 31, 2005. The data presented for Appalachia only reflects costs and expenses since the date of our acquisition of North Coast. Results for the predecessor and successor periods in 2005 are combined as the Equity Buyout transaction had no impact on 2005 production costs. The table also shows the changes in these amounts between periods.

			Private predecessor				Successor
(in thousands)			Year ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005		For the 90 day period from October 3, 2005 to December 31, 2005		Non-GAAP combined 2005		Year to year change 2004-2005(a)
Oil and natural gas production costs: (in thousands)
Oil and natural gas operating costs:
	U.S. (excluding Appalachia)		$	11,636	$	6,739	$	2,733	$	9,472	$	(2,164	)
	Appalachia			8,198		7,842		2,752		10,594		2,396

		Total	$	19,834	$	14,581	$	5,485	$	20,066	$	232

Production and ad valorem taxes:
	U.S. (excluding Appalachia)		$	5,257	$	4,668	$	1,836	$	6,504	$	1,247
	Appalachia			3,165		2,908		1,628		4,536		1,371

		Total	$	8,422	$	7,576	$	3,464	$	11,040	$	2,618

Total oil and natural gas production costs:
	U.S. (excluding Appalachia)		$	16,893	$	11,407	$	4,569	$	15,976	$	(917	)
	Appalachia			11,363		10,750		4,380		15,130		3,767

		Total	$	28,256	$	22,157	$	8,949	$	31,106	$	2,850

Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs:
	U.S. (excluding Appalachia)		$	0.97	$	0.82	$	1.11	$	0.89	$	(0.08	)
	Appalachia			0.74		0.82		0.82		0.82		0.08
		Total		0.86		0.82		0.94		0.85		(0.01	)
Production and ad valorem taxes:
	U.S. (excluding Appalachia)			0.44		0.57		0.74		0.61		0.17
	Appalachia			0.28		0.29		0.49		0.35		0.07
		Total		0.37		0.43		0.60		0.47		0.10
Total oil and natural gas production costs:
	U.S. (excluding Appalachia)			1.41		1.39		1.85		1.50		0.09
	Appalachia			1.02		1.13		1.31		1.17		0.15
		Total		1.23		1.25		1.54		1.32		0.09

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

Our oil and natural gas operating costs for the non-GAAP combined 12 month period ended December 31, 2005 increased $0.2 million, or 1%, from the same period in 2004. The increase in operating costs resulted primarily from the following:

•: an additional 26 days of operating costs resulting from our acquisition of North Coast on January 27, 2004;
•: property acquisitions including our Oak Hill Field properties acquired in July 2004, Minden Field properties acquired on January 21, 2005, the Pinestone Appalachia properties acquired in November and December 2004 and other Appalachian properties acquired in the third quarter of 2005;
•: an increase in salaries and related benefits due to an increase in the number of field employees for our Appalachia properties;
•: a general increase in the cost of goods and services used in our oil and natural gas operations during 2004 and 2005; and
•: new wells added through our development and exploitation capital program.

These increased costs were partially offset by the absence of operating costs from the oil and natural gas properties that were sold during 2004 and 2005.

For our U.S. operations (excluding Appalachia), oil and natural gas operating costs per unit for the non-GAAP combined 12 month period ended December 31, 2005 decreased $0.09 to $0.89 per Mcfe compared to 2004 as the properties we sold had relatively high per unit operating costs. The oil and natural gas operating cost per unit for Appalachia increased from $0.74 per Mcfe for the year ended December 31, 2004 to $0.82 per Mcfe for the non-GAAP combined 12 month period ended December 31, 2005. The increase is primarily a result of higher actual oil and natural gas operating costs (excluding the effect of the additional 26 days of operating results in 2005). Oil and natural gas operating costs increased primarily due to higher personnel related costs of goods and services used in our operations.

Production and ad valorem taxes for the non-GAAP combined 12 month period ended December 31, 2005 increased by $2.6 million, or 31%, over the same period in 2004. These increases are primarily attributable to the increase in oil and natural gas revenues resulting from increased sales volumes of natural gas and higher oil and natural gas sales prices. The increases were partially offset by the absence of production taxes from oil and natural gas properties that we sold in 2004 and 2005. Production taxes are set by the state and local governments and vary as to the tax rate and the value to which that rate is applied. Further, ad valorem taxes in Texas and other states are based partially on the value of oil and natural gas reserves, which have increased as a result of the higher oil and natural gas prices.

The following table presents our depreciation, depletion and amortization expense for the year ended December 31, 2004, the 275 day predecessor period ended October 2, 2005, the 90 day successor

period ended December 31, 2005 and the non-GAAP combined totals for the 12 months ended December 31, 2005. The table also shows changes in these amounts between periods.

	Private predecessor				Successor
(in thousands)	Year ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005		For the 90 day period from October 3, 2005 to December 31, 2005		Non-GAAP combined 2005		Year to year change 2004-2005(a)
Depreciation, depletion and amortization costs:
Depreciation, depletion and amortization expense	$	28,519	$	24,687	$	14,071	$	38,758	$	10,239
Mcfe produced		23,048		17,740		5,808		23,548		500
Calculated rate per Mcfe	$	1.24	$	1.39	$	2.42	$	1.65	$	0.41

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

Our depreciation, depletion and amortization costs for the non-GAAP combined 12 month period ended December 31, 2005 increased by $10.2 million, or 36%, from the same period in 2004. The primary reasons for this increase are an increase in the per unit depletion rate during the 275 day period ended October 2, 2005, an increase in the equivalent sales volume for the non-GAAP combined 12 month period ended December 31, 2005 over the year ended December 31, 2004 and the impact of the change in accounting basis for our oil and natural gas properties as a result of the Equity Buyout for the 90 day period ended December 31, 2005. The increase in the rate for the 275 day period is due primarily to the average per unit prices paid for property acquisitions made during 2004 and 2005 being in excess of the prior period per unit depletion rate. The depletion rate per Mcfe for the 90 day period ended December 31, 2005 (post Equity Buyout) increased to $2.42 per Mcfe, or 74%, from $1.39 per Mcfe in the 275 day period ended October 2, 2005. For the non-GAAP 12 month period ended December 31, 2005, the average depletion rate per Mcfe was $1.65, or 33% higher than the prior year.

Accretion of discount on asset retirement obligations is the result of the adoption, as of January 1, 2003, of SFAS No. 143, "Accounting for Asset Retirement Obligations." This non-cash expense measures the changes in the liability for an asset retirement obligation due to the passage of time by applying an interest method of allocation to the amount of the liability at the beginning of the period. We adjusted our asset retirement obligations as part of our purchase accounting for the Equity Buyout, but the impact was not material to our results of operations for 2004 or non-GAAP combined 2005. See "Note 2. Summary of significant accounting policies—Deferred abandonment and asset retirement obligations" of the notes to our consolidated financial statements.

The following tables present our general and administrative costs for the year ended December 31, 2004, the 275 day predecessor period ended October 2, 2005, the 90 day successor period ended

December 31, 2005, and the non-GAAP combined totals for the 12 months ended December 31, 2005. The table also shows the changes in these amounts between periods.

		Private predecessor						Successor
(in thousands, except per unit amounts)		Year ended December 31, 2004			For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 3, 2005 to December 31, 2005			Non-GAAP combined 2005			Year to year change 2004-2005(a)
General and administrative costs:
	Gross G&A expense	$	18,966		$	18,122		$	7,179		$	25,301		$	6,335
	Operator overhead reimbursements		(2,109	)		(1,291	)		(532	)		(1,823	)		286
	Nonrecurring bonus expense		—			29,624			—			29,624			29,624
	Non cash non recurring—stock based compensation		—			44,092			—			44,092			44,092
	Capitalized acquisition, development and exploitation charges		(1,582	)		(1,203	)		(422	)		(1,625	)		(43	)

	G&A expense	$	15,275		$	89,344		$	6,225		$	95,569		$	80,294

	General and administrative expense per Mcfe	$	0.66		$	5.04		$	1.07		$	4.06		$	3.40

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

Our gross general and administrative costs for the non-GAAP combined 12 month period ended December 31, 2005 increased by $6.3 million, or 33%, over the same period in 2004. These increases were primarily attributable to:

•

A total of $2.2 million of share-based compensation as a result of the adoption of SFAS 123(R) in the fourth quarter of 2005.

•

an increase of $2.4 million in our legal and accounting expenses resulting primarily from:

•: costs incurred of approximately $1.7 million in evaluating the tax and legal implications of the various strategic alternatives considered in light of the sale of Addison;
•: costs incurred of approximately $0.5 million to comply with the provisions of the Sarbanes-Oxley Act; and
•: costs incurred of approximately $0.2 million for the sale of Addison;

•

an increase of $0.6 million in salaries and related benefits of which $81,000 is the result of an additional 26 days of expenses resulting from our acquisition of North Coast on January 27, 2004. The remaining increase in salaries and related benefits is primarily the result of an increase in the number of administrative employees and a general increase in salaries after the first quarter of 2004;

•

an increase of $0.3 million resulting from a reduction in overhead reimbursements received as a result of EXCO property sales during 2004 and 2005, and other increases, including franchise taxes, bad debt expenses, office rentals and bank fees.

General and administrative costs were $95.6 million for non-GAAP combined 12 month period ended December 31, 2005 compared with general and administrative costs of $15.3 million in 2004, an increase of $80.3 million. For the 275 day period ended October 2, 2005, general and administrative costs included $44.1 million of non-cash stock compensation expenses attributable to the acquisition by Holdings II of all the Class B common stock of EXCO Holdings pursuant to the Equity Buyout and $29.6 of cash compensation expenses resulting from payments made to holder of options to purchase Class A shares of EXCO Holdings, payments to employees who were participants in the EXCO

Holdings Employee Stock Participation Plan, and payments to certain employees of EXCO Resources under the EXCO Holdings Employee Bonus Retention Plan as a result of the Equity Buyout. The combination of the non-cash stock compensation of $44.1 million and $29.6 of cash payments attributable to the Equity Buyout plus the $6.3 million of variances previously explained account for the total variance of general and administrative costs for the non-GAAP combined 12 month period ended December 31, 2005 compared with the general and administrative costs in 2004.

The following table presents our interest expenses for the 12 months ended December 31, 2004, the 275 day predecessor period ended October 2, 2005, the 90 day successor period ended December 31, 2005, and the non-GAAP combined totals for the 12 months ended December 31, 2005. The table also shows the changes in these amounts between periods.

		Private predecessor				Successor
(in thousands)		Year ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005		For the 90 day period from October 3, 2005 to December 31, 2005		Non-GAAP combined 2005		Year to year change 2004-2005(a)
Interest expense:
7¹/4% senior notes due 2011		$	28,638	$	24,615	$	7,269	$	31,884	$	3,246
Interim bank loan			—		—		8,750		8,750		8,750
Credit agreements			868		193		90		283		(585	)
$50 million senior term loan			222		245		2		247		25
Amortization and write-off of deferred financing costs			4,157		1,618		3,301		4,919		762
Interest rate swaps			685		—		—		—		(685	)
Other interest expense			—		4		2		6		6

	Total interest expense	$	34,570	$	26,675	$	19,414	$	46,089	$	11,519

(a): Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.

Our interest expense for the non-GAAP combined 12 months ended December 31, 2005 increased $11.5 million from the same period in 2004 due to (i) a $3.2 million increase in interest expense attributable to $100.0 million of senior notes issued on April 13, 2004, which includes a $0.6 million adjustment to interest expense in 2005 related to these notes for the prior year, (ii) $8.8 million of interest expense attributable to the interim bank loan incurred by EXCO Holdings and pushed down to us as required by GAAP in connection with the Equity Buyout, and (iii) an increase of $0.8 million of amortization of deferred financing costs associated with the interim bank loan. The increases of $12.8 million in 2005 are partially offset by lower interest costs associated with (i) the absence of $0.7 million of expense from interest rate swaps we assumed in 2004 upon the acquisition of North Coast, and (ii) reduced interest expense from our credit agreement of $0.6 million. No funds were borrowed under the bridge facility related to the North Coast acquisition.

A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) from continuing operations before income taxes for the year ended December 31, 2004, the 275 day predecessor period from January 1, 2005 to October 2,

2005, the 90 day successor period from October 3, 2005 to December 31, 2005, is presented in the following table:

		Private predecessor						Successor
		Year Ended December 31, 2004			For the 275 Day Period From January 1, 2005 to October 2, 2005			For the 90 Day Period From October 3, 2005 to December 31, 2005
United States federal income taxes (benefit) at statutory rate of 35%		$	(5,120	)	$	(70,293	)	$	8,150
Increases (reductions) resulting from:
	Undistributed earnings of foreign subsidiary		8,237			—			—
	Foreign tax items		—			644			(2,996	)
	Change in Canadian tax rates		(909	)		—			—
	Change in U.S. tax law related to Canadian dividend		—			(2,075	)		—
	Adjustments to the valuation allowance		—			—			—
	Non-deductible compensation		—			15,432			604
	Non-deductible intercompany foreign interest expense		1,840			—			—
	State taxes net of federal benefit		880			(6,665	)		1,095
	Other		198			(741	)		468

Income provision (benefit) before discontinued operations		$	5,126		$	(63,698	)	$	7,321

The income tax expense/benefit on our loss from continuing operations for the 12 months ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005 and benefit on our income from continuing operations for the 90 day period from October 3, 2005 to December 31, 2005 differs from the amounts calculated using the U.S. federal statutory rate. The December 31, 2004 expense includes a $0.9 million tax benefit from reductions to income tax rates and provisions for the deduction of crown royalties in Canada which became effective in May 2004. This benefit is reflected as a component of continuing operations pursuant to SFAS No. 109 and EITF 93-13.

On October 22, 2004, the President signed the American Jobs Creation Act of 2004, or the Act. The Act created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. We repatriated Cdn. $74.5 million ($59.6 million) in an extraordinary dividend, as defined in the Act, from Addison on February 9, 2005. We recognized a tax liability of $8.2 million as of December 31, 2004 related to the extraordinary dividend. As a result of certain technical advice issued by the U.S. Treasury Department, we reduced the tax liability by $2.1 million during the second quarter of, 2005. EXCO Resources filed amended quarterly reports on Form 10-Q/A that included restated financial statements for the quarters ended June 30, 2005 and September 30, 2005 to reflect the tax benefit in the earlier quarter and to classify the benefit as a component of continuing rather than discontinued operations in the September 30, 2005 quarter. This additional tax benefit is recognized as a component of taxes from continuing operations pursuant to SFAS No. 109 and EITF 93-13, which require that a tax effect of a change in enacted rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.

In June 2005, the state of Ohio enacted new legislation that changed the method of taxing businesses that operate in Ohio. We have significant operations in the state of Ohio through our North Coast subsidiary. As a result of the new tax legislation in Ohio, we recognized a reduction to our deferred tax liability of $5.2 million, which reflects the change in Ohio tax rates and the impacts of our stepped-up basis resulting from the Equity Buyout as of December 31, 2005. The 275 day period ended October 2, 2005 also includes a $2.1 million tax benefit related to an extraordinary dividend received from Addison, our former wholly-owned Canadian subsidiary.

On February 10, 2005, we sold all of the issued and outstanding shares of common stock of Addison and two intercompany notes that Addison owed to ROJO. The aggregate purchase price after contractual adjustments was Cdn. $551.3 million ($443.3 million) less the payment of the outstanding balance under Addison's credit facility of Cdn. $90.1 million ($72.1 million). We have recognized a gain from the sale of Addison of $175.7 million before income tax expense of $50.1 million related to the gain. The income tax is composed of:

(unaudited, in thousands)	275 day period ended October 2, 2005
U.S. income tax before foreign tax credits	$	50,128
Canadian income tax on the gain		33,717
U.S. foreign tax credit		(33,788	)

Total income tax on gain	$	50,057

Income taxes from discontinued operations for the 275 day period ended October 2, 2005 reflects the income tax on the gain of $50.1 million as discussed above, an income tax benefit of $1.3 million from Addison's operations during the period January 1, 2005 to February 10, 2005, and approximately $0.5 million of Canadian income taxes withheld on interest paid by Addison in 2005 on the intercompany notes.

The loss from discontinued operations of $4.4 million before the gain on the sale of Addison and income taxes from discontinued operations for the 275 day period ended October 2, 2005 includes:

•: approximately $3.8 million in losses from commodity price risk management activities; and
•: approximately $2.7 million in severance for employees not hired by the purchaser and management retention bonus payments to certain Addison employees that were accelerated as a result of the sale.

Stock based and other compensation expense

Immediately prior to the closing of the Equity Buyout on October 3, 2005, we recorded stock based and other compensation expense for the following items, which are included as part of the 275 day period ended October 2, 2005:

•

A non-cash charge of approximately $44.1 million as a result of the acquisition by Holdings II of all of the shares of Class B common stock of EXCO Holdings held by certain members of our management and other employees. The offset to this expense was to additional paid-in capital. The stockholder agreements governing the Class A and Class B common stock of EXCO Holdings provided that, upon the occurrence of certain specified events, including the change of control that occurred upon the Equity Buyout:

•: the holders of the Class A shares would receive the first $175.0 million of proceeds, and
•: the remaining proceeds in excess of the $175.0 million would be allocated on a pro-rata basis to the holders of the Class A shares and the Class B shares.

For financial accounting purposes, the Class B shares were considered to be a "variable" plan since a holder of the shares had to be employed at the date of the change of control to receive fair value for the Class B shares. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.

•: A charge of $17.8 million for payments made to holders of options to purchase Class A shares of EXCO Holdings less options held by the EXCO Holdings Employee Stock Participation Plan, or ESPP. This amount was paid to option holders at the time of the Equity Buyout by EXCO

Holdings to purchase all stock options outstanding at that time. The amount represented the cumulative difference between the $5.197 per share proceeds for the Class A shares and the exercise price of the outstanding stock options times the number of stock options outstanding.

•: A charge of $8.3 million for payments made to our employees who were participants in the ESPP. This amount was paid by EXCO Holdings at the time of the Equity Buyout and was based upon shares of EXCO Holdings Class A and Class B common stock that were reserved, but unissued, for the ESPP. All employees on the date of the Equity Buyout who were not direct owners of EXCO Holdings Class A or Class B common stock received payments under the ESPP. For financial accounting purposes, the ESPP was considered to be a "variable" plan since, to be eligible, a recipient had to be employed at the date of the change of control to receive a payment. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.
•: A charge of $2.6 million for accelerated payments made by EXCO Holdings to certain employees of EXCO Resources under the EXCO Holdings Employee Bonus Retention Plan, or the Retention Plan. The Retention Plan was accelerated, paid in full and terminated upon consummation of the Equity Buyout.

During the 90 day period from October 3, 2005 to December 31, 2005, we recorded a non-cash charge of $2.2 million, of which $1.0 million was capitalized as part of our proved oil and natural gas properties as a result of the granting of options to purchase 4,992,650 shares of common stock of EXCO Holdings under the 2005 Long-Term Incentive Plan. The offset to this expense was to shareholder's equity as additional paid-in capital. This non-cash charge is a result of Holdings II having adopted the provisions of SFAS 123(R) at the inception of Holdings II in August 2005. Our annual expenses for the stock options outstanding at December 31, 2005 will be approximately $2.7 million in each of 2006 and 2007 and $1.8 million in 2008.

2004 compared with 2003

Revenues and production

The following tables present our oil and natural gas revenues (before commodity price risk management activities), production and average unit sales price for the public predecessor period ended July 28, 2003, private predecessor period ended December 31, 2003, non-GAAP combined totals for the 12 months ended December 31, 2003 and December 31, 2004. The tables also show the changes in these amounts between periods. The non-GAAP combined information presented below for the 12 months ended December 31, 2003 represents the total of our activity for the 209 day period from January 1, 2003 to July 28, 2003 and for the 156 day period from July 29, 2003 to December 31, 2003. The data presented for Appalachia only reflects revenues and production since the date of our acquisition of North Coast on January 27, 2004.

For the 209 day period ended July 28, 2003, cash settlements of hedge transactions are included in oil and natural gas revenues in the consolidated statement of operations. These settlements, which totaled $14.5 million for the 209 day period from January 1, 2003 to July 28, 2003, are not reflected in

the amounts shown below for oil and natural gas revenues (before commodity price risk management activities).

					Private predecessor
			Public predecessor		Private predecessor				Private predecessor
			Public predecessor		For the 156 day period from July 29, 2003 to December
(in thousands)			For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004(a)
Oil and natural gas revenues before commodity price risk management activities:
Oil revenues:
	U.S. (excluding Appalachia)		$	13,874	$	8,477	$	22,351	$	20,966	$	(1,385	)
	Appalachia			—		—		—		3,728		3,728

		Total	$	13,874	$	8,477	$	22,351	$	24,694	$	2,343

Natural gas revenues:
	U.S. (excluding Appalachia)		$	21,300	$	12,751	$	34,051	$	44,193	$	10,142
	Appalachia			—		—		—		71,262		71,262

		Total	$	21,300	$	12,751	$	34,051	$	115,455	$	81,404

Natural gas liquids revenues:
	U.S. (excluding Appalachia)		$	803	$	539	$	1,342	$	1,844	$	502
	Appalachia			—		—		—		—		—

		Total	$	803	$	539	$	1,342	$	1,844	$	502

Total oil and natural gas revenues:
	U.S. (excluding Appalachia)		$	35,977	$	21,767	$	57,744	$	67,003	$	9,259
	Appalachia			—		—		—		74,990		74,990

		Total	$	35,977	$	21,767	$	57,744	$	141,993	$	84,249

					Private predecessor
			Public predecessor		Private predecessor				Private predecessor
			Public predecessor		For the 156 day period from July 29, 2003 to December
			For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004(a)
Production:
Oil (Mbbls):
	U.S. (excluding Appalachia)			461		294		755		538		(217	)
	Appalachia			—		—		—		100		100

		Total		461		294		755		638		(117	)

Natural gas (Mmcf):
	U.S. (excluding Appalachia)			4,424		3,127		7,551		8,355		804
	Appalachia			—		—		—		10,505		10,505

		Total		4,424		3,127		7,551		18,860		11,309

Natural gas liquids (Mbbls):
	U.S. (excluding Appalachia)			35		24		59		60		1
	Appalachia			—		—		—		—		—

		Total		35		24		59		60		1

Total production (Mmcfe):
	U.S. (excluding Appalachia)			7,400		5,035		12,435		11,943		(492	)
	Appalachia			—		—		—		11,105		11,105

		Total		7,400		5,035		12,435		23,048		10,613

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

			Public predecessor		Private predecessor				Private predecessor
Average sales price (before cash settlements of derivative financial instruments):			For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004 (a)
Oil (per Bbl):
	U.S. (excluding Appalachia)		$	30.08	$	28.83	$	29.59	$	38.97	$	9.38
	Appalachia			—		—		—		37.28		n/a
		Total		30.08		28.83		29.59		38.71		9.12
Natural gas (per Mcf):
	U.S. (excluding Appalachia)			4.81		4.08		4.51		5.29		0.78
	Appalachia			—		—		—		6.78		n/a
		Total		4.81		4.08		4.51		6.12		1.61
Natural gas liquids (Mbbls):
	U.S. (excluding Appalachia)			22.77		22.29		22.58		30.73		8.15
	Appalachia			—		—		—		—		—
		Total		22.77		22.29		22.58		30.73		8.15
Total oil and natural gas revenues (per Mcfe):
	U.S. (excluding Appalachia)			4.86		4.32		4.64		5.61		0.97
	Appalachia			—		—		—		6.75		n/a
		Total		4.86		4.32		4.64		6.16		1.52

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

Our revenues from the sale of oil, natural gas and NGLs, before cash settlements of derivative financial instruments, for the year ended December 31, 2004 increased by $84.2 million, or 146% over non-GAAP combined 2003 primarily due to the acquisition of our Appalachia properties. Oil and natural gas revenues for Appalachia for the period from January 27, 2004 to December 31, 2004 were $75.0 million. The increase in revenue was also due to a 11% increase in natural gas production volumes, excluding Appalachia. This increase in production volumes is due primarily to property acquisitions, including the Oak Hill properties that we acquired on July 29, 2004 and the completion in January 2004 of our Miami Corp. 35-1 sidetrack well. For the year ended December 31, 2004, increases in oil, natural gas and NGL prices increased revenues by $18.5 million. Oil production and oil revenues for our U.S. operations (excluding Appalachia) declined in 2004 due to property sales in 2003 and 2004 and a general decline in production from our oil producing properties.

The following tables present our commodity price risk management activities and our other income (expense) for the predecessor period ended July 28, 2003, successor period ended December 31, 2003, non-GAAP combined totals for the 12 months ended December 31, 2003 and December 31, 2004. The table also shows changes in these amounts between periods.

		Public predecessor		Private predecessor				Private predecessor
(in thousands)		For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004			Year to year change 2003-2004(a)
Commodity price risk management activities:
	Cash settlements on derivative financial instruments	$	—	$	5,375	$	5,375	$	(26,083	)	$	(31,458	)
	Non-cash change in fair value of derivative financial instruments		—		5,425		5,425		(24,260	)		(29,685	)

	Total commodity price risk management activities	$	—	$	10,800	$	10,800	$	(50,343	)	$	(61,143	)

		Public predecessor			Private predecessor						Private predecessor
(in thousands)		For the 209 day period from January 1, 2003 through July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003			Non-GAAP combined 2003			Year ended December 31, 2004			Year to year change 2003-2004(a)
Other income:
	Income from terminated hedges	$	1,763		$	—		$	1,763		$	—		$	(1,763	)
	Income (expense) from hedge ineffectiveness		(2,544	)		—			(2,544	)		—			2,544
	Gain (Loss) from foreign currency transactions		(984	)		(368	)		(1,352	)		(6	)		1,346
	Interest, dividends, processing and other, net		616			207			823			1,147			324

	Total other income (expense)	$	(1,149	)	$	(161	)	$	(1,310	)	$	1,141		$	2,451

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

Our cash settlements of derivative financial instruments reduced revenue by $26.1 million during the year ended December 31, 2004. The NYMEX oil and natural gas prices that are used to settle our hedges increased significantly over the oil and natural gas prices of our contracts. The increases in prices resulted in us making significant payments to our counterparties to settle our derivative financial instruments during the year and our revenues decreased as a result. We also had a significant increase in the volume of natural gas under derivative financial instruments to reflect the increase in our natural gas production as a result of the acquisition of North Coast.

Prior to the completion of the going private transaction, we accounted for our derivative financial instruments as cash flow hedges. During the 209 day period from January 1 to July 28, 2003, we reduced our revenues by $2.5 million for the ineffective portion of the change in the fair value of our hedges. The ineffectiveness was primarily due to a significant increase in March 2003 in the difference between the NYMEX price for oil and natural gas, which is the price we use to settle our derivative financial instruments, and the actual price that we receive in the field for the physical delivery of our oil and natural gas production. For the year ended December 31, 2004, we recognized as a reduction of revenue $24.3 million from the change in the fair value of our derivative financial instruments. Previously, the effective portion of this change was reflected in other comprehensive income while the ineffective portion was recognized in current period earnings. We expect that our revenues will continue to be significantly impacted in future periods by changes in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices and the volume of future oil and natural gas sales covered under our commodity price risk management program.

During the 209 day period from January 1 to July 28, 2003, we recorded approximately $1.8 million of non-cash income from terminated hedges as other income. As a result of the going private transaction, we ceased recording such income.

Costs and expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production cost per Mcfe for the predecessor period ended July 28, 2003, successor period ended December 31, 2003, non-GAAP combined totals for the 12 months ended December 31, 2003 and December 31, 2004. The data presented for Appalachia only reflects costs and expenses since the date of our acquisition of North Coast. Results for the predecessor and successor periods in 2003 are combined as the going private transaction had no impact on 2003 production costs. The table also shows the changes in these amounts between periods.

			Public predecessor		Private predecessor				Private predecessor
(In thousands)			For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004(a)
Oil and natural gas operating costs:
	U.S. (excluding Appalachia)		$	8,282	$	5,406	$	13,688	$	11,636	$	(2,052	)
	Appalachia			—		—		—		8,198		8,198

		Total	$	8,282	$	5,406	$	13,688	$	19,834	$	6,146

Production and ad valorem taxes:
	U.S. (excluding Appalachia)		$	3,098	$	1,925	$	5,023	$	5,257	$	234
	Appalachia			—		—		—		3,165		3,165

		Total	$	3,098	$	1,925	$	5,023	$	8,422	$	3,399

Total oil and natural gas production costs:
	U.S. (excluding Appalachia)		$	11,380	$	7,331	$	18,711	$	16,893	$	(1,818	)
	Appalachia			—		—		—		11,363		11,363

		Total	$	11,380	$	7,331	$	18,711	$	28,256	$	9,545

			Public predecessor		Private predecessor				Private predecessor
(per Mcfe)			For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004 (a)
Oil and natural gas operating costs:
	U.S. (excluding Appalachia)		$	1.12	$	1.07	$	1.10	$	0.97	$	(0.13	)
	Appalachia			—		—		—		0.74		n/a
		Total		1.12		1.07		1.10		0.86		(0.24	)
Production and ad valorem taxes:
	U.S. (excluding Appalachia)			0.42		0.38		0.40		0.44		0.04
	Appalachia			—		—		—		0.28		n/a
		Total		0.42		0.38		0.40		0.37		(0.03	)
Total oil and natural gas production costs:
	U.S. (excluding Appalachia)			1.54		1.46		1.50		1.41		(0.09	)
	Appalachia			—		—		—		1.02		n/a
		Total		1.54		1.46		1.50		1.23		(0.27	)

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

Our oil and natural gas operating costs for the year ended December 31, 2004 increased $6.1 million, or 45%, from non-GAAP combined 2003. The primary reasons for the increases in oil and natural gas operating costs are:

•: our acquisition of North Coast which increased oil and natural gas operating costs by $8.2 million for the year ended December 31, 2004;
•: our acquisitions of the Oak Hill properties in east Texas, additional interests in the Vinegarone properties and the acquisition of several other properties during 2003 and 2004, which increased oil and natural gas operating costs by approximately $0.5 million; and
•: a general increase in the cost of goods and services used in our oil and natural gas operations during 2004.

The above increases were partially offset by a $3.0 million reduction in oil and natural gas operating costs from properties that we sold in 2003 and 2004.

Production and ad valorem taxes for the year ended December 31, 2004 increased by $3.4 million, or 68%, over non-GAAP combined 2003. These increases are primarily attributable to our acquisition of North Coast which increased production and ad valorem taxes by $3.2 million and were partially offset by the absence of production taxes from oil and natural gas properties that were sold in 2003 and 2004. Production taxes are set by the state governments and vary as to the tax rate and the value to which that rate is applied. Further, ad valorem taxes in Texas and other states are based partially on the value of oil and natural gas reserves, which have increased as a result of the higher oil and natural gas prices. These taxes are generally based upon the price received for production.

The following table presents our depreciation, depletion and amortization expense for the public predecessor period ended July 28, 2003, private predecessor period ended December 31, 2003, non-GAAP combined totals for the 12 months ended December 31, 2003 and December 31, 2004. The table also shows changes in these amounts between periods.

		Public predecessor		Private predecessor				Private predecessor
(in thousands)		For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004 (a)
Depreciation, depletion and amortization costs:
	Depreciation, depletion and amortization expense	$	5,125	$	5,413	$	10,538	$	28,519	$	17,981
	Mmcfe produced		7,400		5,035		12,435		23,048		10,613
	Calculated rate per Mcfe	$	0.69	$	1.07	$	0.85	$	1.24	$	0.39

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

Our depreciation, depletion and amortization costs for the year ended December 31, 2004 increased by $18.0 million, or 171%, from non-GAAP combined 2003. The primary reasons for this increase are:

•: our acquisition of North Coast (which accounted for approximately $14.6 million of the increase for the year ended December 31, 2004), and other property acquisitions during 2003 and 2004; and
•: the effect of a full year's depreciation, depletion and amortization in 2004 from properties other than North Coast's on the stepped-up values associated with the going private transaction of approximately $2.6 million.
•: other increases in depreciation, depletion, and amortization attributable to rate increases from drilling and acquisition activities of approximately $0.8 million.

The following tables present our general and administrative costs for the public predecessor period ended July 28, 2003, private predecessor period ended December 31, 2003, non-GAAP combined totals for the 12 months ended December 31, 2003 and December 31, 2004. Results for the predecessor and successor periods in 2003 are combined as the going private transaction had no impact on the

accounting for our 2003 general and administrative costs. The table also shows the changes in these amounts between periods.

		Private predecessor			Private predecessor						Private predecessor
(in thousands, except per unit amounts)		For the 209 day period from January 1, 2003 through July 28, 2003			For the 156 day period from July 29,2003 to December 31, 2003			Non-GAAP combined 2003 2003			Year ended December 31, 2004			Year to year change 2003-2004(a)
General and administrative costs:
	Gross G&A expense	$	13,208		$	5,312		$	18,520		$	18,966		$	446
	Operator overhead reimbursements		(1,343	)		(943	)		(2,286	)		(2,109	)		177
	Capitalized acquisition, development and exploitation charges		(518	)		(546	)		(1,064	)		(1,582	)		(518	)

	G&A expense	$	11,347		$	3,823		$	15,170		$	15,275		$	105

General and administrative expense per Mcfe		$	1.53		$	0.76		$	1.22		$	0.66		$	(0.56	)

Our gross general and administrative costs for the year ended December 31, 2004 increased by $0.4 million, or 2%, over non-GAAP combined 2003. This increase was primarily attributable to:

•: the acquisition of North Coast which increased general and adminstrative costs by $4.2 million for the year ended December 31, 2004 and the total number of employees from December 31, 2003 to December 31, 2004 by 153: and
•: a net increase in salaries, benefits and other personnel related costs of $2.1 million for the year ended December 31, 2004.

This increase was partially offset by:

•: a reduction in legal expense of approximately $0.6 million in 2004 primarily due to costs incurred in 2003 for the going private transaction;
•: the absence in 2004 of $1.9 million in financial advisory and other costs incurred in connection with the going private transaction during 2003: and
•: the absence in 2004 of compensation costs from stock option issuances of $3.7 million which were expensed immediately prior to the going private transaction.

The following tables present our interest for the public predecessor period ended July 28, 2003, private predecessor period ended December 31, 2003, non-GAAP combined totals for the 12 month ended December 31, 2003 and December 31, 2004. Results for the public predecessor and private predecessor periods in 2003 are combined as the going private transaction had no impact on the accounting for 2003 interest expense. The table also shows the change in these amounts between periods.

	Public predecessor		Private predecessor				Private predecessor
(in thousands)	For the 209 day period from January 1, 2003 through July 28, 2003		For the 156 day period from July 29,2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004		Year to year change 2003-2004(a)
Interest expense:
7¹/4% senior notes due 2011	$	—	$	—	$	—	$	28,638	$	28,638
Credit agreements		590		1,120		1,710		868		(842	)
$50 million senior term loan		—		647		647		222		(425	)
Amortization and write-off of deferred financing costs		459		—		459		4,157		3,698
Interest rate swaps		—		—		—		685		685
Other interest expense		9		154		163		—		(163	)

Total interest expense	$	1,058	$	1,921	$	2,979	$	34,570	$	31,591

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

Our interest expense for the year ended December 31, 2004 increased $31.6 million from non-GAAP combined 2003. The increase is primarily due to the issuance on January 20, 2004 of $250.0 million aggregate principal amount and on April 13, 2004 of $100.0 million aggregate principal amount of 7¹/4% senior notes due 1022. Additionally, the amortization of deferred financing costs related to the senior notes and the amendment and restatement of our credit agreement increased interest expense by $3.7 million. Amortization of deferred financing costs in 2004 includes approximately $1.7 million in costs relating to the senior term loan that was repaid in full in January 2004 and fees incurred on an interim loan facility related to the North Coast acquisition. No funds were borrowed under the interim loan facility. Our long-term debt balance at December 31, 2004 was $487.5 million compared to $99.5 million at December 31, 2003. As a result of the issuance of the senior notes on January 20, 2004 and April 13, 2004, our interest expense was significantly higher in 2004 than it was in 2003.

A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, and for the year ended December 31, 2004, is presented in the following tabel:

		Public predecessor			Private predecessor						Private predecessor
(in thousands)		For the 209 day period from January 1, 2003 through July 28, 2003			For the 156 day period from July 29,2003 to December 31, 2003			Non-GAAP combined 2003			Year ended December 31, 2004			Year to year change 2003-2004(a)
Income Taxes:
Current:
	Federal	$	—		$	—		$	—		$	—		$	—
	State		(181	)		—			(181	)		1,445			1,626

	Total current income tax expense (benefit)		(181	)		—			(181	)		1,445			1,626
Deferred:
	Federal		—			(2,692	)		(2,692	)		4,681			7,373
	State		—			(131	)		(131	)		(91	)		40
	Canadian		—			(4,941	)		(4,941	)		(909	)		4,032

	Total deferred income tax expense (benefit)		—			(7,764	)		(7,764	)		3,681			11,445

	Total income tax expense (benefit)	$	(181	)	$	(7,764	)	$	(7,945	)	$	5,126		$	13,071

(a): Year to year changes relative to 2003 are calculated using the non-GAAP combined 2003 totals.

Prior to the completion of the going private transaction, we did not record any income tax benefit in the U.S. associated with losses generated in the U.S., as it was uncertain whether we would be able to utilize our net deferred tax asset. Accordingly, the tax effects of our U.S. generated losses were offset by an increase in our valuation allowance. This resulted in an overall higher effective tax rate for the 209 day period ended July 28, 2003, as we increased our U.S. valuation allowance by approximately $2.5 million.

Effective July 29, 2003 and in conjunction with our going private transaction, the deferred tax asset valuation allowance was reduced in the purchase price allocation as EXCO Resources (successor basis) was in a deferred tax liability position.

For the 156 day period ended December 31, 2003, we included $4.9 million of tax benefit attributable to a phase in of reduced income tax rates enacted in Canada effective November of 2003. The impact of this benefit created an effective tax rate of 98.0%. When the effects of this benefit are excluded, the effective rate decreases to 35.7%. These benefits from Canadian taxes are reflected in continuing operations as required by SFAS No. 109 and EITF 93-13, which require that a tax effect of a change in enacted tax rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.

On October 22, 2004, the President signed the American Jobs Creation Act of 2004, or the Act. The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. We repatriated Cdn. $74.5 million ($59.6 million) in an extraordinary dividend, as defined in the Act, from Addison on February 9, 2005. We recognized a tax liability of $8.2 million as of December 31, 2004 related to the extraordinary dividend.

Our liquidity, capital resources and capital commitments

General

Most of our growth has resulted from recent acquisitions and our development and exploitation program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash received from the sales of oil and natural gas properties, cash flow from operations, bank financing and the sale or issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreement is subject to restrictions imposed by our lenders. In addition, our indenture governing our senior notes contains restrictions on incurring indebtedness and pledging our assets.

On February 14, 2006, EXCO Resources completed its IPO of 50,000,000 shares of its common stock for aggregate net proceeds to EXCO Resources of $617.5 million after underwriters' discount. The net proceeds from the IPO, together with cash on hand and additional borrowings under EXCO's credit agreement, were used as follows:

•: $359.8 million to repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred in connection with the Equity Buyout;
•: $163.4 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends and redemption premium, issued to a related party in connection with the acquisition of ONEOK Energy;

•: $375.5 million to repay $171.8 million in principal plus accrued and unpaid interest of $0.9 million under the TXOK credit facility ($137.0 remained outstanding under this facility following the IPO) and $200.0 million in principal plus accrued and unpaid interest of $2.8 million under the TXOK term loan, both loans having been incurred in connection with the acquisition of ONEOK Energy; and
•: $4.4 million to pay fees and expenses in connection with the IPO.

On February 10, 2005, we sold Addison for $443.3 million after contractual adjustments. The net cash proceeds may only be utilized by us in accordance with the terms of the indenture governing the senior notes and our credit agreement. In addition, $120.6 million of these proceeds are pledged as collateral under our credit agreement and the senior notes. The credit agreement security interest on these proceeds was released in conjunction with the commencement of the senior notes purchase offer on November 2, 2005 related to the sale of Addison, or the Addison senior notes purchase offer. Upon completion of the Addison senior notes purchase offer on December 7, 2005, the senior notes security interest was released.

On January 20, 2004, we issued $350.0 million aggregate principal amount of 7¹/4% senior notes due January 15, 2011. Additionally, on April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of our 7¹/4% senior notes due January 15, 2011 having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. We used approximately $98.8 million of the proceeds from the April 2004 offering to repay substantially all of the indebtedness outstanding under our Canadian credit agreement.

We had negative operating cash flow after changes in working capital of approximately $73.3 million for the non-GAAP combined 2005 twelve months ended December 31, 2005. This was primarily the result of $67.6 million paid in January and March 2005 to terminate certain of our commodity price risk management contracts, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production, and approximately $50.1 million in U.S. and Canadian taxes incurred on the gain from the sale of Addison. These payments were funded by cash received from the sale of Addison. At December 31, 2005, our cash and cash equivalents balance was $225.0 million, an increase of $209.0 million from December 31, 2004 primarily as a result of the sale of Addison on February 10, 2005. On January 18, 2005 and July 15, 2005, we made interest payments on our 7¹/4% senior notes totaling $32.6 million. Our working capital deficit at December 31, 2005 was $130.9 million which includes the EXCO Holdings $350.0 million interim bank loan that was repaid with a portion of the proceeds from the IPO, included in total current liabilities.

Acquisitions and capital expenditures

On January 27, 2004, we completed the North Coast acquisition. We funded the North Coast acquisition from the net proceeds from the $350.0 million offering of our 7¹/4% senior notes due January 15, 2011.

The following table presents our capital expenditures for the 209 day predecessor period ended July 28, 2003, the 156 day successor period ended December 31, 2003, the non-GAAP combined totals for the year ended December 31, 2003, the year ended December 31, 2004, the 275 day period ended

October 2, 2005, the 90 day period ended December 31, 2005 and the non-GAAP combined total for the year ended December 31, 2005.

			Public predecessor			Private predecessor				Private predecessor
(in thousands)			For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003		Non-GAAP combined 2003		Year ended December 31, 2004
Capital Expenditures:
	Property acquisitions		$	1,753		$	14,183	$	15,936	$	88,347
	Acquisition of North Coast Energy, Inc., net of cash acquired			—			—		—		215,133
	Development capital expenditures			2,574			5,778		8,352		36,742
	Other			(192	)		1,241		1,049		7,543

		Total capital expenditures	$	4,135		$	21,202	$	25,337	$	347,765

			Private predecessor		Successor
(in thousands)			For the 275 day period from January 1, 2005 to October 2, 2005		For the 90 day period from October 3, 2005 to December 31, 2005		Non-GAAP combined 2005
Capital Expenditures:
	Property acquisitions		$	103,222	$	—	$	103,222
	Development capital expenditures			39,900		13,194		53,094
	Other			5,944		1,712		7,656

		Total capital expenditures	$	149,066	$	14,906	$	163,972

On July 29, 2004, we acquired natural gas properties located in Rusk County, Texas for a total purchase price of $35.9 million ($35.6 million after contractual adjustments). Additionally, in August 2004, we paid $2.3 million to acquire additional interests in certain of the same properties after the seller was able to satisfy certain contractual obligations. Estimated total Proved Reserves acquired, net to our interest and as of the date of acquisition, include approximately 224 Mbbls of oil and 18.1 Bcf of natural gas. We funded the acquisition with $32.0 million in borrowings under our credit agreement and from surplus cash. The properties acquired consist of 32 producing natural gas wells, which we now operate, and a significant number of proved undeveloped and unproved drilling locations.

In November and December 2004 we acquired working interests in, and became operator of, 228 oil and natural gas wells and related natural gas gathering systems in Centre and Clearfield Counties, Pennsylvania. Estimated total Proved Reserves acquired, net to our interests and as of the date of acquisition, include approximately 23.3 Bcf of natural gas. We believe that there are a number of additional unproved drilling locations on these properties. The total purchase price, before contractual adjustments, was approximately $43.5 million and was funded with borrowings under our credit agreement.

On January 21, 2005, we acquired natural gas properties located in the Minden Field in East Texas for a total purchase price of $17.9 million (approximately $17.7 million net of contractual adjustments). Estimated total Proved Reserves acquired, net to our interest and as of the date of acquisition, include approximately 35 Mbbls of oil and 8.8 Bcf of natural gas. We funded the acquisition with $13.3 million in borrowings under our credit agreement and from surplus cash. The properties acquired consist of 13 producing natural gas wells, which we now operate, and a number of proved and unproved drilling locations. We also acquired a small natural gas gathering system as part of this acquisition for an additional $0.7 million.

In the third quarter of 2005, we acquired natural gas properties located in the Appalachia area for an aggregate purchase price of $81.7 million. Estimated total Proved Reserves, net to our interest and as of the date of acquisition, include approximately 48.7 Bcf of natural gas. We funded these

acquisitions with surplus cash. The properties acquired consisted of 744 producing natural gas wells, which we now operate, as well as 512 future drilling locations, of which 320 are classified as proved.

For the year 2005, we spent approximately $53.1 million for drilling, exploitation and development capital expenditures in the United States. As of December 31, 2005, we were contractually obligated to spend $13.4 million for our drilling and exploitation activities.

On a pro forma basis (as if we acquired TXOK on January 1, 2006), we have budgeted approximately $159.1 million in 2006 for drilling, exploitation and operational capital expenditures, including $66.7 million for TXOK. We have also budgeted approximately $7.0 million in 2006 for our additional acquisition-related expenditures and approximately $1.6 million for information technology expenditures. We have no contractual committments related to our capital budget other than an agreement with a contract drilling company which commits us to utilize, or pay for if not utilized, the use of three drilling rigs in east Texas until December 31, 2007. As of December 31, 2005, the minimum amount that we are obligated to pay under this contract is $25.2 million.

We expect to utilize our current cash balance, cash flow from operations and available funds under our credit agreement to fund our acquisitions, capital expenditures and working capital. During the 12 months ended December 31, 2005, we completed seven sales of oil and natural gas properties. As of January 1, 2005, estimated total Proved Reserves net to our interest from these properties included approximately 0.3 Mmbbls of oil and NGLs and 18.4 Bcf of natural gas. The total sales proceeds we received were approximately $45.3 million. During the 12 months ended December 31, 2004, we recorded revenue of approximately $5.0 million and oil and natural gas production costs of approximately $0.9 million on these properties. During the 12 months ended December 31, 2005, we recorded revenues of approximately $3.7 million and oil and natural gas production costs of approximately $1.2 million on these properties through the date of their respective dispositions. We also plan on selling additional non-strategic assets as part of our ongoing business activities.

We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreement are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes and oil and natural gas prices. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may affect our production in future periods. Cash flow from operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. We have experienced increased costs for tubular goods and for certain services during 2004 and 2005. Further, we have encountered difficulties in contracting for drilling rigs and other services due to high demand. Currently, we do not believe that these conditions have had a significant impact upon our capital expenditures programs or our results of operations. If these conditions continue, however, projects may be delayed due to lack of services or materials or we may have to delay projects to stay within our capital budget.

In accordance with the terms of the indenture governing our senior notes, at the time of the closing of the Addison disposition, the security interest of the holders of our senior notes in two-thirds of the common stock of Addison was released and a second lien security interest (behind the first lien security interest under our credit agreement) was effected in $120.6 million of cash equivalents, which represented two-thirds of the net cash proceeds from the sale of the Addison stock. An additional $75.9 million of proceeds from the Addison disposition were applied to temporarily pay down borrowings under our credit agreement to a nominal amount. The remaining Addison disposition proceeds of $130.3 million were invested in short-term investments as permitted under our credit agreement and the indenture governing our senior notes. The net cash proceeds from the Addison disposition as determined under the indenture governing our senior notes was $326.8 million and may be used only in accordance with the terms of the indenture. Section 4.07 of the indenture provided that the net cash proceeds from an asset disposition must be used to permanently reduce debt, reinvest in our business or make an offer to the holders to repurchase their senior notes. As of November 2, 2005, all but $120.6 million of net proceeds had been used to repay debt or have been reinvested in our business.

On November 2, 2005, we commenced an offer to the holders of senior notes to repurchase up to $120.6 million of senior notes at 100% of the principal amount plus accrued and unpaid interest of the notes pursuant to Section 4.07 of the indenture. Simultaneously therewith, we commenced an offer to repurchase all outstanding senior notes at 101% of the principal amount plus accrued and unpaid interest in connection with the change of control provision contained in the indenture as a result of the Equity Buyout. Upon completion of the offer to repurchase related to the Addison sale on December 7, 2005, the second lien security interest on $120.6 million of the proceeds from the sale and the general restrictions under section 4.07 of the indenture on the entire proceeds terminated.

7¹/4% senior notes due January 15, 2011

On January 20, 2004, we issued $350.0 million principal amount of our 7¹/4% senior notes due January 15, 2011 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. Approximately $168.3 million of the proceeds of the issuance of the senior notes was used to finance the acquisition of outstanding common stock, options and warrants of North Coast along with associated fees and expenses. Of the remaining proceeds, $113.8 million was used to repay a portion of our debt under our U.S. credit agreement, North Coast's credit facility indebtedness and accrued interest and fees, $50.1 million was used to repay in full principal and interest on our senior term loan, approximately $10.6 million was used to pay fees and costs associated with the offering, with the remainder, approximately $7.2 million, available for general working capital purposes.

On April 13, 2004, we issued an additional $100.0 million principal amount of our 7¹/4% senior notes due January 15, 2011 pursuant to Rule 144A at a price of 103.25% of the principal amount having the same terms and governed by the same indenture as the senior notes issued on January 20, 2004. Of the total proceeds of $103.3 million, approximately $98.8 million was used to repay substantially all of our outstanding indebtedness under the Canadian credit agreement, approximately $1.2 million was used for fees and expenses associated with the offering, with the remainder, approximately $3.3 million, available for general working capital purposes.

As required by the senior notes registration rights agreements, we exchanged the senior notes for a new issue of substantially identical notes registered under the Securities Act. The exchange offer expired on May 28, 2004 and holders of all but $0.3 million of the senior notes accepted our offer. The exchange offer was closed on June 1, 2004.

Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011. Prior to January 15, 2007, we may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the senior notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the senior notes. On November 2, 2005, we commenced two offers to the holders of our senior notes to purchase their senior notes at 100% and 101%, respectively, of the principal amount of the senior notes plus accrued and unpaid interest. The offer at 100% of the principal amount of the senior notes, or the Addison sale offer, was made pursuant to Section 4.07 of the indenture governing the senior notes. Section 4.07 restricted our use of the net proceeds from the sale of Addison. The Addison sale offer was for up to $120.6 million of senior notes, which represented the net proceeds remaining from the sale of Addison. This offer expired on December 2, 2005 and $5,000 in principal amount of senior notes were tendered pursuant to this offer. The remaining net proceeds from the sale of Addison have been released from the pledge of collateral under the indenture and will no longer be restricted as to their use under Section 4.07.

The Equity Buyout constituted a change of control under the indenture governing our senior notes. As required by the indenture, we commenced an offer to purchase all $450.0 million of senior notes outstanding at 101% of the principal amount plus accrued and unpaid interest through the date

of purchase. The change of control offer expired on December 9, 2005 and $5.3 million in principal amount of senior notes were tendered, which was paid with available cash on hand, including the remaining net proceeds from the sale of Addison. As a result of the Equity Buyout, the carrying value of our senior notes was increased to $468.0 million, the fair value of the senior notes on October 3, 2005.

The indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:

•: incur or guarantee additional debt and issue certain types of preferred stock;
•: pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
•: make investments;
•: create liens on our assets;
•: enter into sale/leaseback transactions;
•: create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
•: engage in transactions with our affiliates;
•: transfer or issue shares of stock of subsidiaries;
•: transfer or sell assets; and
•: consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

On February 14, 2006, concurrent with the closing of our IPO, TXOK and its subsidiaries became restricted subsidiaries under and guarantors of the senior notes.

Credit agreement

On September 30, 2005, we entered into the Fourth Amendment to the credit agreement, which amended the credit agreement to, among other things (i) permit the acquisition of EXCO Holdings by Holdings II, (ii) adjust the restriction on sales of assets by the borrowers and certain subsidiary guarantors under the credit agreement and the application of the proceeds from such sales of assets and (iii) permit the redemption of our senior notes pursuant to the terms of the indenture. Pursuant to the interim bank loan incurred by Holdings II in connection with the Equity Buyout on October 3, 2005, total advances under our credit agreement could not exceed $10.0 million until the interim bank loan was repaid in full in connection with our IPO, which closed on February 14, 2006.

At December 31, 2005, we had $1,000 of outstanding indebtedness under our credit agreement. At December 31, 2005, the six month LIBOR rate was 4.70%, which would result in an interest rate of approximately 5.95% on any new indebtedness we may incur under the credit agreement.

On March 17, 2006, our credit agreement was amended and restated resulting in a new borrowing base of $750.0 million reflecting the addition of the TXOK assets. Using cash and funding under this amended and restated credit facility we repaid in full and terminated the TXOK credit facility. TXOK and its subsidiaries have become guarantors of our credit agreement. The amendment also provided for an extension of the credit agreement maturity date to December 31, 2010. The borrowing base will be redetermined each November 1 and May 1, beginning November 1, 2006. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. Financial covenants under the amended credit agreement require that we:

•: maintain a consolidated current ratio (as defined under our credit agreement) of at least 1.0 to 1.0 at the end of any fiscal quarter; and
•: not permit our ratio of consolidated indebtedness to consolidated EBITDAX (as defined under our credit agreement) to be greater than 3.5 to 1.0 at the end of each fiscal quarter.

Borrowings under our previous amended and restated credit agreement were collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. As of March 17, 2006, borrowings are now collateralized by a first lien mortgage providing a security interest in the value of our proved reserves which is at least 125% of the aggregate commitment. The aggregate commitment is the lesser of (i) $1.25 billion and (ii) the borrowing base, however, the initial aggregate commitment is $300.0 million. This aggregate commitment minimum of $300.0 million can be raised, from time to time, up to the borrowing base of $750.0 million at our sole discretion.

At our option, borrowings under our new amended and restated credit agreement accrue interest at one of the following rates:

•: the sum of (i) the greatest of the administrative agent's prime rate, the base CD rate plus 1.0% or the federal funds effective rate plus 0.50% and (ii) an applicable margin, which ranges from 0.0% up to 0.75% depending on our borrowing usage; or
•: the sum of (i) LIBOR multiplied by the statutory reserve rate and (ii) an applicable margin, which ranges from 1.0% up to 1.75% depending on our borrowing usage.

As of March 28, 2006, we had $104.0 million of outstanding indebtedness under our credit agreement.

Financial covenants and ratios. Our previous amended and restated credit agreement contained certain financial covenants and other restrictions which required that we:

•: maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreement) of at least 1.0 to 1.0 at the end of any fiscal quarter;
•: not permit our ratio of consolidated funded debt to consolidated EBITDA (as defined under our credit agreement) to be greater than (i) 4.35 to 1.00 at the end of each fiscal quarter ending on or before March 31, 2005 and (ii) 4.00 to 1.00 on June 30, 2005 and at the end of each fiscal quarter thereafter;
•: not permit our ratio of consolidated funded debt (other than the senior notes) to consolidated EBITDA (as defined under our credit agreement) to be greater than (i) 3.25 to 1.0 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 3.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter; and
•: not permit our ratio of consolidated EBITDA to consolidated interest expense (as defined under our credit agreement) to be less than 2.5 to 1.0 at the end of each fiscal quarter.

Additionally, our previous and new credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and a prohibition on the payment of dividends on our common stock.

As of December 31, 2005, we were in compliance with the covenants contained in our previous credit agreement.

Senior term loan. On October 17, 2003, we entered into a $50.0 million senior term credit agreement. We borrowed all $50.0 million under the senior term agreement and we used the proceeds to repay a portion of our indebtedness under our credit agreement. The senior term loan was paid in full on January 27, 2004 from the proceeds of the $350.0 million of 7¹/4% senior notes issued on January 20, 2004.

Dividend restrictions. We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreement prohibits payment of dividends and the indenture governing our senior notes contains restrictions related to payment of dividends on our common stock. Even if our credit agreement and the indenture governing our senior notes permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

Interim bank loan

See "—Off balance sheet arrangements" and "Note 6. Long term debt and interim bank loan."

Derivative financial instruments

We may use derivative financial instruments to manage exposure to commodity prices, foreign currency and interest rate risks. Our objectives for holding derivatives are to minimize risks using the most effective methods to eliminate or reduce the impacts of these exposures.

Commodity price risk management activities

Our production is generally sold at prevailing market prices. However, we periodically enter into commodity price risk management contracts for a portion of our production to support our acquisition strategy and when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.

Our objective in entering into commodity price risk management contracts is to manage price fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. During 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 production. We also entered into new commodity price risk management contracts at higher prices.

As of December 31, 2005, we had contracts in place for the volumes and prices shown in the table below:

	Swaps
(in thousands, except average contract prices)	NYMEX gas volume- Mmbtus	Weighted average contract price per Mmbtu		NYMEX oil volume- Bbls	Weighted average contract price per Bbl
Q1 2006	3,555	$	7.34	59	$	67.51
Q2 2006	3,595		6.74	59		67.32
Q3 2006	3,634		6.75	60		66.92
Q4 2006	3,634		6.90	59		66.44
2007	12,410		6.58	201		64.99
2008	10,980		7.62	183		63.00
2009	1,825		4.51	—		—
2010	1,825		4.51	—		—
2011	1,825		4.51	—		—
2012	1,830		4.51	—		—
2013	1,825		4.51	—		—

Our commodity price risk activities, on a pro forma basis including TXOK, as of December 31, 2005 are shown in the following tables:

	Swaps
(in thousands, except average contract prices)	NYMEX gas volume- Mmbtus	Weighted average contract price per Mmbtu		Basis protection volume- Mmbtus	Weighted average differential to NYMEX			NYMEX oil volume- Bbls	Weighted average contract price per Bbl
Q1 2006	5,025	$	9.21	1,350	$	(0.32	)	87	$	67.02
Q2 2006	4,840		7.70	1,365		(0.32	)	84		66.94
Q3 2006	4,694		7.57	1,380		(0.32	)	82		66.68
Q4 2006	4,554		7.69	1,380		(0.32	)	81		66.32
2007	20,570		7.84	—		—		369		64.63
2008	17,820		8.07	—		—		327		62.67
2009	7,705		7.14	—		—		120		60.80
2010	6,985		6.63	—		—		108		59.85
2011	1,825		4.51	—		—		—		—
2012	1,830		4.51	—		—		—		—
2013	1,825		4.51	—		—		—		—

	Floor
	Floor						Ceiling
		Weighted average contract price per Mmbtu			Weighted average contract price per Bbl		Ceiling
(in thousands, except average contract prices)	Gas volume- Mmbtus	Weighted average contract price per Mmbtu		Oil volume- Bbls	Weighted average contract price per Bbl		Gas volume- Mmbtus	Weighted average contract price per Mmbtu		Oil volume- Bbls	Weighted average contract price per Bbl
Q1 2006	1,350	$	6.15	27	$	50.35	1,350	$	10.00	27	$	60.00
Q2 2006	1,365		6.15	27		50.53	1,365		10.00	27		60.00
Q3 2006	1,380		6.15	27		50.53	1,380		10.00	27		60.00
Q4 2006	1,380		6.15	27		50.53	1,380		10.00	27		60.00

Off-balance sheet arrangements

On October 3, 2005, Holdings II, which subsequently merged into EXCO Holdings, entered into the interim bank loan agreement with JPMorgan Chase Bank, N.A., as agent for certain lenders, in connection with the Equity Buyout. The principal amount outstanding of the interim bank loan was $350.0 million. Pursuant to the terms of the agreement, we agreed to redeem all of our outstanding senior notes if the interim bank loan is not repaid on or prior to July 3, 2006. Upon completion of the redemption, if any, we and our subsidiaries would deliver guarantees of the exchange notes issuable by EXCO Holdings upon maturity of the interim bank loan. On February 14, 2006, upon closing of our IPO, EXCO Holdings was merged with and into us. A portion of the proceeds from the IPO were used to repay this loan, together with accrued interest.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at December 31, 2005:

	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
Contractual obligations:
Long-term debt—senior notes(1)	$	—	$	—	$	—	$	444,720	$	444,720
Long-term debt—credit agreement(2)		—		—		1		—		1
Operating leases		3,284		6,208		4,316		856		14,664
Derivative financial instruments(3)		53,189		59,105		11,292		11,009		134,595
Drilling/work commitments		26,040		12,592		—		—		38,632

Total contractual cash obligations	$	82,513	$	77,905	$	15,609	$	456,585	$	632,612

(1): Our senior notes are due on January 15, 2011. The annual interest obligation is $32.2 million.
(2): Our credit agreement was amended and restated on March 17, 2006 and matures on December 31, 2010. As of March 28, 2006, $104.0 million was outstanding under our credit agreement.
(3): Derivative financial instruments represent net liabilities for oil and natural gas commodity derivatives that were valued as of December 31, 2005. The ultimate settlement amounts of our derivative financial instruments are unknown because they are subject to continuing market risk. See "—Quantitative and qualitative disclosure about market risk" and "Note 13. Derivative financial instruments" of the notes to our consolidated financial statements for additional information regarding our derivative financial instruments.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates charged on borrowings and earned on cash equivalent investments, and adverse changes in the market value of marketable securities. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.

Commodity price risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile.

The following table sets forth our commodity price risk management activities as of December 31, 2005:

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at December 31, 2005
Natural Gas:
Swaps:
2006	14,418	$	6.93	$	(54,107	)
2007	12,410		6.58		(42,560	)
2008	10,980		7.62		(16,860	)
2009	1,825		4.51		(6,267	)
2010	1,825		4.51		(5,025	)
2011	1,825		4.51		(4,149	)
2012	1,830		4.51		(3,627	)
2013	1,825		4.51		(3,233	)

Total Natural Gas	46,938				(135,828	)

Oil:
Swaps:
2006	237		67.04		918
2007	201		64.99		214
2008	183		63.00		101

Total Oil	621				1,233

Total Oil and Natural Gas				$	(134,595	)

Our commodity price risk activities, on a pro forma basis including TXOK, as of December 31, 2005 are shown in the following table:

(in thousands, except prices and differentials)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Weighted average differential to NYMEX			Fair value at December 31, 2005
Natural Gas:
Swaps:
2006	19,113	$	8.06				$	(50,595	)
2007	20,570		7.84					(46,493	)
2008	17,820		8.07					(20,670	)
2009	7,705		7.14					(9,542	)
2010	6,985		6.63					(7,582	)
2011	1,825		4.51					(4,149	)
2012	1,830		4.51					(3,627	)
2013	1,825		4.51					(3,233	)

	77,673

Floor:
2006	5,475		6.15					277

	5,475

Ceiling:
2006	5,475		10.00					(8,717	)

	5,475

Basis Protection Swaps:
2006	5,475			$	(0.32	)		4,903

	5,475

Total Natural Gas								(149,428	)

Oil:
Swaps:
2006	334		66.75					1,208
2007	369		64.63					268
2008	327		62.67					84
2009	120		60.80					(4	)
2010	108		59.85					24

	1,258

Floor:
2006	108		50.35					114

	108

Ceiling:
2006	108		60.00					(732	)

	108

Total Oil								962

Total Oil and Natural Gas							$	(148,466	)

At December 31, 2005, the average forward NYMEX oil prices per Bbl for calendar 2006 and for 2007 were $63.19 and $63.98, respectively, and the average forward NYMEX natural gas prices per Mmbtu for calendar 2006 and for 2007 were $10.77 and $10.26, respectively.

Realized gains or losses from the settlement of derivative financial instruments are recorded in our financial statements as increases or decreases in commodity price risk management activities. For example, using the oil swaps in place at December 31, 2005, if the settlement price exceeded the actual weighted average strike price of $67.04, then a reduction in commodity price risk management activities revenue would have been recorded for the difference between the settlement price and $67.04 multiplied by the hedged volume of 237,000 Bbls. Conversely, if the settlement price was less than $67.04, then an increase in commodity price risk management activities revenue would have been recorded for the difference between the settlement price and $67.04 multiplied by the hedged volume of 237,000 Bbls. For example, for a hedged volume of 237,000 Bbls, if the settlement price was $66.04, then commodity price risk management activities revenue would have decreased by $0.2 million. Conversely, if the settlement price was $68.04, commodity price risk management activities revenue would have increased by $0.2 million.

Interest rate risk

At December 31, 2005, our exposure to interest rate changes related primarily to borrowings under our credit agreement and interest earned on short-term investments. The interest rate is fixed at 7¹/4% on our $450.0 million in senior notes. As of December 31, 2005, we were not using any derivatives to manage interest rate risk. Interest is payable on borrowings under our credit agreement based on a floating rate as more fully described in "Management's discussion and analysis of financial condition and results of operations—Our liquidity, capital resources and capital commitments." At December 31, 2005, we had $1,000 in outstanding borrowings under our credit agreement. On February 14, 2006, we increased our borrowing under our credit facility to $65.0 million and subsequently repaid $44.5 million of that increase on February 21, 2006. On March 17, 2006, we borrowed $123.0 million under our credit agreement and used these borrowings to repay in full the TXOK credit facility. This increased the outstanding balance under our credit agreement to $143.5 million. As of March 28, 2006, our outstanding balance under our credit agreement is $104.0 million. The interest rate under our credit agreement as of that date is 5.8%. A 1% change in interest rates based on the borrowings as of March 28, 2006 would result in an increase or decrease in our interest costs of $1.0 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

The interest rate on the $350.0 million interim bank loan was a fixed rate of 10.0%. While EXCO Resources is not the named obligor on the loan, "push-down" accounting requires the debt to be reflected on our consolidated balance sheet. Upon closing of the IPO on February 14, 2006, this interim bank loan, together with accrued interest, was repaid in full.

The TXOK credit facility was a $500.0 million revolving credit facility, subject to a semi-annually determined borrowing base. The initial borrowing base was $325.0 million, of which approximately $308.8 million was drawn down by TXOK to acquire ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C. Concurrently with the closing of the IPO, approximately $185.8 million in borrowings were repaid under the TXOK credit facility which left $123.0 million outstanding on February 14, 2006. Upon the redemption of the TXOK preferred stock on February 14, 2006, TXOK became a wholly-owned subsidiary of EXCO Resources. TXOK and its subsidiaries were parties to the TXOK credit facility, which as of February 14, 2006 was guaranteed by EXCO and its subsidiaries. On March 17, 2006, the $123.0 million outstanding under the TXOK credit facility was repaid in full plus accrued and unpaid interest and this facility was terminated.

The TXOK credit facility bore interest at a fluctuating rate of interest which was a variable margin in excess of reference rates based on either the prime rate or LIBOR. The margin increased with the

borrowing base usage under the TXOK credit facility. The TXOK credit facility was set to mature on September 27, 2009 and was secured by a first priority lien and security interest in TXOK's oil and natural gas properties as well as the capital stock of its subsidiaries. The TXOK credit facility was guaranteed by all existing and future direct or indirect material domestic subsidiaries of TXOK as well as by EXCO and its subsidiaries. The interest rate on the TXOK credit facility was 5.8% on February 14, 2006. A 1% change in the interest would result in an increase or decrease in our interest costs of $1.2 million per year.

Marketable securities risk

As a result of our sale of Addison, we have a substantial cash position as of December 31, 2005. In addition, we only have a nominal amount of indebtedness outstanding under our credit agreement. In compliance with the indenture governing our senior notes, we have invested our cash in short-term commercial paper having an average maturity of 30 days or in overnight funds at J.P. Morgan Securities Inc. The commercial paper is issued by issuers having a credit rating of A1/P1 or better. Our principal risks with respect to these investments are interest rate risk and default risk. At December 31, 2005, we had approximately $187.5 million of such cash equivalent investments. A 1% change in market value would affect interest on these investments by approximately $1.9 million per year. Concurrently with the closing of the IPO, all of our commercial paper investments were liquidated and used to partially repay outstanding indebtedness.

Foreign currency exchange rate risk

At December 31, 2005, we had a current receivable in the amount of Cdn. $21.5 million ($18.5 million) related to the sale of Addison that is denominated in Canadian dollars. Foreign currency exchange gains and/or losses related to these amounts have not been significant. The receivable is translated monthly using current exchange rates, with any resulting unrealized transaction gain or loss being recognized as other income (expense) in our statement of operations. As of December 31, 2005, we were not using any derivatives to manage foreign currency exchange rate risk.

Equity price risk

Our investments in marketable equity securities are recorded at market value. We consider these investments to be "available for sale," which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investments is "other than temporary." As of December 31, 2005, we had no investments in marketable equity securities.

Other market risk

During 2000 and through September 2001, we entered into several swap transactions with Enron North America Corp., an affiliate of Enron Corp. On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court. We terminated our Enron hedges and discontinued hedge accounting for our Enron derivatives effective December 5, 2001. At July 29, 2003, the date of the going private transaction, we had valued our asset from Enron at $2.8 million, or approximately 20% of the value on the day we terminated our positions. This valuation was based on the low range of informal offers we received for our position with Enron and other market information. In April 2004, we sold this claim to a third party for approximately $4.7 million.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EXCO RESOURCES, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Contents

Reports of Independent Registered Public Accounting Firm

Consolidated balance sheets at December 31, 2004 and 2005

Consolidated statements of operations for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, and 90 day period from October 3, 2005 to December 31, 2005

Consolidated statements of cash flows for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, and 90 day period from October 3, 2005 to December 31, 2005

Consolidated statements of changes in shareholder's equity for the 209 day period from January 1, 2003 to July 8, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, and 90 day period from October 3, 2005 to December 31, 2005

Consolidated statements of comprehensive income (loss) for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, and 90 day period from October 3, 2005 to December 31, 2005

Notes to consolidated financial statements

Financial information for the periods prior to July 29, 2003, the date of our going private transaction, represents predecessor (Public Predecessor) basis financial statements. Financial information for the 156 day period from July 29, 2003 to December 31, 2003, calendar year 2004, and the 275 day period from January 1, 2005 to October 2, 2005, represents predecessor (Private Predecessor) basis financial statements for the period prior to our Equity Buyout transaction. Beginning October 3, 2005, the effective date of the Equity Buyout, the accompanying consolidated financial statements reflect a stepped up (Successor) basis of accounting to reflect the purchase of EXCO Resources by Holdings II. See "Note 1. Organization" to the consolidated financial statements.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of EXCO Resources, Inc.:

In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of shareholder's equity and of cash flows present fairly, in all material respects, the results of operations and cash flows of EXCO Resources, Inc. and its subsidiaries (Public Predecessor Company) for the period from January 1, 2003 to July 28, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations," as of January 1, 2003 and changed the manner in which it accounts for asset retirement costs.

/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 18, 2004, except as to
Note 2, for which the date is
November 22, 2005

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of EXCO Resources, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of shareholder's equity and of cash flows present fairly, in all material respects, the financial position of EXCO Resources, Inc. and its subsidiaries (Private Predecessor Company) at December 31, 2004, and the results of their operations and their cash flows for the period from January 1, 2005 to October 2, 2005, the year ended December 31, 2004 and period from July 29, 2003 to December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 31, 2006

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of EXCO Resources, Inc.:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of shareholder's equity and of cash flows present fairly, in all material respects, the financial position of EXCO Resources, Inc. and its subsidiaries (Successor Company) at December 31, 2005, and the results of their operations and their cash flows for the period from October 3, 2005 to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 31, 2006

EXCO Resources, Inc.
Consolidated balance sheets

				December 31,
				2004			2005
(in thousands, except per share amounts)				Private predecessor			Successor
Assets
Current assets:
	Cash and cash equivalents			$	16,007		$	224,991
	Accounts receivable:
		Oil and natural gas sales			18,130			36,895
		Joint interest			2,213			1,081
		Canadian income taxes receivable			—			18,483
		Interest and other			418			12,189
		Related party			—			2,621
	Deferred income taxes				—			29,968
	Deferred costs of intial public offering				—			3,380
	Oil and natural gas derivatives				242			—
	Marketable securities				69			—
	Other				3,962			10,898
	Current assets of discontinued operations				34,807			—

			Total current assets		75,848			340,506

Oil and natural gas properties (full cost accounting method):
	Unproved oil and natural gas properties				18,829			53,121
	Proved developed and undeveloped oil and natural gas properties				454,328			873,595
	Accumulated depreciation, depletion and amortization				(31,707	)		(13,281	)

	Oil and natural gas properties, net				441,450			913,435

Gas gathering, office and field equipment, net					27,014			33,271
Assets of discontinued operations					346,926			—
Deferred financing costs, net					10,779			—
Goodwill					19,984			220,006
Other assets					22			419

			Total assets	$	922,023		$	1,507,637

See accompanying notes.

EXCO Resources, Inc.
Consolidated balance sheets (continued)

				December 31,
				2004			2005
(in thousands, except per share amounts)				Private predecessor			Successor
Liabilities and Shareholder's Equity
Current liabilities:
	Interim bank loan			$	—		$	350,000
	Accounts payable and accrued liabilities				21,919			24,781
	Related party payable				—			6,056
	Accrued interest payable				14,877			23,779
	Revenues and royalties payable				7,249			11,266
	Income taxes payable				1,460			901
	Deferred income taxes				710			—
	Current portion of asset retirement obligations				2,418			1,408
	Oil and natural gas derivatives				22,458			53,189
	Current liabilities of discontinued operations				34,604			—

			Total current liabilities		105,695			471,380

Long-term debt					34,500			1
7¹/4% senior notes due 2011					452,953			461,801
Asset retirement obligations and other long-term liabilities					11,534			15,766
Deferred income taxes					15,794			134,602
Oil and natural gas derivatives					25,961			81,406
Liabilities from discontinued operations					71,835			—
Commitments and contingencies					—			—
Shareholder's equity:
	Common stock, $.01 par value: Authorized shares—100,000; Issued and outstanding shares—1,000 at December 31, 2004 and 2005				1			1
	Additional paid-in capital				172,045			326,716
	Retained earnings				10,338			15,964
	Accumulated other comprehensive income:
		Foreign currency translation adjustments			21,384			—
		Unrealized loss on equity investments			(17	)		—

			Total shareholder's equity		203,751			342,681

			Total liabilities and shareholder's equity	$	922,023		$	1,507,637

See accompanying notes.

EXCO Resources, Inc.
Consolidated statements of operations

			Public predecessor			Private predecessor									Successor
(in thousands, except per share data)			For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003			Year ended December 31, 2004			For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 3, 2005 to December 31, 2005
Revenues and other income:
	Oil and natural gas		$	22,403		$	21,767		$	141,993		$	132,821		$	70,061
	Commodity price risk management activities			—			(10,800	)		(50,343	)		(177,253	)		(256	)
	Other income (loss)			(1,129	)		(161	)		1,141			7,075			2,365

		Total revenues and other income		21,274			10,806			92,791			(37,357	)		72,170

Cost and expenses:
	Oil and natural gas production			11,380			7,331			28,256			22,157			8,949
	Depreciation, depletion and amortization			5,125			5,413			28,519			24,687			14,071
	Accretion of discount on asset retirement obligations			320			205			800			617			226
	General and administrative (includes $3.6 million, $44.1 million and $2.2 million of non-cash compensation expense for the period from January 1, 2003 to July 28, 2003, the period from January 1, 2005 to October 2, 2005 and the period from October 3, 2005 to December 31, 2005, respectively)			11,347			3,823			15,275			89,344			6,225
	Interest			1,058			1,921			34,570			26,675			19,414

		Total cost and expenses		29,230			18,693			107,420			163,480			48,885

Income (loss) before income taxes				(7,956	)		(7,887	)		(14,629	)		(200,837	)		23,285
Income tax expense (benefit)				(181	)		(7,764	)		5,126			(63,698	)		7,321

Income (loss) before discontinued operations and cumulative effect of change in accounting principle				(7,775	)		(123	)		(19,755	)		(137,139	)		15,964

Discontinued operations:
	Income (loss) from operations			13,534			6,217			36,274			(4,403	)		—
	Gain on disposition of Addison Energy Inc			—			—			—			175,717			—
	Income tax expense (benefit)			4,982			1,917			10,358			49,282			—

		Income from discontinued operations		8,552			4,300			25,916			122,032			—

Income (loss) before cumulative effect of change in accounting principle				777			4,177			6,161			(15,107	)		15,964
Cumulative effect of change in accounting principle, net of income taxes of $696,000				255			—			—			—			—

Net income (loss)				1,032		$	4,177		$	6,161		$	(15,107	)	$	15,964

Dividends on preferred stock				2,620

Loss on common stock			$	(1,588	)

Basic and diluted loss per share from continuing operations			$	(1.25	)

Basic and diluted net loss per share			$	(0.19	)

Weighted average number of common and common equivalent shares outstanding:
	Basic and diluted			8,084

See accompanying notes.

EXCO Resources, Inc.
Consolidated statements of cash flows

				Public predecessor			Private predecessor									Successor
(in thousands)				For the 209 Day period from January 1, 2003 to July 28, 2003			For the 156 Day period from July 29, 2003 to December 31, 2003			Year ended December 31, 2004			For the 275 Day period from January 1, 2005 to October 2, 2005			For the 90 Day period from October 3, 2005 to December 31, 2005
				(Revised)			(Revised)			(Revised)
Operating Activities:
Net income (loss)				$	1,032		$	4,177		$	6,161		$	(15,107	)	$	15,964
Income from discontinued operations					(8,552	)		(4,300	)		(25,916	)		(122,032	)		—
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
	Gain on sale of other assets				—			—			—			(373	)		—
	Depreciation, depletion and amortization				5,125			5,413			28,519			24,688			14,071
	Stock option compensation expense				3,567			—			—			44,092			2,207
	Accretion of discount on asset retirement obligations				320			205			800			617			226
	Non-cash change in fair value of derivatives				—			5,423			24,260			114,410			(21,954	)
	Cumulative effect of change in accounting principle, net of income tax				(255	)		—			—			—			—
	Deferred income taxes				—			(7,764	)		3,681			(59,467	)		15,654
	Amortization of deferred financing costs				358			100			3,859			1,320			2,381
	Proceeds from sale of Enron claim				—			—			4,750			—			—
	Income from derivative ineffectiveness and terminated hedges				(187	)		—			—			—			—
	(Gains) losses from sales of marketable securities				(245	)		30			(14	)		3			—
	Other, net				205			(12	)		—			—			—
		Effect of changes in:
			Accounts receivable		1,553			4,983			(2,487	)		(24,512	)		(2,533	)
			Other current assets		(1,419	)		404			(1,350	)		(343	)		1,097
			Accounts payable and other current liabilities		(530	)		1,688			21,599			25,456			(19,373	)
Net cash provided by (used in) operating activities of discontinued operations					19,446			11,373			54,771			(69,772	)		—

Net cash provided by (used in) operating activities					20,418			21,720			118,633			(81,020	)		7,740

Investing Activities:
Acquisition of North Coast Energy, Inc., less cash acquired					—			—			(215,133	)		—			—
Additions to oil and natural gas properties, gathering systems and equipment					(4,201	)		(21,722	)		(139,521	)		(151,144	)		(13,207	)
Proceeds from disposition of property and equipment					6,020			2,303			51,865			46,010			(393	)
Advances/investments with affiliates					—			1,949			151			—			—
Proceeds from sales of marketable securities					422			1,393			1,296			59			—
Other investing activities					(1	)		467			—			209			—
Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415 (discontinued operations)					—			—			—			443,397			—
Net cash used in investing activities of discontinued operations					(25,760	)		(22,918	)		(79,983	)		(442	)		—

Net cash provided by (used in) investing activities					(23,520	)		(38,528	)		(381,325	)		338,089			(13,600	)

Financing Activities:
Proceeds from long-term debt					20,638			58,520			546,350			41,300			9,999
Payments on long-term debt					(11,750	)		(56,000	)		(158,070	)		(148,247	)		(15,279	)
Proceeds from exercise of stock options					12,737			—			—			—			—
Purchase of common stock from employees in connectioin with the merger					(17,874	)		—			—			—			—
Purchase of director and employee stock options in connection with the merger					(3,567	)		—			—			—			—
Payment of fees and expenses in connection with the merger					(563	)		—			—			—			—
Preferred stock dividends					(2,620	)		—			—			—			—
Deferred financing costs					(1,136	)		(1,592	)		(13,431	)		—			—
Other financing activities					172			1			—			—			—
Net cash provided by (used in) financing activities of discontinued operations					13,945			14,035			(91,397	)		59,601			—

Net cash provided by (used in) financing activities					9,982			14,964			283,452			(47,346	)		(5,280	)

Net increase (decrease) in cash					6,880			(1,844	)		20,760			209,723			(11,140	)
Effect of exchange rates on cash and cash equivalents					58			297			(1,685	)		—			—
Cash at beginning of period					1,942			8,880			7,333			26,408			236,131

Cash at end of period including cash of discontinued operations					8,880			7,333			26,408			236,131			224,991
Cash of discontinued operations at end of period					1,697			3,961			10,401			—			—

Cash at end of period				$	7,183		$	3,372		$	16,007		$	236,131		$	224,991

Supplemental Cash Flow Information:
Interest paid				$	618		$	1,658		$	17,102		$	33,099		$	124

Income taxes paid				$	—		$	—		$	—		$	38,213		$	15,500

Supplemental non cash investing:
Capitalized stock option compensation				$	—		$	—		$	—		$	—		$	1,034

See accompanying notes.

EXCO Resources, Inc.
Consolidated statements of changes in shareholder's equity

	5% Preferred Stock					Common Stock									Notes receivable - -officers and employees									Accumulated other comprehensive income (loss)
(in thousands)	5% Preferred Stock					Common Stock			Additional paid-In capital			Deferred compensation						Treasury stock			Retained earnings (deficit)						Total shareholders' equity
(in thousands)	Shares		Amount			Shares	Amount		Additional paid-In capital			Deferred compensation						Treasury stock			Retained earnings (deficit)						Total shareholders' equity
Public predecessor:
Balance, December 31, 2002	5,005		$	101,175		7,263	$	145	$	53,107		$	(705	)	$	(173	)	$	(3,562	)	$	(44,399	)	$	(5,704	)	$	99,884
Conversion of 5% Preferred Stock	(5,005	)		(101,175	)	5,005		100		101,074			—			—			—			—			—			(1	)
Exercise of stock options and warrants	—			—		1,133		23		12,716			—			—			—			—			—			12,739
Repayment of note for stock	—			—		—		—		—			—			173			—			—			—			173
Deferred compensation	—			—		—		—		(594	)		—			—			—			—			—			(594	)
Amortization of deferred compensation	—			—		—		—		—			705			—			—			—			—			705
Purchase of treasury stock	—			—		—		—		—			—			—			(17,874	)		—			—			(17,874	)
Dividends on preferred stock	—			—		—		—		—			—			—			—			(2,620	)		—			(2,620	)
Foreign currency translation adjustments	—			—		—		—		—			—			—			—			—			2,791			2,791
Equity investments	—			—		—		—		—			—			—			—			—			590			590
Hedging activities	—			—		—		—		—			—			—			—			—			(1,602	)		(1,602	)
Net income	—			—		—		—		—			—			—			—			1,032			—			1,032

Balance, for the 209 day period ended July 28, 2003, public predecessor	—		$	—		13,401	$	268	$	166,303		$	—		$	—		$	(21,436	)	$	(45,987	)	$	(3,925	)	$	95,223

Private predecessor:
Beginning Balance, July 29, 2003.	—		$	—		1	$	1	$	—		$	—		$	—		$	—		$	—		$	—		$	1
Capital contributed by parent	—			—		—		—		172,045			—			—			—			—			—			172,045
Foreign currency translation adjustments	—			—		—		—		—			—			—			—			—			7,680			7,680
Equity investments	—			—		—		—		—			—			—			—			—			(34	)		(34	)
Net income	—			—		—		—		—			—			—			—			4,177			—			4,177

Balance, for the 156 day period ended December 31, 2003	—			—		1		1		172,045			—			—			—			4,177			7,646			183,869
Foreign currency translation adjustments	—			—		—		—		—			—			—			—			—			13,704			13,704
Equity investments	—			—		—		—		—			—			—			—			—			17			17
Net income	—			—		—		—		—			—			—			—			6,161						6,161

Balance, December 31, 2004	—			—		1		1		172,045			—			—			—			10,338			21,367			203,751
Foreign currency translation adjustments	—			—		—		—		—			—			—			—			—			(21,399	)		(21,399	)
Unrealized gain on equity investments	—			—		—		—		—			—			—			—			—			32			32
Stock based compensation	—			—		—		—		44,092			—			—			—			—			—			44,092
Net loss	—			—		—		—		—			—			—			—			(15,107	)		—			(15,107	)

Balance, for the 275 day period ended October 2, 2005, public predecessor	—		$	—		1	$	1	$	216,137		$	—		$	—		$	—		$	(4,769	)	$	—		$	211,369

Successor:
Acquisition by Holdings II	—		$	—		1	$	1	$	323,199		$	—		$	—		$	—		$	—		$	—		$	323,200
Stock based compensation	—			—		—		—		3,517			—			—			—			—			—			3,517
Net income	—			—		—		—		—			—			—			—			15,964			—			15,964

Balance, for the 90 day period ended December 31, 2005	—		$	—		1	$	1	$	326,716		$	—		$	—		$	—		$	15,964		$	—		$	342,681

See accompanying notes.

EXCO Resources, Inc.
Consolidated statements of comprehensive income (loss)

			Public predecessor			Private predecessor								Successor
(in thousands)			For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003			Year Ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 3, 2005 to December 31, 2005
Net income (loss)			$	1,032		$	4,177		$	6,161	$	(15,107	)	$	15,964
Other comprehensive income (loss):
	Hedging activities:
		Effective changes in fair value, net of tax of $0		14,701			—			—		—			—
		Reclassification adjustments for settled contracts, net of tax of $0		(14,540	)		—			—		—			—
		Amortization of terminated contracts, net of tax of $0		(1,763	)		—			—		—			—

Total hedging activities				(1,602	)		—			—		—			—
Reclassification adjustment of foreign currency translation adjustment				2,791			7,680			13,704		—			—
Reclassification adjustment for impairment of marketable securities				—			—			—		—			—
Unrealized gain (loss) on equity investments, net of taxes of $0, $(18) and $9 for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from from July 29, 2003 to December 31, 2003 and the year ended December 31, 2004				590			(34	)		17		—			—

Total comprehensive income (loss)			$	2,811		$	11,823		$	19,882	$	(15,107	)	$	15,964

See accompanying notes.

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EXCO Resources, Inc.

Notes to consolidated financial statements

1. Organization

EXCO Resources, Inc., a Texas corporation, was formed in October 1955 and became a wholly-owned subsidiary of EXCO Holdings Inc. (Holdings) on July 29, 2003 pursuant to the going private transaction described below. On October 3, 2005, Holdings was acquired by EXCO Holdings II Inc. pursuant to the Equity Buyout described below. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States and, until February 10, 2005, Canada. We also act as the operator of some of these properties and receive overhead reimbursement fees as a result.

The going private transaction

Holdings, a Delaware corporation, was formed March 4, 2003 and had no operations prior to July 29, 2003 when it acquired all of the outstanding common stock and stock options of EXCO Resources, Inc. (EXCO, Resources, we) (the going private transaction). Prior to July 29, 2003, EXCO was a public company whose common stock was traded on the NASDAQ National Market (NASDAQ). For the period from March 4, 2003 (date of inception) and after the acquisition of EXCO on July 29, 2003, through October 3, 2005, the date of the Equity Buyout, Holdings and EXCO are collectively referred to herein as the Company. On July 29, 2003, pursuant to an Agreement and Plan of Merger, ER Acquisition, Inc., a Texas corporation, and wholly-owned subsidiary of Holdings merged into Resources. Prior to July 29, 2003 EXCO's financial statements are referred to as Public Predecessor and subsequent to that date through October 3, 2005, the date of the Equity Buyout, they are referred to as Private Predecessor and include purchase accounting adjustments related to this change in control.

Holdings was formed by our chairman and chief executive officer, Douglas H. Miller, and his buying group for the purpose of entering into the merger agreement. The holders of EXCO's common stock, other than Holdings and its subsidiaries, received cash of $18.00 per share. The buyout of EXCO was funded with borrowings from EXCO's existing credit facilities of approximately $53.6 million and approximately $172.0 million of Holdings' equity. The equity capital for Holdings was provided by:

•: Cerberus Capital Management, L.P., or Cerberus, an investment management firm—$106.5 million in cash;
•: other institutional investors—$34.3 million in cash;
•: certain members of EXCO's management—$10.5 million in cash and the contribution of EXCO shares; and
•: other institutional and other investors—$20.7 million in cash and the contribution of EXCO shares.

Upon completion of the merger transaction, EXCO's common stock was delisted from trading on the NASDAQ or any other exchange and EXCO's common stock registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934 was terminated.

The total purchase price for EXCO was $353.5 million representing the purchase of all outstanding common stock and stock options including the amounts contributed to Holdings by management and

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key employees and other investors, and liabilities assumed as detailed below and was allocated as follows (in thousands):

Purchase price calculations:
Payments for tendered shares including options		$	195,327
Value of EXCO shares contributed by management			8,429
Value of EXCO shares contributed by other investors			17,966
Assumption of debt			130,003
Merger related costs			1,819

	Total EXCO acquisition costs	$	353,544

Allocation of purchase price:
Oil and natural gas properties—proved		$	358,111
Oil and natural gas properties—unproved			9,967
Goodwill			51,120
Other property and equipment and other assets			3,678
Current assets			36,705
Deferred income taxes(1)			(50,733	)
Accounts payable and accrued expenses			(37,757	)
Asset retirement obligations			(15,744	)
Fair value of oil and natural gas derivatives			(1,803	)

	Total allocation	$	353,544

(1): Represents deferred income taxes recorded at the date of the merger due to differences between the book basis and the tax basis of assets. For book purposes, we had a step-up in basis related to purchase accounting while our existing tax basis carried over.

As a result of the change in control, generally accepted accounting principles (GAAP) requires the acquisition by Holdings to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations." Accordingly, the financial statements for periods subsequent to July 28, 2003, reflect Holdings' stepped-up basis resulting from the acquisition. The aggregate purchase price was allocated to the underlying assets and liabilities based upon the respective estimated fair values at July 29, 2003 (date of acquisition). Carryover basis accounting applies for tax purposes. All financial information presented prior to July 29, 2003 represents the Public Predecessor basis of accounting.

The purchase price allocation resulted in $51.1 million of goodwill, $24.2 million in the EXCO operating segment and $26.9 million in the Canadian geographic operating segment (reflected on the consolidated balance sheet at December 31, 2004 as Assets of discontinued operations). None of the goodwill is deductible for income tax purposes. See "Note 2. Summary of significant accounting policies" for a description of our accounting policies concerning goodwill.

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Pro forma results of operations

The following table reflects the pro forma results of operations as though the merger had been consummated at January 1, 2003:

(in thousands, unaudited)	Year ended December 31, 2003
Revenues and other income	$	32,080
Income before cumulative effect of change in accounting principle		10,169
Net income		10,424

The Equity Buyout

On August 29, 2005, EXCO announced that the Board of Directors of Holdings approved for consideration by the Holdings stockholders the proposed terms of an equity buyout (Equity Buyout) pursuant to a purchase of all of the outstanding shares of capital stock of Holdings by EXCO Holdings II, Inc. (Holdings II), a Delaware corporation controlled by a group of investors led by Douglas H. Miller, the Chairman and Chief Executive Officer of Holdings.

On October 3, 2005, Holdings II completed its purchase of all of the outstanding shares of capital stock of Holdings for an aggregate purchase price of approximately $699.3 million. The Equity Buyout was funded by a combination of (i) $350.0 million of interim loan indebtedness (interim bank loan), including $0.7 million for working capital, (ii) approximately $183.1 million from the issuance of Holdings II common stock to new private equity investors and EXCO employees and (iii) the exchange of Holdings Class A and Class B common stock valued at approximately $166.9 million for Holdings II common stock. Holdings' majority stockholder sold all of its shares for cash. JPMorgan Chase Bank, N.A. was the lead lender under the interim bank loan.

GAAP requires the application of "pushdown accounting" in situations where the ownership of an entity has changed. Holdings II is deemed to be the acquiror of Holdings. The assets and liabilities of Holdings II were recorded at their fair value, and, under Staff Accounting Bulletin (SAB) No. 54, "Pushdown Basis of Accounting in Financial Statements of Subsidiaries Acquired by Purchase", the fair value was allocated as follows:

(in thousands)
Acquisition cost:
	Payments for shares		$	478,836
	Exchange of Holdings II shares for Holdings shares			166,884
	Assumption of senior notes ($452,643 aggregate book value plus $15,357 premium to fair value)			468,000
	Assumption of long-term debt			1
	Less cash assumed of $236,371, less cash compensation payments related to the Equity Buyout			(206,507	)

		Total Holdings acquisition cost	$	907,214

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Allocation of acquisition cost:
	Oil and natural gas properties—proved		$	852,122
	Oil and natural gas properties—unproved			58,573

	Total oil and natural gas properties			910,695
	Gas gathering assets and other equipment			33,073
	Deferred tax asset ($3,471 reclassified to deferred tax liability)			—
	Other assets, reflecting the reduction of deferred debt issuance costs of $8,862 to zero			285
	Goodwill			220,006
	Other current assets			50,898
	Accounts payable and accrued expenses			(44,703	)
	Asset retirement obligations and other long-term liabilities			(17,538	)
	Oil and natural gas derivative liabilities			(156,549	)
	Deferred tax liability of $131,916 at an average marginal tax rate of 39.5%(1), net of $42,963 reclassification of Holdings historical deferred tax asset			(88,953	)

		Total allocation	$	907,214

(1): Marginal tax rate includes federal income taxes at 35.0% plus a blended state tax rate of 4.5%.

As a result of the Equity Buyout, we recorded stock based and other compensation expense for the following items during the 275 day period from January 1, 2005 to October 2, 2005:

•

A non-cash charge of approximately $44.1 million as a result of the acquisition by Holdings II of all of the shares of Class B common stock of Holdings held by members of our management and other employees. The offset to this expense was to Shareholders' Equity as additional paid-in capital. The shareholder agreements governing the Class A and Class B shares of Holdings provided that, upon the occurrence of certain specified events, including a change of control as occurred upon the Equity Buyout:

•: the holders of the Class A shares were to receive the first $175.0 million in proceeds, and
•: the remaining proceeds in excess of the $175.0 million were to be allocated on a pro-rata basis to the holders of the Class A and Class B shares.

For financial accounting purposes, the Class B shares were considered to be a "variable" plan since a holder of the shares had to be employed at the date of a participation event, such as a change of control, to receive fair value for the Class B shares.

•: A charge of $17.8 million for payments made to holders of options to purchase Class A shares of Holdings less options held by the Employee Stock Participation Plan (ESPP). This amount was paid to option holders at the time of the Equity Buyout by Holdings to purchase all stock options outstanding at that time. The amount represents the cumulative difference between the $5.197 per share purchase price for the Equity Buyout for the Class A shares and the exercise price of the outstanding stock options times the number of stock options outstanding.
•: A charge of $8.3 million for payments made to our employees who were participants in the ESPP. This amount was paid at the time of the Equity Buyout and was based upon shares of Holdings Class A and Class B stock that were reserved, but unissued, and options granted to the ESPP under the Holdings' 2004 Long-Term Incentive Plan (the Holdings Plan). All employees on the date of the Equity Buyout who were not direct owners of Holdings Class A or Class B stock received payments under the ESPP. For financial accounting purposes, the ESPP was considered to be a "variable" plan since, to be eligible, a recipient had to be employed at the

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date of the change of control to receive a payment. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.

•: A charge of $2.6 million for accelerated payments made by Holdings to certain employees of EXCO under the Holdings Bonus Retention Plan. The Holdings Bonus Retention Plan was accelerated, paid in full and terminated upon consummation of the Equity Buyout.

Holdings II adopted the 2005 Long-Term Incentive Plan (the 2005 Incentive Plan) which provides for the granting of options to purchase up to 10,000,000 shares of Holdings (formerly Holdings II) common stock. On October 5, 2005, options were granted under the 2005 Incentive Plan to our employees to purchase 4,992,650 shares of Holdings common stock at $7.50 per share. As of December 31, 2005, a total of 4,979,575 options were issued and outstanding. The options expire ten years from the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As a result of the new basis in accounting due to the Equity Buyout, we adopted the provisions of SFAS No. 123(R), "Share-Based Payment" as of October 3, 2005. As a result, we recorded non-cash compensation of $2.2 million as general and administrative expenses and capitalized $1.0 million as oil and natural gas properties during the 90 day period from October 3, 2005 to December 31, 2005.

Merger of Holdings II into Holdings

Promptly following the consummation of the Equity Buyout, Holdings II merged with and into Holdings (Holdings II Merger). As a result of the Holdings II Merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of Holdings common stock. In addition, all shares of Holdings Class A and Class B common stock held by Holdings II were cancelled in connection with the Holdings II Merger. The Equity Buyout was accounted for as a purchase pursuant to SFAS No. 141, which resulted in the assets and liabilities being recorded at their fair value. Holdings II is deemed the accounting acquiror of Holdings.

Pursuant to the Holdings II Merger, the indebtedness incurred by Holdings II to fund the Equity Buyout was assumed by Holdings.

2. Summary of significant accounting policies

Principles of consolidation

The accompanying consolidated balance sheet as of December 31, 2005 and the results of operations, cash flows and comprehensive income for the 90 day period from October 3, 2005 to December 31, 2005 are for EXCO and its subsidiaries and represents the stepped up Successor basis of accounting following the Equity Buyout transaction.

The accompanying consolidated balance sheet as of December 31, 2004 and the results of operations, cash flows and comprehensive income for the 156 day period from July 29, 2003 to December 31, 2003, for the year ended December 31, 2004 and for the 275 day period from January 1, 2005 to October 2, 2005 are for EXCO and its subsidiaries and represent the stepped up Private Predecessor basis of accounting following the going private transaction.

The accompanying consolidated statements of operations, cash flows and comprehensive income for the 209 day period from January 1, 2003 to July 28, 2003 are for EXCO and its subsidiaries and represent the Public Predecessor basis of accounting.

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The financial statements for all periods prior to January 1, 2005 have been restated to reflect the financial position, operations, cash flow and comprehensive income of Addison Energy Inc. (Addison) as discontinued operations.

All intercompany transactions and accounts have been eliminated.

Functional currency

The assets, liabilities and operations of Addison were measured using the Canadian dollar as the functional currency. These assets and liabilities were translated into U.S. dollars using end-of-period exchange rates. Revenue and expenses were translated into U.S. dollars at the average exchange rates in effect during the period. Translation adjustments were deferred and accumulated in other comprehensive income.

Management estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGL reserve volumes, future development, dismantlement and abandonment costs, share-based compensation expenses, estimates relating to certain oil, natural gas and NGL revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management's estimates.

Cash equivalents and marketable securities

We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.

We have evaluated our investment policies in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" and determined that all of our marketable securities, other than cash equivalents, are to be classified as available for sale. Available for sale securities are carried at fair value, with the unrealized gains and losses reported in other comprehensive income. Realized gains and losses are included in other income in the consolidated statement of operations. Declines in value that are considered to be "other than temporary" on available for sale securities are shown separately in the consolidated statement of operations. Realized gains and losses are determined using the first-in, first-out method.

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Concentration of credit risk and accounts receivable

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil, natural gas or NGLs or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to operated wells. Oil, natural gas and NGL sales are generally uncollateralized. We have provided for credit losses in the financial statements and these losses have been within management's expectations. The allowance for doubtful accounts receivable (including current assets of discontinued operations) aggregated $1.5 million and $1.6 million at December 31, 2004 and 2005, respectively. We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our commodity price risk management activities, see "Note 13. Derivative financial instruments."

Derivative financial instruments

We engage in commodity price risk management activities 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 a more predictable cash flow for our development and acquisition activities. These derivatives are not held for trading purposes.

Prior to July 28, 2003, EXCO's derivative financial instruments were designated as cash flow hedges under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." On the date the derivative contract was entered into, it designated the derivative as a hedge. Changes in the fair value of a derivative that was highly effective as a cash flow hedge were recorded in other comprehensive income, until the underlying transactions occur.

EXCO formally documented all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process included linking all derivatives that were designated as cash flow hedges to forecasted transactions. EXCO also formally assessed, both at the hedge's inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were highly effective in offsetting changes in cash flows of hedged items. When it was determined that a derivative was not highly effective as a hedge or that it had ceased to be a highly effective hedge, EXCO discontinued hedge accounting prospectively, as discussed below.

EXCO discontinued hedge accounting prospectively when: (1) it was determined that the derivative was no longer highly effective in offsetting changes in cash flows of a hedged item; (2) the derivative expired or was sold, terminated or exercised; (3) the derivative was not designated as a hedge instrument, because it was unlikely that a forecasted transaction would occur; or (4) management determined that designation of the derivative as a hedge instrument was no longer appropriate.

Effective as of November 30, 2001, EXCO ceased hedge accounting for its hedge transactions then in place with Enron North America Corp., the counterparty to its swap agreements, due to Enron

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North America's bankruptcy filing. See "Note 13. Derivative financial instruments" for a discussion of these derivative transactions.

Effective July 29, 2003, in connection with the going private transaction, we discontinued hedge accounting for all existing derivatives. Currently, we do not designate derivative transactions as hedges for accounting purposes; accordingly, all derivatives are recorded at fair value on our consolidated balance sheets and changes in the fair value of derivative financial instruments including interest rate swaps are recognized currently in our consolidated statements of operations. We continue to designate derivative financial instruments as hedges for income tax purposes.

For the 209 day period from January 1, 2003 to July 28, 2003, EXCO recorded as other income in the statements of operations, a loss of $2.5 million from hedge ineffectiveness. For the 209 day period from January 1, 2003 to July 28, 2003, EXCO also recorded as other income in the statements of operations $1.8 million from derivative transactions for which hedge accounting was discontinued.

Oil and natural gas properties

We have recorded oil and natural gas properties at cost using the full cost method of accounting. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool. Capitalized costs are limited to the aggregate of the after-tax present value of future net revenues plus the lower of cost or fair market value of unproved properties. The full cost pool is comprised of lease and well equipment and exploration and development costs incurred, plus intangible acquired proved leaseholds.

Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not Proved Reserves can be assigned to such properties. At December 31, 2004 and 2005, the $18.8 million and $53.1 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the estimated fair value of undeveloped acreage and possible and probable reserves. We assess our unproved oil and natural gas properties for impairment on a quarterly basis.

Depreciation, depletion and amortization of evaluated oil and natural gas properties is calculated separately for the United States and until February 10, 2005, the Canadian full cost pools using the unit-of-production method based on total Proved Reserves, as determined by independent petroleum reservoir engineers.

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

At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). This ceiling test calculation is done separately for the United States and, until February 10, 2005, the Canadian full cost pools.

The calculation of the ceiling test is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a

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function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

In September 2004, the Securities and Exchange Commission (SEC) issued SAB No. 106, which clarifies the calculation of the full cost ceiling and depreciation, depletion, and amortization of oil and natural gas properties in conjunction with accounting for asset retirement obligations under SFAS No. 143. The guidance in SAB No. 106 has not had a significant impact on our consolidated financial statements.

Gas gathering, office and field equipment

Gas gathering, office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Gathering systems are depreciated over estimated useful lives ranging from 10 to 25 years. Field and office equipment useful lives range from 3 to 15 years.

Goodwill

In accordance with SFAS No. 142, "Goodwill and Intangible Assets", goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, are performed at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. In a February 2005 letter to oil and natural gas companies, the SEC provided guidance concerning the treatment of goodwill in situations when a company sells less than 25% of its proved oil and natural gas reserves in a cost pool. The guidance indicated that such dispositions may trigger a need to evaluate goodwill for impairment under SFAS No. 142. As a result of this guidance, beginning January 1, 2005, we no longer reduce the balance of goodwill for property dispositions of less than 25% of our oil and natural gas reserves unless there is an indication that our goodwill is impaired as a result of the sale.

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The following table reflects our balances for goodwill as of December 31, 2004 and 2005 (in thousands):

Private Predecessor:
Balance as of December 31, 2003	$	24,218
Activity during the year ended December 31, 2004:
Sales of oil and natural gas properties		(2,954	)
Sale of the Enron claim		(1,280	)

Balance as of December 31, 2004(1)	$	19,984

Successor:
Equity Buyout (see "Note 1—Organization")	$	220,006
Activity during the 90 day period from October 3, 2005 to December 31, 2005		—

Balance as of December 31, 2005	$	220,006

(1): Goodwill from the going private transaction was written off as a result of the Equity Buyout.

Environmental costs

Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.

Deferred abandonment and asset retirement obligations

Prior to 2003, EXCO did not provide for site restoration costs on its United States properties as it estimated that salvage values would exceed the asset retirement costs.

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, "Accounting for Asset Retirement Obligations". The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. EXCO adopted the new rules on asset retirement obligations on January 1, 2003. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $5.6 million, recognition of an asset retirement obligation liability of approximately $6.1 million, and a cumulative effect of adoption that increased net income and stockholder's equity by approximately $0.3 million.

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The following is a reconciliation of our asset retirement obligations for the periods indicated (in thousands):

	Public predecessor			Private predecessor									Successor
	For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003			For the year ended December 31, 2004			For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 3, 2005 to December 31, 2005
Asset retirement obligation at beginning of period	$	—		$	6,077		$	6,687		$	13,247		$	14,275
Activity during the period:
Cumulative effect of change in accounting principle		6,164			—			—			—			—
Adjustment to liability due to purchase of EXCO by Holdings in 2003 and Holdings II in 2005		—			444			—			—			1,607
Liabilities incurred during period		37			49			8,462			1,686			51
Liabilities settled during period		(444	)		(88	)		(2,702	)		(1,275	)		(336	)
Accretion of discount		320			205			800			617			226

Asset retirement obligation at end of period		6,077			6,687			13,247			14,275			15,823
Less current portion		—			—			2,418			1,713			1,408

Long-term portion	$	6,077		$	6,687		$	10,829		$	12,562		$	14,415

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

Revenue recognition and gas imbalances

We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2004 and 2005 were not significant.

Capitalization of internal costs

We capitalize as part of our proved developed oil and natural gas properties a portion of salaries and, beginning in October 2005, related share-based compensation for employees who are directly involved in the acquisition and exploitation of oil and natural gas properties. During the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005, we have capitalized $0.5 million, $0.5 million, $1.6 million, $1.2 million and $1.5 million, respectively. Included in the $1.5 million for the 90 day period from October 3, 2005 to December 31, 2005 is $1.0 million of share based compensation resulting from the adoption of SFAS No. 123(R) on October 3, 2006. See "Note 8. Stock transactions" for further discussion.

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Overhead reimbursement fees

We have classified fees from overhead charges billed to working interest owners, including ourselves, of $1.3 million, $0.9 million, $2.1 million, $1.3 million and $0.5 million for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. Our share of these charges was $0.9 million, $0.7 million, $1.5 million, $0.8 million and $0.3 million for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005, respectively, and are classified as oil and natural gas production costs.

Income taxes

Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

Earnings per share

SFAS No. 128, "Earnings per share," requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings per common share for the 209 day period from January 1, 2003 to July 28, 2003 equals the net income plus cumulative effect change in accounting principle less preferred stock dividends divided by the weighted average common shares outstanding during the period. Diluted earnings per common share for the 209 day period from January 1, 2003 to July 28, 2003 equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents assumed to be issued. Common stock equivalents for the 209 day period from January 1, 2003 to July 28, 2003 are shares assumed to be issued if (1) EXCO's outstanding stock options were in-the-money and exercised, and (2) the outstanding 5% convertible preferred stock was converted to common stock.

For the 209 day period from January 1, 2003 through July 28, 2003, EXCO reported a loss from continuing operations of $7.8 million. As a result, the common stock equivalents of director and employee stock options and the 5% convertible preferred stock, which would have increased the weighted average number of shares outstanding by approximately 535,000 and 4,363,000 shares, respectively, are considered to be anti-dilutive and are not considered in the earnings per share calculation due to a loss from continuing operations being reported for that period.

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The following table presents the basic and diluted earnings (loss) per share computations for the 209 day period from January 1, 2003 through July 28, 2003:

(in thousands, except per share amounts)				209 day period ended July 28, 2003
Basic and diluted earnings (loss) per common share:
	Loss from continuing operations			$	(7,775	)
	Dividends of preferred stock				(2,620	)
	Cumulative effect of change in accounting principle				255

		Loss on common stock		$	(10,140	)

	Income from discontinued operations			$	8,552

	Shares:
	Weighted average number of common shares outstanding				8,084

	Basic and diluted earnings (loss) per common share
		Continuing operations		$	(1.25	)
		Discontinued operations			1.06

			Total basic loss per common share	$	(0.19	)

Earnings per share for all periods after July 28, 2003 are not presented since we are wholly-owned by Holdings, and its successor, Holdings II, our parent.

Stock options

On December 16, 2004, FASB issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in our consolidated statements of operations based on their estimated fair values. Pro forma disclosure is no longer an alternative.

Holdings (formerly Holdings II) adopted the 2005 Long-Term Incentive Plan (the 2005 Incentive Plan) which provides for the granting of options to purchase up to 10,000,000 shares of Holdings common stock. New shares will be issued for any stock options exercised. As a result of the new basis in accounting due to the Equity Buyout, we adopted the provisions of SFAS No. 123(R) as of October 3, 2005 in connection with the Equity Buyout. See "Note 8. Stock transactions" for additional information related to the 2005 Incentive Plan. The adoption of SFAS No. 123(R) did not have a cumulative affect on our financial statements as no options were outstanding prior to October 5, 2005.

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

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EXCO elected to continue to utilize the accounting method prescribed by APB 25 until October 3, 2005, under which no compensation cost was recognized, and adopted the disclosure requirements of SFAS 123. As a result, SFAS 123 had no effect on EXCO's results of operations for the 209 day period from January 1, 2003 to July 28, 2003. Stock based compensation expense reflected in the table below for the 209 day period from January 1, 2003 to July 28, 2003, is a result of options issued under EXCO's 1998 Stock Option Plan that were issued subject to shareholders' approval and options that were issued to the management and key employees of Addison. See "Note 8. Stock transactions" for a further description of these stock options.

Had compensation costs for these plans been determined consistent with SFAS No. 123, EXCO's net income and earnings (loss) per share (EPS) would have been adjusted to the following pro forma amounts (See "Note 8. Stock transactions" for assumptions used in fair value method):

(in thousands)	period from January 1, 2003 to July 28, 2003
Net income applicable to common stockholders, as reported	$	(1,588	)
Add: Stock-based compensation expense, as reported (net of taxes)		2,578
Less: Total stock-based compensation expense determined under the fair value method for employee stock awards, net of taxes		(6,969	)

Net income applicable to common stockholders, proforma	$	(5,979	)

Basic and diluted net loss per share, as reported	$	(0.19	)

Basic and diluted net loss per share, proforma	$	(0.74	)

Certain employees were granted Holdings stock options under Holdings' 2004 Long-Term Incentive Plan (the Holdings Plan). The Holdings Plan provides for grants of stock options that could have been exercised for Class A common shares of Holdings. The stock options were to vest upon the earlier of a change in control of Holdings, the consummation of an initial public offering or three years from the date of grant, and expire ten years after the date of grant. Holdings had reserved 12,962,968 shares of its Class A common stock for issuance upon the exercise of stock options. The Equity Buyout was a change of control under the Holdings Plan. All Holdings stock options outstanding on October 3, 2005 (8,671,906 shares) were cancelled upon the payment of an aggregate amount of $17.8 million to the holders of the stock options. This amount was expensed as general and administrative expense during the 275 day period from January 1, 2005 to October 2, 2005.

Effective with the grant of these options on June 3 and June 4, 2004, we elected to utilize the accounting method prescribed by APB 25 under which no compensation expense was required to be recognized upon the issuance of stock options to our employees as the exercise price of the option is equal to or higher than the fair value of the underlying common stock at the date of grant.

Under the minimum value method as prescribed under SFAS No. 123, no compensation expense would have been incurred during the year ended December 31, 2004 from the granting of these stock options and, as such, no pro forma disclosure is required.

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Foreign currency translation

Addison, our former Canadian subsidiary, entered into a long-term note agreement with a U.S. subsidiary of EXCO in the amount of $98.8 million. Addison used the proceeds of this borrowing to repay virtually all of its outstanding indebtedness under its Canadian credit agreement in April 2004. The indebtedness was denominated in U.S. dollars and was repaid upon the sale of Addison on February 10, 2005. Under the provisions of SFAS No. 52 "Foreign Currency Translation", Addison was required to recognize any foreign transaction gains or losses in its statement of operations when translating this liability from U.S. dollars to Canadian dollars. Gain or loss recognized by Addison was not eliminated when preparing EXCO's consolidated statement of operations. As a result, we recorded a non-cash foreign currency transaction gain of $10.8 million during the year ended December 31, 2004 and a non-cash foreign currency loss of $3.5 million for the 275 day period from January 1, 2005 to October 2, 2005. These amounts are included in income (loss) from operations of discontinued operations in the accompanying consolidated statements of operations.

3. Sale of Addison Energy Inc.

On January 17, 2005, our 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 Acquisition, Inc. (Taurus), our wholly-owned subsidiary. The Addison Purchase Agreement provided that EXCO would sell to Purchaser all of the issued and outstanding shares of common stock of Addison Energy Inc. (Addison), which was at that time our wholly-owned Canadian subsidiary. 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 stock and the Addison Notes was Cdn. $551.3 million (U.S. $443.4 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. $45.2 million) was withheld and has been remitted to the Canadian government for potential income taxes that we may owe resulting from the sale of the stock. We have recorded a receivable in the amount of Cdn. $21.5 million (U.S. $18.9 million) for our estimate of the excess of the amount withheld for Canadian income taxes from the sales proceeds over the estimated amount of Canadian income taxes that are actually owed on the gain from the sale. The purchase price was subject to further adjustment based upon, among other items, the final determination of Addison's working capital balance. In June 2005, we adjusted the liability and the gain recognized on the sale by Cdn. $1.6 million (U.S. $1.3 million). In October 2005, we paid the Purchaser the Cdn. $1.6 million (U.S. $1.1 million) in settlement of the working capital balance. The purchase price is also subject to additional adjustments based upon the outcome of Crown royalty and joint venture audits, if any, that may occur in the future that cover periods prior to February 1, 2005.

All severance payments paid or payable in respect of employees terminated up to May 31, 2005 were borne by EXCO. If Purchaser or its affiliates makes an employment offer to a terminated employee and the employee accepts the offer, Purchaser is obligated to pay EXCO an amount equal to

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all severance payments paid to that employee. This obligation was in effect for a period of six months for any employee terminated at closing and for an indefinite period for any employee terminated after closing but prior to May 31, 2005. At closing, Cdn. $2.1 million (U.S. $1.7 million) was deducted from the sales proceeds for severance payments made to Addison employees who were terminated at closing.

We have recognized a gain from the sale of Addison in the amount of U.S. $175.7 million before income tax expense of U.S. $49.3 million related to the gain. The cumulative adjustment resulting from the translation of Addison's financial statements has been eliminated. These amounts were considered in the determination of the gain on the sale.

The net carrying value of Addison's assets and liabilities as of December 31, 2004 are as follows (in thousands of U.S. dollars):

		December 31, 2004
Cash		$	10,401
Other current assets			24,406
Oil and natural gas properties, net			315,144
Gas gathering, office and field equipment, net			267
Goodwill			31,432
Other assets			83

	Total assets		381,733
Current liabilities			34,604
Long-term debt			12,896
Deferred income taxes			43,308
Other liabilities			15,631
	Total liabilities		106,439

Net investment in Addison		$	275,294

The following table presents the summary operating results for Addison, which has been reported as a discontinued operation:

	Public Predecessor		Private Predecessor
(in thousands)	For the 209 day period from January 1, 2003 to July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003		Year ended December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005
Revenues	$	39,109	$	24,426	$	85,219	$	4,490
Costs and expenses		25,575		18,209		48,945		8,893

Income (loss) from operations		13,534		6,217		36,274		(4,403	)
Gain on disposition		—		—		—		175,717
Income tax expense		4,982		1,917		10,358		49,282

Income from discontinued operations, net of income tax	$	8,552	$	4,300	$	25,916	$	122,032

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Addison Energy Inc. 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). This dividend was funded by Addison by an additional drawdown on its bank credit facility. The dividend was subject to Canadian tax withholding of 5% or Cdn. $3.7 million (U.S. $3.0 million), which amount has been included in the 2004 tax provision.

Presentation on financial statements

Addison's financial position and results of operations have been reported as discontinued operations. We have revised our consolidated statements of cash flows for the 209 day period beginning January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003 and the year ended December 31, 2004 to separately disclose the operating, investing, and financing sections of the cash flows attributable to Addison's operations. We had previously reported the income or loss from discontinued operations as a component of net cash provided by or used in operating activities of discontinued operations.

Our current presentation of cash flow includes net income from discontinued operations as a separate adjustment to reconcile cash flows from operations. The cash flow from discontinued operations includes cash flows from our discontinued Canadian operations and the cash flows related to the sale of these operations.

4. Marketable securities

Marketable securities at December 31, 2004 were common stock investments in public corporations, which are classified as available for sale securities. At December 31, 2004, our cost basis of marketable securities was $37,000 while the aggregate fair value was $69,000. In May 2005, we sold our remaining marketable securities. We had no marketable securities at December 31, 2005.

In May 2004, we received common stock of a public corporation valued at approximately $0.5 million as a portion of the proceeds from the sale of oil and natural gas properties. We sold all of these shares in September 2004 for approximately $0.5 million.

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At December 31, 2004, we had gross unrealized holding gains from available for sale securities of $32,000. Investment income is presented in the following table:

	Public predecessor		Private Predecessor
(in thousands)	For the 209 day period from January 1, 2003 To July 28, 2003		For the 156 day period from July 29, 2003 to December 31, 2003			December 31, 2004		For the 275 day period from January 1, 2005 to October 2, 2005
Gross proceeds from sales of marketable securities	$	442	$	1,393		$	1,296	$	59
Gross realized gains from sales of marketable securities		245		—			14		3
Gross realized losses from sales of marketable securities		—		(30	)		—		—
Unrealized net gain (loss) included in other comprehensive income		590		(34	)		17		—

There were no marketable securities activities during the 90 day period from October 3, 2005 to December 31, 2005.

5. Acquisition of North Coast Energy, Inc.

On November 26, 2003, EXCO entered into the North Coast Acquisition Agreement, as amended and restated on December 4, 2003, to acquire all of the issued and outstanding stock of North Coast pursuant to a tender offer and merger. EXCO acquired all of the outstanding common stock, options and warrants of North Coast on January 27, 2004 for a purchase price of $168.0 million, including transaction related costs, and we assumed $57.1 million of North Coast's outstanding indebtedness. As a result, on January 27, 2004, North Coast became a wholly-owned subsidiary and established a new core operating area for us in the Appalachian Basin. We have accounted for the North Coast acquisition using the purchase method of accounting and have consolidated its operations effective January 27, 2004.

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The total purchase price for North Coast was $225.1 million representing the purchase of all outstanding common stock and liabilities assumed as detailed below and has been allocated as follows (in thousands):

Purchase price calculations:
	Payments for tendered shares including options and warrants	$	167,781
	Assumption of debt including interest		57,148
	Merger related costs		156

	Total North Coast acquisition costs (before cash acquired)	$	225,085

Allocation of purchase price:
	Oil and natural gas properties—proved	$	192,035
	Oil and natural gas properties—unproved		7,258
	Gas gathering assets and other equipment		21,454
	Cash		10,429
	Other assets		412
	Deferred income tax asset		942
	Other current assets		11,080
	Accounts payable and accrued expenses		(10,340	)
Asset retirement obligations			(5,639	)
Liabilities from commodity price risk management activities			(2,546	)

Total allocation		$	225,085

The following table reflects the pro forma results of operations for the years ended December 31, 2003 and 2004. The information for the year ended December 31, 2003 has been derived from EXCO's audited consolidated statement of operations for the 209 day period ended July 28, 2003 and our audited consolidated statement of operations for the 156 day period ended December 31, 2003, and North Coast's audited financial statements for the year ended December 31, 2003. The information for the year ended December 31, 2004 has been derived from our audited consolidated statement of operations for the year ended December 31, 2004 and North Coast's unaudited consolidated financial statement of operations for the 26 day period from January 1 to January 26, 2004. The pro forma results of operations give effect to the following events as if each occurred on January 1 of each respective year.

•: The going private transaction, which occurred on July 29, 2003. See "Note 1. Organization" for further discussion.
•: Our acquisition of North Coast for a purchase price of approximately $225.1 million. The North Coast acquisition was accounted for using the purchase method of accounting in accordance with SFAS No. 141. Accordingly, EXCO's historical financial statements reflect the allocation of the purchase price to the underlying assets and liabilities based upon their estimated fair values. For tax purposes we also received a step up in tax basis equal to the purchase price.
•: Adjustments to conform North Coast's historical accounting policies related to oil and natural gas properties from successful efforts to full cost accounting.

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•: The issuance of $350.0 million in 7¹/4% senior notes, or senior notes, due January 15, 2011 (See "Note 6. Long-term debt and interim bank loan").
•: The assumption of North Coast's debt and repayment of our and North Coast's credit facilities.
•: The payment of our related fees and expenses.

During North Coast's year ended December 31, 2003 and the 26 day period from January 1, 2004 to January 26, 2004, there were $1.5 million and $11.9 million in investment banking fees, employee bonus and severance payments and other costs incurred in connection with the merger with EXCO that have been excluded from net income in the following table.

(in thousands)		For the year ended December 31, 2003			For the year ended December 31, 2004
Revenues and other income		$	94,954		$	99,544
Net income (loss)		$	(8,262	)	$	8,306

The pro forma information presented herein does not purport to be indicative of the financial position or results of operations that would have actually occurred had the events discussed above occurred on the dates indicated or which may occur in the future.

6. Long-term debt and interim bank loan

Long-term debt is summarized as follows:

	December 31,
(in thousands)	December 31,
(in thousands)	2004		2005
Notes payable	$	34,500	$	1
7¹/4% senior notes due 2011		452,953		461,801

Long-term debt	$	487,453	$	461,802

Credit agreements

Credit agreement. At December 31, 2003, our former restated U.S. credit agreement provided for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $95.0 million. At December 31, 2003, we had approximately $49.5 million of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $45.2 million available for borrowing.

On January 27, 2004, our credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the credit agreement maturity date to January 27, 2007. Upon the issuance of the $100.0 million in additional senior notes on April 13, 2004, the credit agreement borrowing base was reduced to $95.0 million. Effective June 28, 2004, the borrowing base was redetermined at $145.0 million. Effective October 8, 2004 and August 12, 2005, the borrowing base was redetermined at $145.0 million, and will be redetermined each May 1 and November 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At December 31, 2004, we had $34.5 million of outstanding indebtedness and letter of credit commitments of $0.3 million and

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approximately $110.2 million available for borrowing. At December 31, 2005, we had $1,000 of outstanding indebtedness under our credit agreement. At December 31, 2005, the six month LIBOR rate was 4.70%, which would result in an interest rate of approximately 5.95% of any new indebtedness we may incur under the credit agreement. Borrowings under our amended and restated credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus .50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At December 31, 2004 and 2005, the six month LIBOR rate was 2.78% and 4.70%, respectively, which would result in an interest rate of approximately 4.03% and 5.95% on any new indebtedness we may incur under the U.S. credit agreement.

On September 30, 2005, we entered into the Fourth Amendment to the U.S. credit agreement, which amended the credit agreement to, among other things (i) permit the acquisition of Holdings by Holdings II, (ii) adjust the restriction on sales of assets by the borrowers and certain subsidiary guarantors under the credit agreement and the application of the proceeds from such sales of assets and (iii) permit the redemption of our senior notes pursuant to the terms of the indenture. Pursuant to the interim bank loan incurred by Holdings II in connection with the Equity Buyout on October 3, 2005, total advances under our credit agreement could not exceed $10.0 million until the interim bank loan was repaid in full in connection with our initial public offering which closed on February 14, 2006.

Canadian credit agreement. At December 31, 2004, we had approximately $12.9 million of outstanding indebtedness under our Canadian credit agreement (which has been reclassified as Liabilities from discontinued operations on the Consolidated Balance Sheet at December 31, 2004). Borrowings under the Canadian credit agreement were collateralized by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. We repaid all outstanding indebtedness under our Canadian credit agreement in full on February 10, 2005 with a portion of the proceeds received from the sale of Addison.

Financial covenants and ratios. Our amended and restated U.S. credit agreement contains certain financial covenants and other restrictions which require that we:

•: maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our credit agreements) of at least 1.0 to 1.0 at the end of any fiscal quarter;
•: not permit our ratio of consolidated funded debt to consolidated EBITDA (as defined under our credit agreements) to be greater than (i) 4.35 to 1.00 at the end of each fiscal quarter ending on or before March 31, 2005 and (ii) 4.00 to 1.00 on June 30, 2005 and at the end of each fiscal quarter thereafter;
•: not permit our ratio of consolidated funded debt (other than the senior notes) to consolidated EBITDA (as defined under our credit agreements) to be greater than (i) 3.25 to 1.0 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 3.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter; and
•: not permit our ratio of consolidated EBITDA to consolidated interest expense (as defined under our credit agreements) to be less than 2.5 to 1.0 at the end of each fiscal quarter.

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Additionally, the credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and prohibit the payment of dividends on our common stock. At December 31, 2004, we were in compliance with the covenants contained in our U.S. and Canadian credit agreements. At December 31, 2005, we were in compliance with the covenants contained in our U.S. credit agreement.

U.S. senior term loan. On October 17, 2003, we entered into a $50.0 million senior term credit agreement. We borrowed all $50.0 million under the senior term credit agreement and we used the proceeds to repay a portion of our indebtedness under our U.S. credit agreement. The U.S. senior term loan was paid in full on January 27, 2004 from the proceeds of the $350 million senior notes issued on January 20, 2004.

Dividend restrictions. We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our U.S. credit agreement currently prohibits us from paying dividends on our common stock. Even if our U.S. credit agreement permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

7¹/4% senior notes due January 15, 2011

On January 20, 2004, EXCO completed the private placement of $350.0 million aggregate principal amount of 7¹/4% senior notes due January 15, 2011 pursuant to Rule 144A and Regulation S under the Securities Act of 1933 (Securities Act) at a price of 100% of the principal amount. The net proceeds of the 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 those transactions.

Concurrent with the issuance of the senior notes, we wrote off $0.9 million of costs incurred in January 2004 to secure interim loan financing which was not utilized upon issuance of the senior notes and deferred financing costs of approximately $0.7 million related to the senior term loan, which was retired with the proceeds of the senior notes. These amounts are reflected in the consolidated statements of operations as interest expense.

On April 13, 2004, EXCO completed a private placement of an additional $100.0 million aggregate principal amount of the senior notes pursuant to Rule 144A, having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The 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 the April 13, 2004 offering were used to repay substantially all of our outstanding indebtedness under our Canadian credit agreement and pay fees and expenses associated therewith.

On May 28, 2004, EXCO concluded an exchange offer of $450.0 million aggregate principal amount of our senior notes, which were privately placed in January and April 2004, for $450.0 million aggregate principal amount of our senior notes that have been registered under the Securities Act. Holders of all but $0.3 million of the senior notes elected to accept our exchange offer.

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In accordance with the terms of the indenture governing our senior notes, at the time of the closing of the sale of Addison Energy Inc. (See "Note 3. Sale of Addison Energy, Inc."), the security interest of the holders of our senior notes in two-thirds of the common stock of Addison was released and a second lien security interest (behind the first lien security interest under our U.S. credit agreement) was effected in U.S. $120.6 million of cash equivalents, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. An additional U.S. $75.8 million of proceeds from the Addison disposition were applied to temporarily pay down borrowings under our U.S. credit agreement to a nominal amount. The remaining Addison disposition proceeds of U.S. $130.3 million were invested in short-term investments as permitted under our U.S. credit agreement and our senior notes. The net cash proceeds from the Addison disposition as determined under the indenture governing our senior notes was U.S. $326.8 million and may be used only in accordance with the terms of the indenture. The indenture provides that the net cash proceeds from an asset disposition must be used to permanently reduce debt, reinvest in our business or make an offer to the holders to repurchase their senior notes.

The Equity Buyout was a change of control under the indenture governing the senior notes. As a result of this change of control and also in connection with the sale of Addison, on November 2, 2005, we commenced an offer to the holders of senior notes to repurchase up to $120.6 million of senior notes at 100% of the principal amount plus accrued and unpaid interest of the notes pursuant to the indenture. Simultaneously therewith, we commenced an offer to repurchase all outstanding senior notes at 101% of the principal amount plus accrued and unpaid interest in connection with the change in control provision contained in the indenture as a result of the Equity Buyout. Holders of $5.3 million in aggregate principal amount of the senior notes were tendered to and purchased by us in December 2005 as a result of these offers for total consideration of $5.5 million including accrued plus unpaid interest and the applicable premium. As a result of the repurchase of these senior notes, we recognized a gain upon the early extinguishment of these notes in the amount of approximately $151,000 during the 90 day period from October 3, 2005 to December 31, 2005 which has been reflected in other income on our consolidated statements of operations. Upon completion of the offer to repurchase related to the Addison sale, the second lien security interest on $120.6 million of the proceeds from the sale and the general restrictions under the indenture on the entire proceeds was terminated.

Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011. Prior to January 15, 2007, EXCO may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the notes.

As part of the "pushdown accounting" resulting from the Equity Buyout, the senior notes were recorded at their fair value of $468.0 million on October 3, 2005. The resulting premium of $18.0 million in excess of the aggregate principal amount will be amortized over the remaining life of the senior notes. The unamortized premium was $17.1 million at December 31, 2005. The purchase of the $5.3 million in aggregate principal amount of senior notes tendered to us as discussed above has reduced the premium to be amortized by approximately $202,000.

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The indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:

•: incur or guarantee additional debt and issue certain types of preferred stock;
•: pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
•: make investments;
•: create liens on our assets;
•: enter into sale/leaseback transactions;
•: create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
•: engage in transactions with our affiliates;
•: transfer or issue shares of stock of subsidiaries;
•: transfer or sell assets; and
•: consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

The estimated fair value of our senior notes at December 31, 2005 was $453.6 million as compared to the carrying amount of $461.8 million (including $17.1 million of unamortized premium). The fair value of the senior notes is estimated based on quoted market prices for the senior notes.

Interim bank loan

In order to fund the Equity Buyout on October 3, 2005, Holdings II borrowed $350.0 million in interim debt financing under a credit agreement dated October 3, 2006 with JP Morgan. The loan was collateralized by a first priority lien on all of our common stock. The maturity date of the loan is July 3, 2006, with an interest rate of 10%. The loan agreement contains representations and warranties, covenants and conditions usual for a transaction of this type. Covenants contained in this loan include, among other things, restrictions on the incurrence of indebtedness, the payment dividends, redemption of capital stock and making of certain investments, sales of assets and subsidiary stock, entering into sale and leaseback transactions, entering into agreements that restrict the payment of dividends by subsidiaries, or the repayment of intercompany loans and advances, entering into affiliate transactions, entering into mergers, consolidations and sales of substantially all of our assets, amending material debt instruments, and certain other activities. The interim bank loan could be prepaid, in whole or in part, at the option of Holdings II, at any time upon three days' prior notice.

The interim bank loan is legally in the name of Holdings II. The Equity Buyout resulted in a change of control. GAAP requires the acquisition by Holdings II to be accounted for as a purchase transaction in accordance with SFAS No. 141. In addition, GAAP requires the application of "push down accounting" in situations where the ownership of an entity has changed, meaning that the post transaction financial statements of the acquired entity (EXCO) reflect the new basis of accounting in accordance with SAB 54. In addition to the stepped-up basis resulting from the acquisition, the interim bank loan has been "pushed- down" to EXCO and is presented as a component of consolidated debt.

On February 14, 2006, upon closing of the initial public offering (IPO), the interim bank loan, together with accrued interest was paid in full.

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7. Income taxes

The income tax provision attributable to our income (loss) before income taxes consists of the following:

			Public Predecessor			Private Predecessor									Successor
(in thousands)			For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003			Year ended December 31, 2004			For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 3, 2005 to December 31, 2005
Current expenses (benefit):
	U.S.
		Federal	$	—		$	—		$	—		$	(3,563	)	$	(7,020	)
		State		(181	)		—			1,445			(668	)		1,315

		Total current income tax (benefit)		(181	)		—			1,445			(4,231	)		(8,335	)

Deferred:
	U.S.
		Federal		—			(2,692	)		4,681			(49,881	)		12,656
		State		—			(131	)		(91	)		(9,586	)		3,000
		Canadian		—			(4,941	)		(909	)		—			—

		Total deferred income tax (benefit)		—			(7,764	)		3,681			(59,467	)		15,656

		Total income tax (benefit)	$	(181	)	$	(7,764	)	$	5,126		$	(63,698	)	$	7,321

We have net operating loss carryforwards (NOLs) for United States income tax purposes that have either been generated from our operations or were purchased in our acquisitions. Our ability to use the purchased NOLs has been restricted by Section 382 of the Internal Revenue Code due to ownership changes which occurred on December 19, 1997 and July 29, 2003, the change in ownership of Rio Grande, Inc. which occurred on March 16, 1999, as well as the Equity Buyout, which occurred on October 3, 2005. We estimate that approximately $7.4 million of the NOLs limited by Section 382 will expire prior to their utilization. Expiration is expected to occur from 2005 through 2019. Accordingly, a valuation allowance of $2.6 million was established to reserve a portion of NOLs in excess of the Section 382 limitations, which we believe will more likely than not expire unutilized. Prior to the Equity Buyout, this valuation allowance and its associated deferred tax asset was written off because it was deemed worthless.

At December 31, 2002, EXCO had a valuation allowance to offset its U.S. deferred tax assets. During the 209 day period from January 1, 2003 to July 28, 2003, we had a U.S. operating loss and accordingly increased our valuation allowance to reflect that loss. As a result of the going private transaction, we were in a deferred tax liability position in the United States at the time of the transaction due to the step up in basis for book purposes related to purchase accounting and the carryover of tax basis. Except for the valuation allowance against NOLs limited by Section 382 described above, no valuation allowance was recognized in the purchase price allocation resulting from

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the going private transaction at December 31, 2003, December 31, 2004, or at the Equity Buyout on October 3, 2005. During the 275 day period from January 1, 2005 to October 2, 2005, the valuation allowance against NOLs limited by Section 382 and its associated deferred tax asset was written off.

Prior to the fourth quarter of 2004, we had not provided for any U.S. deferred income taxes on the undistributed earnings of Addison, our former Canadian subsidiary, based upon the determination that those earnings would be indefinitely reinvested in Canada. On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). The Act created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. In February 2005, we repatriated Cdn. $74.5 million (U.S. $59.6 million) in an extraordinary dividend, as defined in the Act, from Addison. Accordingly, we recognized a tax liability of $8.2 million as of December 31, 2004 related to the extraordinary dividend. This dividend represented a substantial portion of the undistributed earnings of Addison, based upon its earnings and profits as determined under U.S. federal income tax law, as of December 31, 2004. As a result of certain technical corrections to the Act, we recognized a benefit of $2.1 million in our current income taxes during the 275 day period from January 1, 2005 to October 2, 2005 related to this dividend. This additional $2.1 million benefit has been recognized as a component of taxes from continuing operations pursuant to SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109) and Emerging Issues Task Force 93-13, "Effect of a Retroactive Change in Enacted Tax Rates That is Included in Income from Continuing Operations" (EITF 93-13), which require that the tax effect of a change in enacted tax rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.

For the 156 day period ended December 31, 2003 and for the year ended December 31, 2004, we recognized a deferred income tax benefit of approximately $4.9 million and $0.9 million, respectively, related to Canadian legislation which became effective in November 2003 and May 2004 to phase in reduced income tax rates and allow for deductibility of crown royalties. These amounts have been reflected as income tax benefits in continuing operations pursuant to the provisions of SFAS No. 109 and EITF 93-13 as discussed above.

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Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:

		December 31,
		2004			2005
(in thousands)		Private predecessor			Successor
Current deferred tax assets (liabilities):
	Basis difference in fair value of derivative financial instruments	$	—		$	26,605
	Other		(710	)		3,363

	Total current deferred tax assets (liabilities)		(710	)		29,968

Long-term deferred tax assets:
	Net operating loss carryforwards — U.S		17,807			1,879
	Basis difference in fair value of derivative financial instruments		13,127			34,300
	Credit carryforwards		5			—
	Purchase accounting adjustment to bond premium		—			5,456
	Share-based compensation		—			437
	Other		1,050			3
	Valuation allowance for deferred tax assets		(2,673	)		—

	Total long-term deferred tax assets	$	29,316		$	42,075

Deferred tax liabilities:
	Book basis of oil and natural gas properties in excess of tax basis — U.S	$	(36,873	)	$	(176,677	)
	Taxes on undistributed earnings of foreign subsidiary — U.S		(8,237	)		—

	Total deferred liabilities	$	(45,110	)	$	(176,677	)

	Net noncurrent deferred tax liabilities	$	(15,794	)	$	(134,602	)

A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, for the

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year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005 is presented in the following table:

		Public predecessor			Private predecessor									Successor
(in thousands)		For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003			Year ended December 31, 2004			For the 275 day period from January 1, 2005 to October 2, 2005			For the 90 day period from October 2, 2005 to December 31, 2005
United States federal income taxes (benefit) at statutory rate of 35%		$	(2,785	)	$	(2,760	)	$	(5,120	)	$	(70,293	)	$	8,150
Increases (reductions) resulting from:
	Undistributed earnings of foreign subsidiary		—			—			8,237			—			—
	Foreign tax items		—			—			—			644			(2,996	)
	Change in Canadian tax rates		—			(4,941	)		(909	)		—			—
	Change in U.S. tax law related to Canadian dividend		—			—			—			(2,075	)		—
	Adjustments to the valuation allowance		2,447			—			—			—			—
	Non-deductible compensation		—			—			—			15,432			604
	Non-deductible intercompany foreign interest expense		—			—			1,840			—			—
	State taxes net of federal benefit		(118	)		(85	)		880			(6,665	)		1,095
	Other		275			22			198			(741	)		468

Income tax expense (benefit) before cumulative effect of change in accounting principles		$	(181	)	$	(7,764	)	$	5,126		$	(63,698	)	$	7,321

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8. Stock transactions

Stock options

The following table summarizes EXCO's stock option activity during the period from January 1, 2003 through December 31, 2003:

		Stock options		Weighted average exercise price per share
Options outstanding at December 31, 2002		2,049,831		$	10.85
	Granted	—			—
	Expired or canceled	(916,446	)		10.37
	Exercised	(1,133,385	)		11.24

Options outstanding at December 31, 2003(1)		—		$	—

(1): All stock options were cancelled prior to the going private transaction.

The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used for the EXCO options included in the above table:

Fair market value of stock at date of grant		$6.00 to $20.62
Option exercise prices		$6.00 to $20.62
Expected life		4 years
Risk-free rate of return		10-year U.S. Treasury Notes
Volatility		Based upon daily stock prices from January 1, 2000 through December 31, 2002
Dividend yield		0%
Calculated Black-Scholes values		$2.60 to $8.94 per option

See "Note 2. Summary of significant accounting policies" for a comparison of our net income/(loss) and net income/(loss) per share as reported and as adjusted for the pro forma effects of determining compensation expense in accordance with SFAS No. 123. All outstanding stock options were either exercised prior to or cashed out as a result of the going private transaction.

During the 209 day period from January 1, 2003 to July 28, 2003, EXCO recognized $3.6 million of stock-based compensation expense in general and administrative expense. This amount was paid to option holders at the time of the going private transaction to cancel all unexercised stock options outstanding at that time. The amount represented the cumulative difference between the $18.00 per share proceeds and the exercise price of the outstanding stock options times the number of stock options outstanding.

As an incentive to the management and certain key employees of Addison, the board of directors of Addison established the Addison Energy Inc. stock option plan effective June 30, 2002. Addison stock options were issued as of June 30, 2002, under the plan that, if fully exercised, would allow the participants to own in the aggregate 1,000 shares of Addison common stock, approximately 10% of the shares of common stock in Addison on a fully-diluted basis. The Addison stock options were

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exercisable for a term of five years from the date of the grant. The Addison stock options were subject to vesting. The vesting schedule was as follows:

Vesting date		Cumulative percent Vested
Prior to April 26, 2003		None
April 26, 2003		50%
April 26, 2004		75%
April 26, 2005		100%

The exercise price under the Addison stock option plan as of June 30, 2002 was Cdn. $1,031.61 per share. The price was determined by using a formula as set forth in the Addison stock option agreement. The formula was based upon:

•: the value of Addison's Proved Reserves;
•: the amount of any working capital surplus or deficiency;
•: any capital contributions or distributions made after June 30, 2002;
•: any debt owed to us, owed under the Canadian credit agreement or owed to other third parties;
•: the total exercise price of all outstanding Addison stock options under the plan;
•: the amount of deferred income tax liability incurred after June 30, 2002;
•: a calculated amount to allocate certain general and administrative costs that we incur that also benefit Addison; and
•: the ratio of the average trading price of our common stock divided by $18.25.

This formula was to be calculated as of December 31 of each year, beginning December 31, 2002, to determine the value of each share of Addison's common stock.

If an Addison stock option were exercised, we would be obligated to purchase the shares of Addison common stock from the employee six months later at the then-current price as calculated using the above formula. Each employee receiving an Addison stock option entered into an agreement that restricted their ability to sell or transfer any Addison common stock acquired under the Addison stock option plan to any party other than to us.

The Addison stock options became fully vested and exercisable if any of the following occurs:

•: a person, or a group of people acting together, has the right to cast more than 50% of the votes when electing our directors;
•: our shareholders approve a merger or other transaction that would result in our shareholders owning less than 50% of the combined entity; or
•: we sell the shares of Addison or substantially all of its assets.

The going private transaction was a triggering event under the Addison stock option plan. We calculated the value of each share of Addison common stock as of the date of the event to be Cdn. $10,014.50 per share. We paid approximately Cdn. $9.0 million in cash to the holders of the

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Addison stock options, which represented the difference between the calculated value per share and the Addison stock option exercise price times the number of shares of Addison common stock that the participant had the right to purchase under the Addison stock option plan.

The value of a share of Addison common stock was calculated to be Cdn. $7,013.94 per share as of December 31, 2002. The following table summarizes our Addison stock option activity:

		Stock options	Weighted average exercise price per share
Options outstanding at December 31, 2002		1,000	Cdn. $	1,031.61
	Granted	—		—
	Expired or canceled	1,000	Cdn. $	1,031.64
	Exercised	—		—

Options outstanding at December 31, 2003		—		—

During the 209 day period from January 1, 2003 to July 28, 2003, U.S. $5.5 million of stock-based compensation expense for the Addison stock option plan has been recognized in income from discontinued operations.

As discussed in Note 2. Summary of significant accounting policies, certain of our employees have been granted Holdings stock options under the Holdings Plan. The following table summarizes Holdings stock option activity under the Holdings Plan:

		Stock options	Weighted average exercise price per share
Options outstanding at December 31, 2003		—		—
	Granted	8,801,354	$	3.00
	Expired or canceled	—		—
	Exercised	—		—

Options outstanding at December 31, 2004		8,801,354	$	3.00
	Granted	194,630	$	3.57
	Expired or canceled	324,078	$	3.00
	Exercised	—		—
	Cash-out in connection with Equity Buyout	8,671,906	$	3.01

Options outstanding at October 3, 2005		—		—

All of the issued and outstanding Holdings stock options as of October 3, 2005 were purchased by Holdings as a part of the Equity Buyout transaction. This resulted in a charge of $17.8 million to general and administrative expense during the 275 day period from January 1, 2005 to October 2, 2005.

The 2005 Incentive Plan provides for the granting of options to purchase up to 10,000,000 shares of Holdings (formerly Holdings II) common stock. From October 5, 2005 to December 31, 2005,

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options were granted under the 2005 Incentive Plan to our employees to purchase 4,992,650 shares of Holdings common stock at $7.50 per share. The options expire ten years following the date of grant and have a weighted average remaining life of 9.75 years. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of December 31, 2005, there were 5,026,925 shares available to be granted under the Plan.

The following table summarizes Holdings stock option activity related to our employees under the 2005 Incentive Plan:

		Stock options	Weighted average exercise price per share
Options outstanding at October 3, 2005		—		—
	Granted	4,992,650	$	7.50
	Expired or canceled	19,575	$	7.50
	Exercised	—		—

Options outstanding at December 31, 2005		4,973,075	$	7.50

Options exercisable at December 31, 2005		1,244,113	$	7.50

The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used for the Holdings options included in the above table:

Fair market value of stock at date of grant		$7.50
Option exercise prices		$7.50
Expected life		4 years
Risk-free rate of return		10-year U.S. Treasury Notes
Volatility		30.4%
Dividend yield		0%
Calculated Black-Scholes values		$2.29 per option

As required by SFAS 123(R), the granting of options under the 2005 Incentive Plan by Holdings to our employees are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Volatility was determined based on the weighted average of historical volatility of the common stock of the Public Predessor for 1.25 years and the daily closing prices from five comparable public companies. Total share-based compensation for the 90 day period from October 3, 2005 to December 31, 2005 was $3.2 million, of which $2.2 million is included in general and administrative expense and $1.0 million was capitalized as part of proved developed and undeveloped oil and natural gas properties, as discussed in "Note 2. Summary of significant accounting policies." Total share-based compensation to be recognized on unvested awards is $7.5 million over a weighted average period of 2.83 years.

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Issuance of preferred stock

EXCO was authorized to issue up to 10,000,000 shares of preferred stock, $.01 par value per share. On June 29, 2001, EXCO closed its rights offering to existing shareholders that resulted in the sale of 5,004,869 shares of 5% convertible preferred stock at $21.00 per share. EXCO raised a total of approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions), through the exercise of 4,466,869 rights and the sale of 538,000 shares of 5% convertible preferred stock by dealer managers. We applied approximately $97.6 million of the offering proceeds to pay-off its bank loans and used the remaining proceeds for general corporate purposes. Dividends on the 5% convertible preferred stock were payable quarterly in cash and the dividend payment was approximately $1.3 million per quarter beginning September 30, 2001. Preferred stock dividends of approximately $2.7 million, $5.3 million and $2.6 million were paid during the years ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003. Each share of 5% convertible preferred stock was converted into one share of common stock on or before June 30, 2003.

In July 2003, Holdings issued 115.9 million of its Class A common stock valued at $1.50 per share to institutional investors, members of EXCO's management and key employees, and other investors in exchange for cash, shares of EXCO common stock and, in the case of certain members of management and key employees, notes receivable. Also in July 2003, Holdings issued 11.9 million shares of Class B common stock valued at $0.001 per share to members of management and key employees for cash. The shareholder agreement governing the Class A and Class B common stock provided that, upon the occurrence of certain specified events, including a change in control as occurred upon the Equity Buyout, the Class A common stock was entitled to receive the first $175.0 million upon the sale or liquidation of Holdings. Thereafter, the Class A and Class B common stock shared all proceeds on a pro-rata basis. As discussed in Note 1. Organization, the Class B common stock was considered to be a "variable" plan for financial accounting purposes. As a result, we recognized a non-cash charge of approximately $44.1 million during the 275 day period from January 1, 2005 to October 2, 2005 related to the Class B common stock.

9. Employee benefit plans

We sponsor two 401(k) plans for our U.S. employees and match up to 100% of employee contributions based on years of service with us. Our matching contributions of $155,000, $59,000, $404,000, $423,000 and $95,000 for the 209 day period from January 1, 2003 to July 28, 2003, for the 156 day period from July 29, 2003 to December 31, 2003, for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005 and for the 90 day period from October 3, 2005 to December 31, 2005, respectively, have been included as general and administrative expense.

10. Commitments and contingencies

We lease our offices and certain equipment. Our rental expenses were approximately $0.3 million, $0.2 million, $0.6 million, $0.6 million, and $0.2 million for the 209 day period from January 1, 2003 to July 28, 2003, for the 156 day period from July 29, 2003 to December 31, 2003, for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, and the 90 day

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period from October 3, 2005 to December 31, 2005, respectively. Our future minimum rental payments under operating leases with remaining noncancellable lease terms at December 31, 2005, are as follows:

On November 4, 2005, we entered into an agreement with a contract drilling company which commits us to utilize, or to pay for if not utilized, the use of three drilling rigs in east Texas until December 31, 2007. As of December 31, 2005, the minimum amount that we are obligated to pay under the contract is $25.2 million.

(in thousands)	Amount
2006	$	3,284
2007		3,141
2008		3,067
2009		3,545
2010		771
Thereafter		856

	$	14,664

11. Environmental regulation

Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.

12. Geographic operating segment information and oil and natural gas disclosures

We have operations in only one industry segment, that being the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have geographic operating segments in the United States and, until February 10, 2005, in Canada. Upon the acquisition of North Coast during 2004, our geographic operating segments in the United States were EXCO (excluding Appalachia) and Appalachia. The following tables provide our geographic operating segment data.

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The following table presents total capitalized costs of proved and unproved properties, accumulated depreciation, depletion and amortization related to oil and natural gas production, and total assets excluding information relating to Addison:

	Private predecessor
(in thousands)	EXCO (excluding Appalachia)			Appalachia			Total
As of December 31, 2004:
Oil and natural gas properties, including proved and unproved leasehold	$	206,356		$	266,801		$	473,157
Accumulated depreciation, depletion and amortization		(18,689	)		(13,018	)		(31,707	)

Oil and natural gas properties, net	$	187,667		$	253,783		$	441,450

Goodwill	$	19,984		$	—		$	19,984

Total assets	$	241,032		$	299,258		$	540,290

	Successor
As of December 31, 2005:
Oil and natural gas properties, including proved and unproved leasehold	$	336,250		$	590,466		$	926,716
Accumulated depreciation, depletion and amortization		(5,473	)		(7,808	)		(13,281	)

Oil and natural gas properties, net	$	330,777		$	582,658		$	913,435

Goodwill	$	76,786		$	143,220		$	220,006

Total assets	$	667,172		$	840,465		$	1,507,637

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The results of operations from our oil and natural gas producing activities, excluding information relating to Addison, are as follows:

		Public predecessor			Private predecessor
(in thousands)		For the 209 day period from January 1, 2003 to July 28, 2003			For the 156 day period from July 29, 2003 to December 31, 2003
Oil and natural gas sales		$	22,403		$	21,767
Commodity price risk management activities			—			(10,800	)
Other loss			(1,129	)		(161	)

	Total revenues and other income		21,274			10,806

Production costs			11,380			7,331
Depreciation, depletion and amortization			5,125			5,413
Accretion of discount on asset retirement obligations			320			205
General and administrative			11,347			3,823
Interest			1,058			1,921

	Total costs and expenses		29,230			18,693

Loss before income taxes, discontinued operations and cumulative effect of change in accounting principle			(7,956	)		(7,887	)
Income tax benefit(1)			(181	)		(7,764	)

Loss before discontinued operations and cumulative effect of change in accounting principle		$	(7,775	)	$	(123	)

(1): Includes an income tax benefit of $4,941 for the 156 day period from July 29, 2003 to December 31, 2003 related to changes in Canadian tax rates.

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		Private predecessor
(in thousands)		EXCO (excluding Appalachia)			Appalachia			Total
Year ended December 31, 2004:
Oil and natural gas sales		$	67,003		$	74,990		$	141,993
Commodity price risk management activities			(18,055	)		(32,288	)		(50,343	)
Other income			402			739			1,141

Total revenues and other income			49,350			43,441			92,791

Production costs			16,893			11,363			28,256
Depreciation, depletion and amortization			13,941			14,578			28,519
Accretion expense			425			375			800
General and administrative			11,413			3,862			15,275
Interest			30,434			4,136			34,570

	Total costs and expenses		73,106			34,314			107,420

Income (loss) before income taxes and discontinued operations			(23,756	)		9,127			(14,629	)
Income tax expense(1)			505			4,621			5,126

Income (loss) from continuing operations		$	(24,261	)	$	4,506		$	(19,755	)

(1): The income tax expense for EXCO (excluding Appalachia) has been reduced by an income tax benefit of $909 related to changes in Canadian tax rates.

			Private predecessor
(in thousands)			EXCO (excluding Appalachia)			Appalachia			Total
For the 275 day period from January 1, 2005 to October 2, 2005:
Revenues and other income:
	Oil and natural gas		$	55,177		$	77,644		$	132,821
	Commodity price risk management activities			(56,705	)		(120,548	)		(177,253	)
	Other income			5,806			1,269			7,075

		Total revenues and other income		4,278			(41,635	)		(37,357	)

Costs and expenses:
	Oil and natural gas production			11,407			10,750			22,157
	Depreciation, depletion and amortization			11,355			13,332			24,687
	Accretion of discount on asset retirement obligations			277			340			617
	General and administrative			79,219			10,125			89,344
	Interest			26,675			—			26,675

		Total costs and expenses		128,933			34,547			163,480

Loss from continuing operations before income taxes				(124,655	)		(76,182	)		(200,837	)
Income tax benefit				(21,538	)		(42,160	)		(63,698	)

Loss from continuing operations			$	(103,117	)	$	(34,022	)	$	(137,139	)

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			Successor
(in thousands)			EXCO (excluding Appalachia)			Appalachia			Total
For the 90 day period from October 3, 2005 to December 31, 2005:
Revenues and other income:
	Oil and natural gas		$	23,271		$	46,790		$	70,061
	Commodity price risk management activities			2,856			(3,112	)		(256	)
	Interest and other income			1,849			516			2,365

		Total revenues and other income		27,976			44,194			72,170

Costs and expenses:
	Oil and natural gas production			4,569			4,380			8,949
	Depreciation, depletion and amortization			5,689			8,382			14,071
	Accretion of discount on asset retirement obligations			84			142			226
	General and administrative			4,838			1,387			6,225
	Interest			19,414			—			19,414

		Total costs and expenses		34,594			14,291			48,885

Income (loss) from continuing operations before income taxes				(6,618	)		29,903			23,285
Income tax expense (benefit)				(3,415	)		10,736			7,321

Income (loss) from continuing operations			$	(3,203	)	$	19,167		$	15,964

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13. Derivative financial instruments

In connection with the incurrence of debt related to our acquisition activities, our management has adopted a policy of entering into oil and natural gas derivative financial instruments to protect against commodity price fluctuations and to achieve a more predictable cash flow. SFAS No. 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings in our public predecessor basis financial statements. Prior to July 29, 2003, all of EXCO's derivative financial instruments were designated as cash flow hedges. Beginning July 29, 2003, the date of the going private transaction, we have not designated our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative's fair value currently in earnings.

EXCO entered into several swap transactions during 2000 and 2001 with Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern District of New York. We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001. We believe that we were owed approximately $15.3 million, including settlements already due but not paid, but the exact amount of the claim was determined pursuant to the terms of the ISDA Master Agreement. In connection with the going private transaction, we valued the Enron derivative asset at $2.8 million, which represented our estimate of the fair market value of our bankruptcy claim against Enron North America. Our estimate of the value of our bankruptcy claim was based upon informal offers that we received from third parties attempting to purchase those claims as well as management's best estimate of the financial condition of Enron's bankruptcy estate as determined from published reports and court filings related to the bankruptcy. Our claim was sold to a third party in April 2004 for approximately $4.7 million. The difference between the $4.7 million received for the claim and the $2.8 million derivative asset was treated as a purchase price adjustment for the going private transaction. As a result, we reduced goodwill by $1.2 million and increased deferred income taxes payable by $0.7 million.

The following table sets forth our oil and natural gas derivatives as of December 31, 2005. The fair values at December 31, 2005 are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at December 31, 2005. We

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have the right to offset amounts we expect to receive or pay among our individual counterparties. As a result, we have offset amounts for financial statement presentation purposes.

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at December 31, 2005
Natural gas:
Swaps:
2006	14,418	$	6.93	$	(54,107	)
2007	12,410		6.58		(42,560	)
2008	10,980		7.62		(16,860	)
2009	1,825		4.51		(6,267	)
2010	1,825		4.51		(5,025	)
2011	1,825		4.51		(4,149	)
2012	1,830		4.51		(3,627	)
2013	1,825		4.51		(3,233	)

Total Natural Gas	46,938				(135,828	)

Oil:
Swaps:
2006	237		67.04		918
2007	201		64.99		214
2008	183		63.00		101

Total Oil	621				1,233

Total Oil and Natural Gas				$	(134,595	)

At December 31, 2005, the average forward NYMEX oil prices per Bbl for calendar 2006 and 2007 were $63.19 and $63.98, respectively, and the average forward NYMEX natural gas prices per Mmbtu for calendar 2006 and 2007 were $10.77 and $10.26, respectively.

During the 275 day period from January 1, 2005 to October 2, 2005, we canceled 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. We also entered into new commodity price risk management contracts at higher prices.

14. Acquisitions and dispositions

Significant transactions that occurred during 2003

During the 209 day period from January 1, 2003 to July 28, 2003, we completed several oil and natural gas property acquisitions in the United States. The total purchase price for the acquisitions was approximately $1.8 million funded from surplus cash. During this period, we sold our interest in several oil and natural gas properties in the United States for total sales proceeds of approximately $6.1 million.

During the 156 day period from July 29, 2003 to December 31, 2003, we completed several oil and natural gas property acquisitions in the United States. The total purchase price for the acquisitions was

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approximately $14.4 million funded with borrowings under our Canadian credit agreement and from surplus cash. The most significant purchase during this period was the acquisition of additional interests in certain natural gas properties that we operate in the United States that we closed in October 2003. As of October 1, 2003, estimated total Proved Reserves net to our interest from these properties included approximately 19.8 Bcf of natural gas. The total purchase price for the properties was approximately $13.9 million (after contractual adjustments).

Transactions, other than the acquisition of North Coast, that occurred during 2004

During the year ended December 31, 2004, we completed six oil and natural gas property acquisitions in the United States. Estimated total Proved Reserves net to our interest from these acquisitions included approximately 0.3 Mmbbls of oil and NGLs and 52.1 Bcf of natural gas. The total purchase price for the acquisitions was approximately $88.4 million funded with borrowings under our U.S. credit agreement and from surplus cash. During 2004, since the date of the respective acquisitions, we recorded revenue of approximately $3.7 million and oil and natural gas production costs of $0.6 million on these properties.

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 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.

Transactions, other than the sale of Addison, that occurred during 2005

During the 275 day period from January 1, 2005 to October 2, 2005, we completed seven oil and natural gas property acquisitions. Estimated total Proved Reserves net to our interest from the acquisitions included approximately 0.1 Mmbbls of oil and 59.8 Bcf of natural gas. The total purchase price for the acquisitions was approximately $102.3 million, funded with borrowings under our U.S. credit agreement and from surplus cash. In addition, we acquired a small natural gas gathering system for $0.7 million as part of one of the acquisitions.

During the 275 day period from January 1, 2005 to October 2, 2005, we completed seven sales of oil and natural gas properties. As of January 1, 2005, estimated total Proved Reserves net to our interest from these properties included approximately 0.3 Mmbbls of oil and NGLs and 18.4 Bcf of natural gas. The total sales proceeds we received were approximately $45.3 million. During the year ended December 31, 2004, we recorded revenue of approximately $5.5 million and oil and natural gas production costs of approximately $1.2 million on these properties. During the 275 day period from January 1, 2005 to October 2, 2005, we recorded revenues of approximately $3.7 million and oil and natural gas production costs of approximately $1.2 million on these properties through the date of their respective dispositions.

During the 90 day period from October 3, 2005 to December 31, 2005, we did not complete any acquisitions or dispositions of oil and natural gas properties.

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

15. Bonus retention program

In connection with the going private transaction, Holdings established a bonus retention program to provide an incentive for the employee stockholders of Holdings to remain employed with the company and its subsidiaries. The program provided for equal quarterly payments to the employee stockholders totaling $1.8 million on an annual basis. The first payments under the program were made on October 29, 2003. During the 156 day period from July 29, 2003 to December 31, 2003, and for the year ended December 31, 2004, we have included approximately $0.6 million and $1.4 million, respectively, in general and administrative expense and $0.2 million and $0.4 million, respectively, in income from operations of discontinued operations related to this program.

The payments to employee stockholders were to continue for four years unless the employee stockholder voluntarily terminated employment or was dismissed for cause, at which time the payments would cease. On February 10, 2005, in conjunction with the sale of Addison, the Addison employee bonus retention plan was terminated and all bonus retention amounts payable, aggregating approximately $1.0 million, were accelerated and paid in full pursuant to the terms of the plan. This amount has been included in the loss from operations of discontinued operations during the 275 day period from January 1, 2005 to October 2, 2005. The Equity Buyout on October 3, 2005 constituted a change of control as defined in the agreement. As a result, the employee bonus retention plan was terminated resulting in an additional charge of $2.6 million. Accordingly, all bonus retention amounts payable, aggregating approximately $2.8 million, were accelerated and paid in full pursuant to the terms of the plan. As a result, we have included this amount in general and administrative expense related to this program during the 275 day period from January 1, 2005 to October 2, 2005.

16. Concentration of credit risk

During 2005, sales of natural gas to an industrial customer accounted for 10.1% of our total oil and natural gas revenues. If we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser's service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser.

During 2004, sales of natural gas to an industrial customer accounted for 10.6% of our total oil and natural gas revenues. For the 209 day period from January 1, 2003 to July 28, 2003, sales of oil to Plains All American, Inc. and affiliates accounted for approximately 14.0% of total revenues. Sales to Western Gas Resources accounted for approximately 10.0% of total revenues for the same 209 day period. For the 156 day period from July 29, 2003 to December 31, 2003, sales to ONEOK Gas Marketing, Inc., Plains All American, Inc., and Western Gas Resources accounted for 10.0%, 13.2%, and 12.7% of total revenues, respectively.

17. Related party transactions

On September 16, 2005, Holdings (formerly Holdings II) incorporated TXOK Acquisition, Inc. (TXOK), a Delaware corporation with a $1,000 investment in TXOK common stock. TXOK was formed to acquire (i) all of the issued and outstanding shares of common stock of ONEOK Energy

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Resources Company (ONEOK Energy) and (ii) all of the issued and outstanding membership interests of ONEOK Energy Resources Holdings, LLC (ONEOK Energy LLC) (collectively ONEOK Energy). ONEOK Energy was wholly-owned by ONEOK, Inc., a Tulsa-based public utility company.

The ONEOK Energy acquisition closed on September 27, 2005. The purchase price paid at closing, based upon adjustments as of that date, was $642.9 million. Effective upon closing, ONEOK Energy and ONEOK Energy LLC became wholly-owned subsidiaries of TXOK.

TXOK funded the ONEOK Energy acquisition with (i) $20.0 million in private debt financing, $15.0 million of which was provided by Mr. Boone Pickens, one of our directors; (ii) the issuance of $150.0 million of TXOK preferred stock to BP EXCO Holdings LP, an entity controlled by Mr. Pickens; (iii) the TXOK credit facility, with an initial borrowing base of $325.0 million, of which approximately $308.8 million was drawn at the closing of the ONEOK Energy acquisition; and (iv) the TXOK second lien term loan facility of $200.0 million. Neither Holdings nor EXCO Resources is an obligor or guarantor with respect to these financings; however, Holdings has pledged its stock in TXOK as collateral security for payment of the TXOK credit facility and the TXOK term loan.

On October 7, 2005, EXCO advanced $4.0 million to Holdings (formerly Holdings II), which was used to partially fund an additional $20.0 million investment in TXOK Class B common stock by Holdings. TXOK used these proceeds to repay the $20.0 million in private debt financing described in (i) above. Following the Equity Buyout, Holdings made payments on behalf of Resources of approximately $10.0 million, including bank fees associated with the interim bank loan that was pushed down to us. As of December 31, 2005, we had a net liability to Holdings of $6.1 million. The TXOK preferred stock had full voting rights to vote with the TXOK common stock on all matters submitted to a vote by stockholders. Accordingly, holders of the TXOK preferred stock held voting control of TXOK prior to the February 14, 2006 redemption (See "Note 18. Subsequent Events"). If the TXOK preferred stock was not redeemed on or before September 27, 2006, the TXOK preferred stock and accumulated dividends would have automatically converted into common stock representing 90% of the outstanding common stock of TXOK. At December 31, 2005, Holdings accounted for its investment in TXOK using the cost method of accounting.

Effective October 15, 2005, we entered into an agreement with TXOK to manage TXOK's business affairs. Mr. Pickens controls TXOK through BP EXCO Holdings LP's ownership of the TXOK preferred stock. The agreement provides that we will provide TXOK with general management, treasury, finance, legal, audit, tax, information technology, and payroll and benefit administration services. TXOK has agreed to reimburse us on a monthly basis for the total amount of compensation, taxes and benefits we provide to employees providing services to TXOK. TXOK has also agreed to pay us $25,000 per month for the additional services that we provide, as well as reimbursement of all costs directly related to the operations of TXOK. We hired 57 people who were formerly employed by ONOEK and historically worked on these assets. TXOK reimburses us for all compensation expenses of these employees. At December 31, 2005, we had approximately $2.6 million reflected in accounts receivable-related parties on our consolidated balance sheet as due to us from TXOK of which $0.3 million was to reimburse us for accrued, but unpaid, stock option compensation expense for our employees who are assigned to manage TXOK's business.

143

18. Subsequent Events

On February 8, 2006, our registration statement on Form S-1, as amended, was declared effective by the SEC, which allowed for the issuance of 50,000,000 shares of our $0.001 par value common stock at an initial offering price of $13.00 per share. Net proceeds from the offering after underwriting discount, but before other expenses, which closed on February 14, 2006, were approximately $617.5 million. Concurrent with the closing of the IPO, Holdings was merged into and with us and we became the surviving company. Each share of stock and stock options of Holdings was automatically converted into an equal number of like securities of EXCO.

We granted the underwriters of our IPO an over-allotment option, exercisable for 30 days from the effective date of our IPO, to purchase an aggregate of 7,500,000 additional shares of Common Stock (Option Shares) at $12.35 per share. On February 21, 2006, the underwriters exercised their option for the purchase of 3,615,200 shares of our Common Stock for net proceeds of approximately $44.7 million.

The net proceeds from the IPO, including the funds received from the over-allotment option, together with cash on hand and additional borrowings under the U.S. Credit Agreement, were used to:

•: repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred by Holdings in connection with its Equity Buyout completed on October 3, 2005;
•: redeem the TXOK Preferred Stock issued by TXOK, an affiliate of Holdings, in connection with the ONEOK Energy acquisition (where described more fully in Note 17. Related party transactions) for $158.8 million in cash. In addition, we issued 388,889 shares of our Common Stock as the redemption premium (Redemption Shares) under terms of the Amended and Restated Certificate of Incorporation of TXOK. The Redemption Shares were calculated using a price of $12.00 per share in accordance with the redemption terms;
•: repay $200.0 million of principal plus accrued and unpaid interest under the TXOK Term Loan, repay approximately $171.8 million in principal plus accrued and unpaid interest under the TXOK Credit Facility, all incurred in connection with the ONEOK Energy acquisition; and repay $45.0 million on our Credit Agreement; and
•: pay fees and expenses in connection with the IPO.

Concurrent with the Closing of the IPO, including the redemption of the TXOK Preferred Stock, Holdings, our parent, merged with and into us, with EXCO being the surviving corporation. The outstanding shares of Holdings stock were cancelled as a result of the merger and such shares were exchanged for the same number of shares of our Common Stock. As a result of the merger, TXOK became a wholly-owned subsidiary of EXCO and TXOK and its subsidiaries became guarantors under EXCO's senior notes Indenture. EXCO also became a guarantor of certain collateralized revolving indebtedness of TXOK and TXOK likewise agreed to guarantee EXCO's collateralized revolving credit facility.

The TXOK Credit Facility is a $500.0 million revolving credit facility, subject to a semi-annually determined borrowing base. The initial borrowing base is $325.0 million, of which approximately $308.8 million was drawn down by TXOK to acquire ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C. As a result of the pay-down following the IPO, the outstanding balance was approximately $137.0 million plus accrued and unpaid interest.

144

The TXOK Credit Facility bears interest at a fluctuating rate of interest which is a variable margin in excess of reference rates based on either the prime rate or LIBOR. The margin increases with the borrowing base usage under the TXOK Credit Facility. The TXOK Credit Facility matures September 27, 2009 and is collateralized by a first priority lien and security interest in TXOK's oil and natural gas properties as well as the capital stock of its subsidiaries. The TXOK Credit Facility is guaranteed by all existing and future direct or indirect material domestic subsidiaries of TXOK as well as by EXCO and its subsidiaries.

The TXOK Credit Facility financial covenants include, among other covenants, the following:

•: minimum current ratio of 1.0 to 1.0;
•: maximum total debt to earnings before interest, income taxes, depreciation, amortization, and capital expenditures, or EBITDAX of 3.75x for the fourth quarter in 2005 (net of acquired ONEOK Energy hedges), with a step down to 3.5x beginning in the first quarter of 2006; and
•: minimum EBITDAX to interest of 2.5x.

On February 14, 2006, EXCO entered into the Sixth Amendment (Sixth Amendment) to its Credit Agreement. The Sixth Amendment permits the Borrowers to guarantee the debt and other obligations of TXOK under the TXOK Credit Facility. Upon consummation of the IPO, EXCO's access under the Credit Agreement to its full borrowing base of $145.0 million was restored.

On March 17, 2006, our U.S. credit agreement was amended to combine the TXOK credit facility into our credit agreement resulting in a new borrowing base of $750.0 million reflecting the addition of the TXOK assets. TXOK and its subsidiaries have become guarantors of our credit agreement. The amendment also provided for an extension of the credit agreement maturity date to December 31, 2010. The borrowing base will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices.

Borrowings under our amended and restated credit agreement were collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. As of March 17, 2006, borrowings are now collateralized by a first lien mortgage providing a security interest in the value of our proved reserves which is at least 125% of the Aggregate Commitment. The Aggregate Commitment is the lesser of (i) $1.25 billion, (ii) the borrowing base or (iii) $300.0 million. The Aggregate Commitment minimum of $300.0 million can be raised, from time to time, up to borrowing base of $750.0 million at our sole discretion. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus 0.50% plus an applicable margin or (ii) LIBOR plus an applicable margin.

On February 27, 2006, we entered into a revision of our office space lease in Dallas, Texas. This revision extends our lease two years to June 30, 2013 and obligates us to an additional $1.2 million of future minimum rental payments.

19. Consolidating Financial Statements (unaudited)

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary. The senior notes are jointly and severally guaranteed by

145

our current and some of our subsidiaries in the United States (referred to as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources, and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidaries. Addison was not a guarantor of the senior notes. Instead, the notes were collateralized, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison. This share pledge is limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock is not equal to or greater than 20% of then outstanding aggregate principal amount of the notes.

The following financial information presents consolidating financial statements, which include:

•: Resources;
•: the guarantor subsidiaries on a combined basis;
•: the non-guarantor subsidiary;
•: elimination entries necessary to consolidate Resources, the guarantor subsidiaries and the non-guarantor subsidiary; and
•: EXCO on a consolidated basis.

Rojo Pipeline, Inc., EXCO Investment I, LLC, and EXCO Investment II, LLC are guarantors of the senior notes. These companies have no material operations and, accordingly, these companies have been omitted from the guarantor financial information. Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the guarantor and non-guarantor subsidiaries are presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

146

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

December 31, 2004

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	8,535		$	7,472		$	—	$	—		$	16,007
Other current assets		12,132			12,902			—		—			25,034
Current assets of discontinued operations		—			—			34,807		—			34,807

Total current assets		20,667			20,374			34,807		—			75,848

Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		783			18,046			—		—			18,829
Proved developed and undeveloped oil and natural gas properties		70,569			383,759			—		—			454,328
Allowance for depreciation, depletion and amortization		(9,592	)		(22,115	)		—		—			(31,707	)

Oil and natural gas properties, net		61,760			379,690			—		—			441,450
Gas gathering, office and field equipment, net		1,935			25,079			—		—			27,014
Goodwill		19,984			—			—		—			19,984
Investments in and advances to affiliates		658,198			—			—		(658,198	)		—
Assets of discontinued operations		—			—			346,926		—			346,926
Other assets, net		10,779			22			—		—			10,801

Total assets	$	773,323		$	425,165		$	381,733	$	(658,198	)	$	922,023

Liabilities and Stockholder's Equity
Current liabilities	$	60,807		$	10,284		$	—	$	—		$	71,091
Current liabilities of discontinued operations		—			—			34,604		—			34,604
Long-term debt		487,453			—			—		—			487,453
Deferred income taxes		7,448			8,346			—		—			15,794
Other liabilities		30,532			6,963			—		—			37,495
Payable to parent		(16,668	)		118,564			191,702		(293,598	)		—
Liabilities of discontinued operations		—			—			71,835		—			71,835
Commitments and contingencies		—			—			—		—			—
Stockholder's equity		203,751			281,008			83,592		(364,600	)		203,751

Total liabilities and stockholder's equity	$	773,323		$	425,165		$	381,733	$	(658,198	)	$	922,023

147

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

December 31, 2005

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	189,537		$	35,454		$	—	$	—		$	224,991
Other current assets		67,777			47,738			—		—			115,515

Total current assets		257,314			83,192			—		—			340,506

Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		49			53,072			—		—			53,121
Proved developed and undeveloped oil and natural gas properties		94,872			778,723			—		—			873,595
Allowance for depreciation, depletion and amortization		(1,650	)		(11,631	)		—		—			(13,281	)

Oil and natural gas properties, net		93,271			820,164			—		—			913,435
Gas gathering, office and field equipment, net		2,423			30,848			—		—			33,271
Goodwill		76,786			143,220			—		—			220,006
Investments in and advances to affiliates		891,817			—			—		(891,817	)		—
Other assets, net		—			419			—		—			419

Total assets	$	1,321,611		$	1,077,843		$	—	$	(891,817	)	$	1,507,637

Liabilities and Stockholder's Equity
Current liabilities	$	418,833		$	52,546		$	—	$	—		$	471,379
Long term debt		461,802			—			—		—			461,802
Deferred income taxes		33,842			100,761			—		—			134,603
Other liabilities		56,975			40,197			—		—			97,172
Payable to Parent		7,478			371,199			—		(378,677	)		—
Commitments and contingencies		—			—			—		—			—
Stockholder's equity		342,681			513,140			—		(513,140	)		342,681

Total liabilities and stockholder's equity	$	1,321,611		$	1,077,884		$	—	$	(906,603	)	$	1,507,637

148

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the 209 day period ended July 28, 2003

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiaries		Eliminations			Consolidated
Revenues and other income:
Oil and natural gas sales	$	7,502		$	14,901		$	—	$	—		$	22,403
Other income (loss)		(1,129	)		—			—		—			(1,129	)
Equity in earnings of subsidiaries		18,068			—			—		(18,068	)		—

Total revenues and other income		24,441			14,901			—		(18,068	)		21,274

Costs and expenses:
Oil and natural gas production		7,361			4,019			—		—			11,380
Depreciation, depletion and amortization		3,158			1,967			—		—			5,125
Accretion of discount on asset retirement obligations		240			80			—		—			320
General and administrative		11,347			—			—		—			11,347
Interest		1,058			—			—		—			1,058

Total costs and expenses		23,164			6,066			—		—			29,230

Income (loss) before income taxes		1,277			8,835			—		(18,068	)		(7,956	)
Income tax expense (benefit)		(181	)		—			—		—			(181	)

Income (loss) before discontinued operations and cumulative effect of change in accounting principles		1,458			8,835			—		(18,068	)		(7,775	)

Discontinued operations:
Income from operations		—			—			13,534		—			13,534
Income tax expense		—			—			4,982		—			4,982

Income from discontinued operations, net of tax		—			—			8,552		—			8,552

Income before cumulative effect of change in accounting principle		1,458			8,835			8,552		(18,068	)		777
Cumulative effect of change in accounting principle, net of income tax		(426	)		(135	)		816		—			255

Net income	$	1,032		$	8,700		$	9,368	$	(18,068	)	$	1,032

149

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the 156 day period ended December 31, 2003

(in thousands)	Resources			Guarantor subsidiaries		Non-guarantor subsidiaries		Eliminations			Consolidated
Revenues and other income:
Oil and natural gas sales	$	13,939		$	7,828	$	—	$	—		$	21,767
Commodity price risk management activities		(10,800	)		—		—		—			(10,800	)
Other loss		(161	)		—		—		—			(161	)
Equity in earnings of subsidiaries		7,807			—		—		(7,807	)		—

Total revenues and other income		10,785			7,828		—		(7,807	)		(7,807	)

Costs and expenses:
Oil and natural gas production		5,219			2,112		—		—			7,331
Depreciation, depletion and amortization		3,251			2,162		—		—			5,413
Accretion of discount on asset retirement obligations		158			47		—		—			205
General and administrative		3,823			—		—		—			3,823
Interest		1,921			—		—		—			1,921

Total costs and expenses		14,372			4,321		—		—			18,693

Income (loss) before income taxes		(3,587	)		3,507		—		(7,807	)		(7,887	)
Income tax benefit		(7,764	)		—		—		—			(7,764	)

Income before discontinued operations:		4,177			3,507		—		(7,807	)		(123	)

Discontinued operations:
Income from operations		—			—		6,217		—			6,217
Income tax expense		—			—		1,917		—			1,917

Income from discontinued operations, net of tax		—			—		4,300		—			4,300

Net income	$	4,177		$	3,507	$	4,300	$	(7,807	)	$	4,177

150

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the year ended December 31, 2004

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiaries		Eliminations			Consolidated
Revenues and other income:
Oil and natural gas sales	$	39,993		$	102,000		$	—	$	—		$	141,993
Commodity price risk management activities		(18,055	)		(32,288	)		—		—			(50,343	)
Other income (loss)		4,262			877			—		(3,998	)		1,141
Equity in earnings of subsidiaries		41,164			—			—		(41,164	)		—

Total revenues and other income		67,364			70,589			—		(45,162	)		92,791

Costs and expenses:
Oil and natural gas production		11,563			16,693			—		—			28,256
Depreciation, depletion and amortization		7,148			21,371			—		—			28,519
Accretion of discount on asset retirement obligations		348			452			—		—			800
General and administrative		11,412			3,863			—		—			15,275
Interest		34,432			4,136			—		(3,998	)		34,570

Total costs and expenses		64,903			46,515			—		(3,998	)		107,420

Income (loss) before income taxes		2,461			24,074			—		(41,164	)		(14,629	)
Income tax expense		504			4,622			—		—			5,126

Income before discontinued operations		1,957			19,452			—		(41,164	)		(19,755	)

Discontinued operations:
Income from operations		5,114			—			31,160		—			36,274
Income tax expense		910			—			9,448		—			10,358

Income from discontinued operations, net of tax		4,204			—			21,712		—			25,916

Net income	$	6,161		$	19,452		$	21,712	$	(41,164	)	$	6,161

151

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the 275 day period ended October 2, 2005

(in thousands)		Resources			Guarantor subsidiaries			Non-guarantor subsidiary			Eliminations			Consolidated
Revenues:
Oil and natural gas sales		$	22,861		$	109,960		$	—		$	—		$	132,821
Commodity price risk management activities			(56,705	)		(120,548	)		—			—			(177,253	)
Other income (loss)			32,052			1,349			—			(26,326	)		7,075
Equity in earnings of subsidiaries			(43,080	)		—			—			43,080			—

Total revenues			(44,872	)		(9,239	)		—			16,754			(37,357	)

Costs and expenses:
Oil and natural gas production			6,772			15,385			—			—			22,157
Depreciation, depletion and amortization			3,978			20,709			—			—			24,687
Accretion of discount on asset retirement obligations			235			382			—			—			617
General and administrative			79,219			10,125			—			—			89,344
Interest			26,673			26,328			—			(26,326	)		26,675

Total costs and expenses			116,877			72,929			—			(26,326	)		163,480

Loss before income taxes			(161,749	)		(82,168	)		—			43,080			(200,837	)
Income tax benefit			(21,538	)		(42,160	)		—			—			(63,698	)

Loss before discontinued operations			(140,211	)		(40,008	)		—			43,080			(137,139	)

Discontinued operations:
	Loss from operations		—			—			(4,403	)		—			(4,403	)
	Gain on disposition of Addison Energy Inc		175,717			—			—			—			175,717
	Income tax (benefit) expense		50,613			—			(1,331	)		—			49,282

Income from discontinued operations, net of tax			125,104			—			(3,072	)		—			122,032

Net loss		$	(15,107	)	$	(40,008	)	$	(3,072	)	$	43,080		$	(15,107	)

152

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)

For the 90 day period ended December 31, 2005

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations			Consolidated
Revenues:
Oil and natural gas sales	$	8,463		$	61,598		$	—	$	—		$	70,061
Commodity price risk management activities		2,856			(3,112	)		—		—			(256	)
Other income (loss)		7,920			520			—		(6,075	)		2,365
Equity in earnings of subsidiaries		21,217			—			—		(21,217	)		—

Total revenues		40,456			59,006			—		(27,292	)		72,170

Costs and expenses:
Oil and natural gas production		1,784			7,165			—		—			8,949
Depreciation, depletion and amortization		1,869			12,202			—		—			14,071
Accretion of discount on asset retirement obligations		70			156			—		—			226
General and administrative		4,798			1,427			—		—			6,225
Interest		19,413			6,076			—		(6,075	)		19,414

Total costs and expenses		27,934			27,026			—		(6,075	)		48,885

Income before income taxes		12,522			31,980			—		(21,217	)		23,285
Income tax expense (benefit)		(3,442	)		10,763			—		—			7,321

Net income (loss)	$	15,964		$	21,217		$	—	$	(21,217	)	$	15,964

153

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the 209 day period ended July 28, 2003

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(9,910	)	$	10,882		$	19,446		$	—		$	20,418

Investing Activities:
Additions to oil and natural gas property and equipment		(3,517	)		(684	)		—			—			(4,201	)
Proceeds from dispositions of property and equipment		2,773			3,247			—			—			6,020
Advances/investments with affiliates		19,544			(13,445	)		—			(6,099	)		—
Proceeds from sales of marketable securities		422			—			—			—			422
Net cash used in investing activities of discontinued operations		—			—			(31,859	)		6,099			(25,760	)
Other investing activities		(1	)		—			—			—			(1	)

Net cash provided by (used in) investing activities		19,221			(10,882	)		(31,859	)		—			(23,520	)

Financing Activities:
Proceeds from long-term debt		20,638			—			—			—			20,638
Payments on long-term debt		(11,750	)		—			—			—			(11,750	)
Proceeds from exercise of stock options		12,737			—			—			—			12,737
Purchase of common stock from employees in connection with the merger		(17,874	)		—			—			—			(17,874	)
Purchase of director and employee stock options in connection with the merger		(3,567	)		—			—			—			(3,567	)
Payment of fees and expenses in connection with the merger		(563	)		—			—			—			(563	)
Preferred stock dividends		(2,620	)		—			—			—			(2,620	)
Deferred financing costs		(1,136	)		—			—			—			(1,136	)
Net cash provided by financing activities of discontinued operations		(32	)		—			13,977			—			13,945
Other financing costs		172			—			—			—			172

Net cash provided by (used in) financing activities		(3,995	)		—			13,977			—			9,982

Net increase in cash		5,316			—			1,564			—			6,880
Effect of exchange rates on cash and cash equivalents		—			—			58			—			58
Cash at beginning of period		1,867			—			75			—			1,942

Cash at end of period	$	7,183		$	—		$	1,697		$	—		$	8,880

154

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the 156 day period ended December 31, 2003

(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	4,633		$	5,716		$	11,371		$	—	$	21,720

Investing Activities:
Additions to oil and natural gas property and equipment		(6,282	)		(15,440	)		—			—		(21,722	)
Proceeds from dispositions of property and equipment		508			1,795			—			—		2,303
Advances/investments with affiliates		(5,980	)		7,929			—			—		1,949
Proceeds from sales of marketable securities		1,393			—			—			—		1,393
Net cash used in investing activities of discontinued operations		521			—			(23,439	)		—		(22,918	)
Other investing activities		467			—			—			—		467

Net cash used in investing activities		(9,373	)		(5,716	)		(23,439	)		—		(38,528	)

Financing Activities:
Proceeds from long-term debt		58,520			—			—			—		58,520
Payments on long-term debt		(56,000	)		—			—			—		(56,000	)
Net cash provided by operating activities of discontinued operations		—			—			14,035			—		14,035
Deferred financing costs and other		(1,591	)		—			—			—		(1,591	)

Net cash provided by financing activities		929			—			14,035			—		14,964

Net increase (decrease) in cash		(3,811	)		—			1,967			—		(1,844	)
Effect of exchange rates on cash and cash equivalents		—			—			297			—		297
Cash at beginning of period		7,183			—			1,697			—		8,880

Cash at end of period	$	3,372		$	—		$	3,961		$	—	$	7,333

155

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the year ended December 31, 2004

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	219		$	63,643		$	54,771		$	—	$	118,633

Investing Activities:
Additions to oil and natural gas property and equipment		(15,547	)		(123,974	)		—			—		(139,521	)
Proceeds from dispositions of property and equipment		47,364			4,501			—			—		51,865
Purchase of North Coast Energy, Inc		(225,562	)		10,429			—			—		(215,133	)
Advances/investments with affiliates		(177,456	)		52,873			124,734			—		151
Proceeds from sales of marketable securities		1,296			—			—			—		1,296
Net cash used in investing activities of discontinued operations		—			—			(79,983	)		—		(79,983	)
Other investing activities		—			—			—			—		—

Net cash provided by (used in) investing activities		(369,905	)		(56,171	)		44,751			—		(381,325	)

Financing Activities:
Proceeds from long-term debt		546,350			—			—			—		546,350
Payments on long-term debt		(158,070	)		—			—			—		(158,070	)
Net cash used in financing activities of discontinued operations		—			—			(91,397	)		—		(91,397	)
Deferred financing costs and other		(13,431	)		—			—			—		(13,431	)

Net cash provided by (used in) financing activities		374,849			—			(91,397	)		—		283,452

Net increase in cash		5,163			7,472			8,125			—		20,760
Effect of exchange rates on cash and cash equivalents		—			—			(1,685	)		—		(1,685	)
Cash at beginning of period		3,372			—			3,961			—		7,333

Cash at end of period	$	8,535		$	7,472		$	10,401		$	—	$	26,408

156

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the 275 day period ended October 2, 2005

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash proviced by (used in) operating activities)	$	(76,147	)	$	14,285		$	(19,158	)	$	—	$	(81,020	)

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		3,983			(155,131	)		—			—		(151,144	)
Proceeds from dispositions of non-oil and natural gas properties		—			—			—			—		—
Proceeds from dispositions of oil and natural gas properties		(160	)		46,170			—			—		46,010
Advances/investments with affiliates		(58,523	)		107,719			(48,987	)		—		209
Proceeds from the sale of Addison		444,812			—			(1,415	)		—		443,397
Proceeds from sales of marketable securities		59			—			—			—		59
Net cash used in investing activities of discontinued operations		—			—			(442	)		—		(442	)
Other investing activities		—			—			—			—		—

Net cash provided by (used in) investing activities		390,175			(1,242	)		(50,844	)		—		338,089

Financing Activities:
Proceeds from long-term debt		41,300			—			—			—		41,300
Payments on long-term debt		(148,247	)		—			—			—		(148,247	)
Deferred financing costs and other		—			—			—			—		—
Net cash used in financing of discontinued operations		—			—			59,601			—		59,601

Net cash provided by (used in) financing activities		(106,947	)		—			59,601			—		(47,346	)

Net increase (decrease) in cash		207,081			13,043			(10,401	)		—		209,723
Cash at the beginning of the period		8,535			7,472			10,401			—		26,408

Cash at end of period	$	215,616		$	20,515		$	—		$	—	$	236,131

157

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the 90 day period ended December 31, 2005

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(19,500	)	$	27,240		$	—	$	—	$	7,740

Investing Activities:
Additions to oil and natural gas property, gathering systems and equipment		(1,153	)		(12,054	)		—		—		(13,207	)
Proceeds from dispositions of property and equipment		(145	)		(248	)		—		—		(393	)

Net cash used in investing activities		(1,298	)		(12,302	)		—		—		(13,600	)

Financing Activities:
Proceeds from long-term debt		9,999			—			—		—		9,999
Payments on long-term debt		(15,279	)		—			—		—		(15,279	)

Net cash used in financing activities		(5,280	)		—			—		—		(5,280	)

Net increase (decrease) in cash		(26,078	)		14,938			—		—		(11,140	)
Effect of exchange rates on cash and cash equivalents		—			—			—		—		—
Cash at the beginning of the period		215,616			20,515			—		—		236,131

Cash at end of period	$	189,538		$	35,453		$	—	$	—	$	224,991

158

20. Supplemental information relating to oil and natural gas producing activities—continuing operations (unaudited)

Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities (excluding all amounts related to Addison, our former Canadian subsidiary):

(in thousands, except per unit amounts)
For the 209 day period from January 1, 2003 to July 28, 2003:
Proved property acquisition costs	$	1,474
Development costs		2,622
Capitalized asset retirement costs		37
Depreciation, depletion and amortization per Boe	$	4.16
Depreciation, depletion and amortization per Mcfe	$	0.69
For the 156 day period from July 29, 2003 to December 31, 2003:
Proved property acquisition costs	$	14,183
Development costs		6,326
Capitalized asset retirement costs		49
Depreciation, depletion and amortization per Boe	$	6.45
Depreciation, depletion and amortization per Mcfe	$	1.07
2004:
Proved property acquisition costs	$	285,811
Unproved property acquisition costs		17,669

Total property acquisition costs(1)		303,480
Development and exploration costs(2)		36,742
Capitalized asset retirement costs		8,462
Depreciation, depletion and amortization per Boe	$	7.42
Depreciation, depletion and amortization per Mcfe	$	1.24
For the 275 day period from January 1, 2005 to October 2, 2005:
Proved property acquisition costs	$	103,222
Development and exploration costs(2)		39,900
Capitalized asset retirement costs		1,686
Depreciation, depletion and amortization per Boe	$	8.35
Depreciation, depletion and amortization per Mcfe	$	1.39
For the 90 day period from October 3, 2005 to December 31, 2005:
Development and exploration costs(2)		13,194
Capitalized asset retirement costs		51
Depreciation, depletion and amortization per Boe	$	14.54
Depreciation, depletion and amortization per Mcfe	$	2.42

(1): Includes $199.3 million that was allocated to oil and natural gas properties in the North Coast purchase price allocation.
(2): Exploration costs are not considered material.

159

We retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil, natural gas and NGL reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise. All amounts related to Addison, our former Canadian subsidiary, have been excluded from the information contained in this note.

Estimated quantities of proved reserves

(in thousands)		Oil (Bbls)		Natural gas (Mcf)		NGLs (Bbls)(1)		Mcfe(2)
December 31, 2002		12,281		141,598		1,097		221,866
	Purchase of reserves in place	153		22,133		45		23,321
	New discoveries and extensions	528		5,810		—		8,978
	Revisions of previous estimates	(93	)	(2,164	)	(205	)	(3,952	)
	Production	(755	)	(7,551	)	(59	)	(12,435	)
	Sales of reserves in place	(1,624	)	(3,764	)	(51	)	(13,814	)

December 31, 2003		10,490		156,062		827		223,964
	Purchase of reserves in place	1,651		229,837		—		239,743
	New discoveries and extensions	537		21,109		18		24,439
	Revisions of previous estimates	(381	)	432		39		(1,620	)
	Production	(638	)	(18,860	)	(60	)	(23,048	)
	Sales of reserves in place	(4,426	)	(27,469	)	(613	)	(57,703	)

December 31, 2004		7,233		361,111		211		405,775
	Purchase of reserves in place	60		59,780		—		60,140
	New discoveries and extensions	354		31,500		—		33,624
	Revisions of previous estimates	16		(10,383	)	(191	)	(11,433	)
	Production	(491	)	(20,482	)	(20	)	(23,548	)
	Sales of reserves in place	(343	)	(17,886	)	—		(19,944	)

December 31, 2005		6,829		403,640		—		444,614

160

Estimated quantities of proved developed reserves

(in thousands)	Oil (Bbls)	Natural gas (Mcf)	NGLs (Bbls)(1)	Mcfe(2)
December 31, 2003	7,750	123,897	724	174,741
December 31, 2004	6,022	318,044	211	355,442
December 31, 2005	5,534	324,326	—	357,530

(1): Beginning December 31, 2005, NGL's are no longer tracked separately as they are considered immaterial.
(2): Mcfe-One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Standardized measure of discounted future net cash flows

We have summarized the Standardized Measure related to our proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you

161

should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

(in thousands)
Year ended December 31, 2003:
Future cash inflows	$	1,214,803
Future production and development costs		413,968
Future income taxes		254,719

Future net cash flows		546,116
Discount of future net cash flows at 10% per annum		312,031

Standardized measure of discounted future net cash flows	$	234,085

Year ended December 31, 2004:
Future cash inflows	$	2,573,281
Future production, development and abandonment costs		792,906
Future income taxes		582,480

Future net cash flows		1,197,895
Discount of future net cash flows at 10% per annum		724,505

Standardized measure of discounted future net cash flows	$	473,390

Year ended December 31, 2005:
Future cash inflows	$	4,859,073
Future production, development and abandonment costs		1,203,442
Future income taxes		1,282,599

Future net cash flows		2,373,032
Discount of future net cash flows at 10% per annum		1,442,705

Standardized measure of discounted future net cash flows	$	930,327

During recent years, prices paid for oil and natural gas have fluctuated significantly. The NYMEX spot prices at December 31, 2003, 2004 and 2005 used in the above table, were $32.52, $43.45 and $61.04 per Bbl of oil, respectively, and $6.19, $6.15 and $11.23 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials between NYMEX and local prices.

162

Changes in standardized measure

The following are the principal sources of change in the Standardized Measure:

(in thousands)
Year ended December 31, 2003:
Sales and transfers of oil and natural gas produced, net of production costs	$	(39,032	)
Net changes in prices and production costs		77,635
Extensions and discoveries, net of future development and production costs		11,126
Development costs during the period		8,669
Changes in estimated future development costs		(6,025	)
Revisions of previous quantity estimates		(8,673	)
Sales of reserves in place		(19,806	)
Purchase of reserves in place		25,619
Accretion of discount before income taxes		28,384
Changes in timing, foreign currency translation and other		(16,982	)
Net change in income taxes		20,247

Net change	$	81,162

Year ended December 31, 2004:
Sales and transfers of oil and natural gas produced, net of production costs	$	(114,116	)
Net changes in prices and production costs		68,474
Extensions and discoveries, net of future development and production costs		34,433
Development costs during the period		36,793
Changes in estimated future development costs		17,798
Revisions of previous quantity estimates		(23,751	)
Sales of reserves in place		(81,485	)
Purchase of reserves in place		320,788
Accretion of discount before income taxes		56,033
Changes in timing, foreign currency translation and other		(42,019	)
Net change in income taxes		(33,643	)

Net change	$	239,305

Year ended December 31, 2005:
Sales and transfers of oil and natural gas produced, net of production costs	$	(171,775	)
Net changes in prices and production costs		676,877
Extensions and discoveries, net of future development and production costs		103,361
Development costs during the period		53,094
Changes in estimated future development costs		(59,066	)
Revisions of previous quantity estimates		(21,654	)
Sales of reserves in place		(29,363	)
Purchase of reserves in place		117,572
Accretion of discount before income taxes		69,787
Changes in other		(11,868	)
Net change in income taxes		(270,028	)

Net change	$	456,937

163

20. Supplemental information relating to oil and natural gas producing activities—discontinued operations (unaudited)

Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities of our discontinued operations, which relate to Addison, our former Canadian subsidiary:

(in thousands, except per unit amounts)
For the 209 day period from January 1, 2003 to July 29, 2003:
Property acquisition costs	$	10,837
Development costs		14,705
Capitalized asset retirement costs		203
Depreciation, depletion and amortization per Boe	$	5.10
Depreciation, depletion and amortization per Mcfe	$	0.85
For the 156 day period from July 29, 2003 to December 31, 2003:
Property acquisition costs	$	4,954
Development costs		17,486
Capitalized asset retirement costs		980
Depreciation, depletion and amortization per Boe	$	6.99
Depreciation, depletion and amortization per Mcfe	$	1.17
2004:
Property acquisition costs	$	43,178
Development costs		33,258
Capitalized asset retirement costs		2,388
Depreciation, depletion and amortization per Boe	$	6.86
Depreciation, depletion and amortization per Mcfe	$	1.14
For the 275 day period from January 1, 2005 to October 2, 2005:
Property acquisition costs	$	16
Development and exploration costs		272
Capitalized asset retirement costs		—
Depreciation, depletion and amortization per Boe	$	7.49
Depreciation, depletion and amortization per Mcfe	$	1.16

We retained independent engineering firms for 2003 and used our internal engineers for 2004 to provide annual year-end estimates of our future net recoverable oil, natural gas and NGL reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.

164

Estimated quantities of proved reserves—discontinued operations

(in thousands)		Oil (Bbls)		Natural gas (Mcf)		NGLs (Bbls)		Mcfe(1)
December 31, 2002		5,754		107,695		3,994		166,183
	Purchase of reserves in place	115		9,563		354		12,377
	New discoveries and extensions	724		21,459		973		31,641
	Revisions of previous estimates	641		(3,965	)	1,985		11,791
	Production	(448	)	(8,360	)	(332	)	(13,040	)
	Sales of reserves in place	—		—		—		—

December 31, 2003		6,786		126,392		6,974		208,952
	Purchase of reserves in place	1,378		17,105		455		28,103
	New discoveries and extensions	656		19,570		1,130		30,286
	Revisions of previous estimates	1,068		14,450		1,586		30,374
	Production	(549	)	(10,345	)	(643	)	(17,497	)
	Sales of reserves in place	—		—		—		—

December 31, 2004		9,339		167,172		9,502		280,218
	Purchase of reserves in place	—		—		—		—
	New discoveries and extensions	—		—		—		—
	Revisions of previous estimates	—		—		—		—
	Production	(64	)	(1,142	)	(84	)	(2,030	)
	Sales of reserves in place	(9,275	)	(166,030	)	(9,418	)	(278,188	)

December 31, 2005		—		—		—		—

Estimated quantities of proved developed reserves—discontinued operations

(in thousands)		Oil (Bbls)		Natural gas (Mcf)		NGLs (Bbls)		Mcfe(1)
December 31, 2003		6,529		117,030		6,377		194,466
December 31, 2004		8,825		155,012		9,250		263,462

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

Standardized measure of discounted future net cash flows—discontinued operations

We have summarized the Standardized Measure related to Addison's proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect

165

current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.

	(in thousands)
Year ended December 31, 2003:
Future cash inflows	$	953,165
Future production and development costs		364,305
Future income taxes		165,069

Future net cash flows		423,791
Discount of future net cash flows at 10% per annum		204,772

Standardized measure of discounted future net cash flows	$	219,019

Year ended December 31, 2004:
Future cash inflows	$	1,525,346
Future production, development and abandonment costs		502,980
Future income taxes		295,697

Future net cash flows		726,669
Discount of future net cash flows at 10% per annum		366,833

Standardized measure of discounted future net cash flows	$	359,836

Year ended December 31, 2005:
Future cash inflows	$	—
Future production, development and abandonment costs		—
Future income taxes		—

Future net cash flows		—
Discount of future net cash flows at 10% per annum		—

Standardized measure of discounted future net cash flows	$	—

During The NYMEX spot prices at December 31, 2003 and 2004 used in the above table, were $32.52 and $43.45 per Bbl of oil, respectively, and $6.19 and $6.15 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials between NYMEX and local prices.

166

Changes in standardized measure—discontinued operations

The following are the principal sources of change in the Standardized Measure:

(in thousands)
Year ended December 31, 2003:
Sales and transfers of oil and natural gas produced, net of production costs	$	(47,773	)
Net changes in prices and production costs		(7,053	)
Extensions and discoveries, net of future development and production costs		47,518
Development costs during the period		25,478
Changes in estimated future development costs		(16,614	)
Revisions of previous quantity estimates		18,054
Sales of reserves in place		—
Purchase of reserves in place		21,509
Accretion of discount before income taxes		24,595
Changes in timing, foreign currency translation and other		(28,329	)
Net change in income taxes		24,217

Net change	$	61,602

Year ended December 31, 2004:
Sales and transfers of oil and natural gas produced, net of production costs	$	(74,160	)
Net changes in prices and production costs		79,167
Extensions and discoveries, net of future development and production costs		55,950
Development costs during the period		33,258
Changes in estimated future development costs		(20,516	)
Revisions of previous quantity estimates		56,311
Sales of reserves in place		—
Purchase of reserves in place		61,904
Accretion of discount before income taxes		30,119
Changes in timing, foreign currency translation and other		(31,253	)
Net change in income taxes		(49,963	)

Net change	$	140,817

Year ended December 31, 2005:
Sales and transfers of oil and natural gas produced, net of production costs	$	(8,756	)
Development costs during the period		272
Accretion of discount before income taxes		2,999
Changes in timing, foreign currency translation and other		(11,002	)
Sales of reserves in place		(343,349	)

Net change	$	(359,836	)

167

21. Selected Quarterly Financial Information (Unaudited)

Selected Quarterly Financial Information (Unaudited)

	2005
	Private Predecessor											Successor
				As Restated(1)					2 Day period from October 1 to October 2			90 day period from October 3 to December 31
(in thousands, except per share amounts)				As Restated(1)
(in thousands, except per share amounts)	March 31			June 30		September 30
Total revenues	$	(18,079	)	$	31,653	$	(52,333	)	$	1,402		$	72,170
Income (loss) from continuing operations		(28,639	)		4,452		(49,715	)		(63,237	)		15,964
Income from discontinued operations		120,884			1,148		—			—			—
Basic earnings (loss) per share		N/A			N/A		N/A			N/A			N/A
Diluted earnings (loss) per share		N/A			N/A		N/A			N/A			N/A
Total assets		847,329			870,152		910,464			911,072			1,507,637
Long-term debt, less current maturities		452,853			452,750		452,644			452,642			461,801
Stockholder's equity		274,613			280,230		230,515			209,692			342,681

	2004
	Private Predecessor
(in thousands, except per share amounts)	Private Predecessor
(in thousands, except per share amounts)	March 31			June 30		September 30			December 31
Total revenues	$	5,571		$	20,970	$	5,271		$	60,979
Net income (loss)		(9,066	)		2,756		(11,090	)		23,561
Basic earnings (loss) per share		N/A			N/A		N/A			N/A
Diluted earnings (loss) per share		N/A			N/A		N/A			N/A
Total assets		770,268			796,665		856,813			922,023
Long-term debt, less current maturities		350,001			453,153		470,051			487,453
Stockholder's equity		173,808			174,804		171,962			203,751

	2003
	Public Predecessor							Private Predecessor
(in thousands, except per share amounts)	March 31		June 30		28 Day Period From July 1 to July 28			64 Day Period From July 29 to September 30		December 31
Total revenues	$	7,344	$	10,318	$	3,612		$	8,817	$	1,969
Net income (loss)		4,349		3,718		(7,035	)		3,726		451
Basic earnings (loss) per share		0.43		0.34		(0.58	)		N/A		N/A
Diluted earnings (loss) per share		0.35		0.29		(0.58	)		N/A		N/A

(1): EXCO restated its second and third quarter financial statements due to a misapplication of SFAS No. 109 related to the recording of an income tax benefit on an extraordinary dividend received from Addison.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

We maintain "disclosure controls and procedures," as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable assurance of achieving the desired control objectives and we necessarily are required to apply our judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures.

Our management evaluated, under the supervision and with the participation of our CEO and our CFO who is also our Chief Accounting Officer, collectively referred to as the disclosure committee, the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2005.

Based upon this evaluation and solely because of the material weakness described below, our CEO and CFO have concluded that our disclosure controls and procedures were not effective as of December 31, 2005. Notwithstanding the material weakness described below, we believe our consolidated financial statements included in this annual report on Form 10-K fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles.

Material weakness in internal control over financing reporting

Our management has concluded that as of December 31, 2005, we did not maintain effective controls over the preparation and review of the quarterly and annual tax provision and the related financial statement presentation and disclosure of income tax matters. Specifically, our controls were not adequate to ensure the completeness and accuracy of the tax provision and the deferred tax balances, including the timing and classification of recording the tax impact of an extraordinary dividend. This control deficiency resulted in the restatement of our consolidated financial statements for the quarters ended June 30, 2005 and September 30, 2005 and audit adjustments to the consolidated financial statements for the years ended December 31, 2004 and 2005, affecting income tax expense and the deferred tax liability accounts. Additionally, this control deficiency could result in a misstatement in the aforementioned tax accounts that would result in a material misstatement to the annual or interim financial statements that would not be prevented or detected. Accordingly, management has concluded that this deficiency in internal control over financial reporting is a material weakness.

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Remediation of material weakness

During 2005, the following remedial activities have been undertaken to address the material weakness described above:

•: We added additional staff to our accounting and tax departments.
•: We hired additional finance and accounting personnel and expanded the scope of the work of the outside consulting firm that we use to review our quarterly and annual tax provisions and related deferred taxes.
•: We implemented more stringent reviews of the quarterly tax provision.

We believe that once fully implemented, these steps will be adequate to address all open matters related to the material weakness described above.

Changes in internal control over financial reporting

There were no changes to our internal control over financial reporting during our last fiscal quarter ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

At the end of fiscal 2007, Section 404 of the Sarbanes-Oxley Act will require our management to provide an assessment of the effectiveness of our internal control over financial reporting, and our independent registered public accountants will be required to audit management's assessment. We are in the process of performing the system and process documentation, evaluation and testing required for management to make this assessment and for its independent registered public accountants to provide their attestation report. We have not completed this process or its assessment, and this process will require significant amounts of management time and resources. In the course of evaluation and testing, management may identify deficiencies that will need to be addressed and remediated.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Executive officers and directors

The following table sets forth certain information with respect to our executive officers and directors.

Name	Age	Position(s)
Douglas H. Miller	58	Chairman and Chief Executive Officer
Stephen F. Smith	64	Vice Chairman, President and Secretary
J. Douglas Ramsey, Ph.D	45	Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer
Harold L. Hickey	50	Vice President and Chief Operating Officer
Jeffrey D. Benjamin(1)(2)(3)	44	Director
Earl E. Ellis(1)(2)(3)	64	Director
Robert H. Niehaus(1)(2)(3)	50	Director
Boone Pickens	77	Director
Robert L. Stillwell(2)(3)	69	Director

(1): Member of our audit committee
(2): Member of our compensation committee
(3): Member of our nominating and corporate governance committee

Douglas H. Miller became the Chairman of our board of directors and our Chief Executive Officer in December 1997. Mr. Miller was Chairman of the board of directors and Chief Executive Officer of Coda Energy, Inc., or Coda, an independent oil and natural gas company, from October 1989 until November 1997 and served as a director of Coda from 1987 until November 1997.

Stephen F. Smith joined us in June 2004 as Vice Chairman of our board of directors and was appointed President and Secretary in October 2005. Prior to joining us, Mr. Smith was co-founder and Executive Vice President of Sandefer Oil and Gas, Inc., an independent oil and gas exploration and production company, from January 1980 to June 2004. Mr. Smith was one of our directors from March 1998 to July 2003. Prior to 1980, Mr. Smith was an Audit Partner with Arthur Andersen LLP.

J. Douglas Ramsey, Ph.D., became our Chief Financial Officer and a Vice President in December 1997. Dr. Ramsey was one of our directors from March 1998 until October 5, 2005. From March 1992 to December 1997, Dr. Ramsey worked for Coda as Financial Analyst and Assistant to the President and then as Financial Planning Manager. Dr. Ramsey also taught finance at Southern Methodist University in their undergraduate and professional MBA programs.

Harold L. Hickey became our Vice President and Chief Operating Officer in October 2005. Prior to then and beginning in January 2004, Mr. Hickey served as President of our wholly-owned subsidiary, North Coast. Mr. Hickey was our Production and Asset Manager from February 2001 to January 2004. From April 2000 until he joined us, Mr. Hickey was Chief Operating Officer of Inca Natural Resources Group, L.P., an independent oil and natural gas exploration company. Prior to that, Mr. Hickey worked at Mobil Oil Corporation from 1979 to March 2000.

Jeffrey D. Benjamin became one of our directors in October 2005 and was previously one of our directors from August 1998 through July 2003 and a director of our parent holding company from July 2003 through its merger into us. Mr. Benjamin has been a Senior Advisor to Apollo Management, LP since September 2002. He had previously been a Managing Director of Libra Securities LLC, an investment banking firm, from January 2002 to September 2002 and served as Co-Chief Executive

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Officer of Libra Securities from January 1999 to December 2001. Mr. Benjamin is also a director of Dade Behring Holdings Inc., Chiquita Brands International, Inc. and NTL Incorporated.

Earl E. Ellis became one of our directors in October 2005 and was previously one of our directors from March 1998 through July 2003. Mr. Ellis has served as chairman and chief executive officer of Carolina Soy Products, a soy based product manufacturing company since September 2003. Mr. Ellis has also been a private investor since 2001. He served as a Director of Coda from 1992 until 1996. Mr. Ellis served as a managing partner of Benjamin Jacobson & Sons, LLC, specialists on the New York Stock Exchange. He had been associated with Benjamin Jacobson & Sons, LLC from 1977 to 2001.

Robert H. Niehaus became one of our directors in November 2004 and was a director of our parent holding company from July 2003 through its merger into us. Mr. Niehaus is the Chairman and Managing Partner of Greenhill Capital Partners, LLC, a private equity investment firm, and a Managing Director of Greenhill & Co., LLC. Prior to joining Greenhill in January 2000 to start its private equity business, Mr. Niehaus was a Managing Director in Morgan Stanley's private equity investment department from 1990 to 1999. Mr. Niehaus is a director of the American Italian Pasta Company, Global Signal Inc., Heartland Payment Systems, Inc. and several private companies.

Boone Pickens became one of our directors in October 2005 and was previously one of our directors from March 1998 through July 2003. Mr. Pickens has served as the Chairman and CEO of BP Capital LP since September 1996 and Mesa Water, Inc. since August 2000 and is a board member of Clean Energy. BP Capital LP or affiliates is the general partner and an investment advisor of private funds investing in energy commodities (BP Capital Energy Fund) and publicly-traded energy equities (BP Capital Equity Fund and its offshore counterpart). Clean Energy is the largest provider of natural gas (CNG and LNG) and related services in North America. He was the founder of Mesa Petroleum Co., an independent oil and natural gas exploration and production company. He served as CEO and Chairman of the Board of Mesa from its inception until his departure in 1996. See "Related party transactions—ONEOK Energy acquisition" for a description of certain related party transactions involving Mr. Pickens.

Robert L. Stillwell became one of our directors in October 2005. Mr. Stillwell has served as the General Counsel of BP Capital LP, Mesa Water, Inc. and affiliated companies engaged in the petroleum business since 2001. Mr. Stillwell was a lawyer and Senior Partner at Baker Botts LLP in Houston, Texas from 1969 to 2001. He also served as a director of Mesa Petroleum Co. and Pioneer Natural Resources Company from 1969 to 2001.

Our directors serve terms of one year. As a result, stockholders will elect our board of directors each year. Our executive officers are elected by, and serve at the discretion of, our board of directors. There are no family relationships between our directors and executive officers.

Other officers of our company

Charles R. Evans joined us in February 1998, became one of our Vice Presidents in March 1998 and was our Chief Operating Officer from December 2000 until October 2005. He currently serves as our Vice President of Marketing and Outside Operations. After working for Sun Oil Co., he joined TXO Production Corp. in 1979 and was appointed Vice President of Engineering and Evaluation in 1989. In 1990, he was named Vice President of Engineering and Project Development for Delhi Gas Pipeline Corporation, a natural gas gathering, processing and marketing company. Mr. Evans served as Director-Environmental Affairs and Safety for Delhi until December 1997.

Richard L. Hodges became one of our Vice Presidents in October 2000. He began his career with Texaco, Inc. and has served in various land management capacities with several independent oil and gas

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companies during the past 27 years. He served as Vice President of Land for Central Resources, Inc. until we acquired the Central properties in September 2000.

John D. Jacobi became one of our Vice Presidents in February 1999. In 1991, he co-founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas producer, and served as its President until January 1997. He served as the Vice President and Treasurer of Jacobi-Johnson from January 1997 until May 8, 1998, when the company was sold to us.

Daniel A. Johnson became one of our Vice Presidents in February 1999. In 1991, he co-founded Jacobi-Johnson Energy, Inc., an independent oil and natural gas producer. He served as its President from January 1997 until the company was sold to us on May 8, 1998.

Mark E. Wilson became our Controller and one of our Vice Presidents in August 2005. He began his career in 1980 with Diamond Shamrock Corporation. Since that time, he has served in Controller roles with Maxus Energy, Snyder Oil Company and Repsol-YPF International. From September 2000 to August 2005, Mr. Wilson served as Chief Financial Officer of Epoch Holdings Corporation and its predecessor, an investment management and advisory firm.

Board committees

Our board of directors has an audit committee, a compensation committee, and a nominating and corporate governance committee.

Audit committee

The audit committee of our board of directors recommends the appointment of our independent auditors, reviews our internal accounting procedures and financial statements and consults with and reviews the services provided by our independent auditors, including the results and scope of their audit. The audit committee is currently comprised of Messrs. Benjamin (chair), Ellis and Niehaus, each of whom are independent, within the meaning of applicable SEC and New York Stock Exchange, or NYSE, rules. Mr. Benjamin has been designated as an audit committee financial expert, as currently defined under the SEC rules implementing the Sarbanes-Oxley Act of 2002. We believe that the composition and functioning of our audit committee complies with all applicable requirements of the Sarbanes-Oxley Act of 2002, as well as NYSE and SEC rules and regulations.

Compensation committee

The compensation committee of our board of directors reviews and recommends to our board of directors the compensation and benefits for all of our executive officers, administers our stock plans, and establishes and reviews general policies relating to compensation and benefits for our employees. The compensation committee is currently comprised of Messrs. Stillwell (chair), Benjamin, Ellis and Niehaus, each of whom are independent, within the meaning of applicable NYSE rules. We believe that the composition and functioning of our compensation committee complies with all applicable requirements of the Sarbanes-Oxley Act of 2002, as well as NYSE and SEC rules and regulations.

Nominating and corporate governance committee

The nominating and corporate governance committee of our board of directors is responsible for:

•: reviewing the appropriate size, function and needs of the board of directors;
•: developing the board's policy regarding tenure and retirement of directors;
•: establishing criteria for evaluating and selecting new members of the board, subject to board approval thereof;

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•: identifying and recommending to the board for approval individuals qualified to become members of the board of directors, consistent with criteria established by the committee and by the board;
•: overseeing the evaluation of management and the board; and
•: monitoring and making recommendations to the board on matters relating to corporate governance.

The nominating and corporate governance committee currently consists of Messrs. Ellis (chair), Benjamin, Stillwell and Niehaus, each of whom is independent within the meaning of applicable NYSE rules. We believe that the composition and functioning of our nominating and governance committee complies with all applicable requirements of the Sarbanes-Oxley Act of 2002, as well as NYSE and SEC rules and regulations.

Lead director

The independent members of our board of directors have selected Mr. Stillwell to act as a lead director. The lead director will chair the executive sessions of the non-employee and independent directors, consult with the chairman of the board concerning the agenda for board meetings and perform such other duties as the independent directors might designate.

Codes of ethics

We have adopted Corporate Governance Guidelines, a Code of Business Conduct and Ethics, and a Code of Ethics for all executive officers. These documents are available on our website at www.excoresources.com.

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ITEM 11. EXECUTIVE COMPENSATION

The following table provides compensation information for the fiscal years 2003, 2004 and 2005 for our Chief Executive Officer, Douglas H. Miller, the three other most highly compensated executive officers, and the two most highly compensated non-executive officers serving as of December 31, 2005 other than Mr. Douglas H. Miller: Stephen F. Smith, T. W. Eubank, J. Douglas Ramsey, Harold L. Hickey and Charles R. Evans.

Summary compensation table

		Annual compensation			Long term compensation
					Awards		Payouts
Name and principal position	Fiscal year	Salary	Bonus(1)	Other annual compensation	Restricted stock awards	Securities underlying options/SARs(2)	LTIP payouts	All other compensation(3)
		($)	($)	($)	($)	(# of shares)	($)	($)
Douglas H. Miller Chairman and Chief Executive Officer	2005 2004 2003	475,000 475,000 431,250	2,349,945 914,980 291,245	— — —	— — —	1,705,000 2,657,407 —	— — —	44,683,614 16,000 14,257,044
Stephen F. Smith Vice Chariman, President and Secretary	2005 2004 2003	200,000 125,000 —	40,000 25,000 —	— — —	— — —	383,300 100,000 —	— — —	2,325,634 — —
T. W. Eubank(4) Consultant—Special Projects	2005 2004 2003	262,500 300,000 275,000	327,500 160,000 80,000	— — —	— — —	50,000 324,074 —	— — —	5,465,025 16,000 4,006,445
J. Douglas Ramsey, Ph.D. Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer	2005 2004 2003	175,000 175,000 168,750	145,000 75,000 43,750	— — —	— — —	166,700 150,000 —	— — —	2,237,566 13,000 2,519,270
Harold L. Hickey Vice President and Chief Operating Officer	2005 2004 2003	180,000 176,500 117,500	91,000 60,273 28,500	— — —	— — —	166,700 150,000 —	— — —	1,284,969 5,200 72,985
Charles R. Evans(4) Vice President-Marketing and Outside Operations	2005 2004 2003	231,426 250,000 225,000	265,478 130,000 65,000	— — —	— — —	66,700 259,259 —	— — —	4,375,618 16,000 1,037,080

(1): Includes amounts paid in 2003, 2004 and 2005 under the EXCO Holdings employee bonus retention plan. We paid retention bonuses in 2003, 2004 and 2005 to each of the named executive officers as follows: Douglas H. Miller—$204,995, $819,980 and $2,254,945; Stephen F. Smith—$0, $0 and $0; T.W. Eubank—$25,000, $100,000 and $275,000; J. Douglas Ramsey—$10,000, $40,000 and $110,000; Harold L. Hickey—$5,000, $20,000 and $55,000; and Charles R. Evans—$20,000, $80,000 and $220,000. This plan was terminated in October 2005, and all amounts remaining due were paid in conjunction with the Equity Buyout. See "—Employee Bonus Retention Plan" for a description of this plan.
(2): Represents stock options granted under the EXCO Holdings 2004 Long-Term Incentive Plan. EXCO Holdings granted options covering a total of 8,801,354 shares to employees, including executive officers, during 2004. These stock options were cashed-out and the plan was terminated in October 2005 in conjunction with the Equity Buyout. See "—Employee Bonus Retention Plan" for a description of this plan. In October 2005, stock options were granted under the EXCO Holdings II, Inc. 2005 Long-Term Incentive Plan. EXCO Holdings, successor by merger to EXCO Holdings II in conjunction with the Equity Buyout, granted options covering a total of 4,992,650 shares to employees and directors, including executive officers, during 2005. In February 2006, the 2005 Long-Term Incentive Plan was assumed by us in conjunction with our IPO, the name of the plan was changed to the EXCO Resources 2005 Long-Term Incentive Plan to reflect the merger of EXCO Holdings into us, and the stock option awards previously granted under the plan were converted into awards in our common stock.
(3): Includes (i) for 2003, in conjunction with the going private transaction, the pre-tax cash amounts received upon the sale of common stock or for each non-qualified stock option held in an amount equal to the amount by which $18.00 exceeded the

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exercise price of the option, (ii) for 2005, in conjunction with the Equity Buyout, the pre-tax cash amounts received upon the sale of common stock or for each non-qualified stock option held in an amount equal to $2.1971277, and (iii) for all years shown, our matching contributions under our 401(k) plan. In 2003, all incentive stock options the holder owned where the exercise price of the option was less than $18.00 were exercised. The common stock received upon exercise was then sold for $18.00 per share upon completion of the going private transaction and/or exchanged for Class A common stock of EXCO Holdings. In 2005, all non-qualified stock options were cashed-out upon the completion of the Equity Buyout. There were no incentive stock options outstanding.

(4): Effective October 5, 2005, Messrs. Eubank and R. E. Miller resigned as officers and directors of ours, and Mr. Evans resigned as our Chief Operating Officer. Mr. Eubank is continuing his employment with us in a non-officer capacity as Consultant—Special Projects, and Mr. Evans is continuing his employment with us in an officer capacity as Vice President—Marketing and Outside Operations.

The compensation described in this table does not include medical, group life insurance or other benefits that are available generally to all of EXCO's salaried employees. It also does not include certain perquisites and other personal benefits, securities or property received by these executive officers that are not material in amount.

The Board's compensation committee approved 2006 salaries for our executive officers as follows: Douglas H. Miller—$600,000; Stephen F. Smith—$400,000; J. Douglas Ramsey—$300,000; and Harold L. Hickey—$300,000.

Option grants in fiscal 2005

EXCO Holdings did not grant any stock options during 2005 other than the stock options discussed in the table above under its 2005 Long-Term Incentive Plan.

Option exercises in fiscal year 2005 and value at fiscal year end 2005

Prior to the IPO and the merger of EXCO Holdings with and into EXCO Resources on February 14, 2006, equity securities of EXCO Holdings were used to incentivize our management and our employees. The following table shows the number of shares of EXCO Holdings common stock acquired upon exercise of stock options, or, if no shares were received, the number of securities, if any, with respect to which stock options were exercised and the aggregate dollar value realized, if any, upon such exercise during fiscal 2005. This table also shows the number of shares of EXCO Resources common stock covered by both exercisable and non-exercisable stock options held by Messrs. Miller, Smith, Eubank, Ramsey, Hickey and Evans as of December 31, 2005.

			Number of securities underlying unexercised options at fiscal year-end(2)		Value of unexercised in-the-money options at fiscal year-end(3)
	Shares acquired on exercise
		Value realized(1)
		Value realized(1)	(#)		($)
Name	(#)	($)	(#)		($)
Name			Exercisable	Unexercisable	Exercisable	Unexercisable
Douglas H. Miller	—	5,838,663	426,250	1,278,750	—	—
Stephen F. Smith	—	430,637	95,825	287,475	—	—
T. W. Eubank	—	712,032	12,500	37,500	—	—
J. Douglas Ramsey, Ph.D	—	329,569	41,675	125,025	—	—
Harold L. Hickey	—	329,569	41,675	125,025	—	—
Charles R. Evans	—	569,625	16,675	50,025	—	—

(1): Represents the pre-tax amount realized from stock options granted under the EXCO Holdings 2004 Long-Term Incentive Plan which were cashed-out in conjunction with the Equity Buyout.
(2): Represents stock options granted under the EXCO Holdings 2005 Long-Term Incentive Plan (now known as the EXCO Resources 2005 Long-Term Incentive Plan, as a result of the IPO).

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(3): Since EXCO Holdings was a privately held company and there was not an established market for its equity securities, the value of unexercised in-the-money stock options at fiscal year end was not readily determinable.

Compensation of directors

Prior to the Equity Buyout, our directors did not receive any compensation for acting as a director, but were reimbursed for reasonable out-of-pocket expenses incurred in connection with their attendance at meetings of the board of directors and committee meetings. Following the Equity Buyout, our non-employee directors are paid a retainer of $25,000 per year. The chair of each committee is paid an additional $10,000 per year, other than the chair of the audit committee who is paid an additional $50,000 per year. Each other committee member is paid an additional $5,000 per year. We pay no additional remuneration to our employees serving as directors.

All directors, including our employee directors, are reimbursed for reasonable out-of-pocket expenses incurred in connection with their attendance at meetings of the board of directors and committee meetings and, on October 5, 2005, were given a one-time grant of an option to purchase 50,000 shares of our common stock with an exercise price of $7.50 per share, the price at which shares of common stock of Holdings II were issued in connection with the Equity Buyout.

2004 Long-Term Incentive Plan

In June 2004, EXCO Holdings adopted the 2004 Long-Term Incentive Plan. In 2004, we granted options covering 8,801,354 shares of Class A common stock to employees, including executive officers, under the terms of the option plan. No stock options were exercised during 2004 or 2005. In connection with the Equity Buyout, all of the then outstanding options granted under the EXCO Holdings 2004 Long-Term Incentive Plan were terminated for cash in an amount per share issuable upon exercise of these options, without regard to any vesting restrictions, equal to $5.1971277, less the applicable exercise price and withholding taxes.

2005 Long-Term Incentive Plan

Our 2005 Long-Term Incentive Plan was adopted by Holdings II Board of Directors and approved by Holdings II stockholders in September 2005. A total of 10,000,000 shares of our common stock have been authorized for issuance under this plan. The stated purpose of this plan is to provide financial incentives to selected employees and to promote our long-term growth and financial success by:

•: attracting and retaining employees of outstanding ability;
•: strengthening our capability to develop, maintain and direct a competent management team;
•: providing an effective means for selected employees to acquire an ownership interest in us;
•: motivating key employees to achieve long-range performance goals and objectives; and
•: providing incentive compensation competitive with other similar companies.

Our board of directors administers this plan and the awards granted under this plan. Awards under this plan can consist of incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights and other awards.

Pursuant to the terms of the stock option agreements that we entered into with our option holders, the stock options granted:

•: are vested as to 25% of the shares subject to the option on the date of grant and will vest an additional 25% on each of the next three anniversaries of the date of grant;

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•: expire on the tenth anniversary of the date of grant, or sooner under some circumstances; and
•: become fully vested and exercisable, subject to their early termination as provided in the option agreements, immediately prior to a change of control of us.

As of December 31, 2005, there were 4,973,075 outstanding incentive and nonqualified stock options to purchase shares of our common stock pursuant to this plan exercisable at $7.50 per share through October 5, 2015, of which 1,244,113 currently are exercisable. A total of 10.0 million shares of our common stock have been registered for issuance pursuant to our Registration Statement on Form S-8 filed on March 17, 2006.

On October 5, 2005, we granted options to purchase shares of our common stock to our named executive officers for 2005 as follows.

Name	Exercisable	Unexercisable	Exercise price
Douglas H. Miller	426,250	1,278,750	$	7.50
Stephen F. Smith	95,825	287,475	$	7.50
J. Douglas Ramsey, Ph.D	41,675	125,025	$	7.50
Harold L. Hickey	41,675	125,025	$	7.50

The following table provides information as of December 31, 2005 with respect to shares of our common stock that may be issued under our only existing equity compensation plan, which has been approved by our stockholders.

		Number of shares authorized for issuance under plan		Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted-average exercise price of outstanding options, warrants and rights			Number of securities remaining available for future issuance under equity compensation plans
2005 Long-Term Incentive Plan		10,000,000		4,973,075		$	7.50		5,026,925

Severance Plan

Our Amended and Restated Severance Plan, as amended, or the Severance Plan, provides for severance pay to eligible employees in the event they are terminated on the effective date of a change of control of us or within six months following the effective date of a change of control. The plan was amended to clarify that the Equity Buyout was not considered a change in control as defined in the Severance Plan. Eligible employees under this plan include our regular full-time employees, except those employees who own common stock of EXCO Holdings. The severance pay for each eligible employee is equal to one year's salary, before deductions and excluding bonuses and overtime, less any amounts due the eligible employee from the exercise of EXCO Holdings stock options. None of Messrs. Douglas H. Miller, Stephen F. Smith, J. Douglas Ramsey, or Harold L. Hickey are eligible to receive payments under this plan. This plan is in the process of being reviewed by our Compensation Committee.

Employee Bonus Retention Plan

The board of directors of EXCO Holdings and the board of directors of Addison adopted identical employee bonus retention plans effective upon the completion of the 2003 going private transaction in order to provide certain employees with an incentive to remain employed with us and Addison after the going private transaction. On February 10, 2005, the Addison employee bonus retention plan was terminated and all bonus retention amounts payable thereunder, aggregating approximately $1.0 million, were accelerated and paid in full.

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In conjunction with the closing of the Equity Buyout, on October 3, 2005, the EXCO Holdings employee bonus retention plan was terminated and all bonus retention amounts payable thereunder, aggregating approximately $2.8 million, were accelerated and paid in full. The participants in the plan agreed to customary confidentiality and nonsolicitation provisions. Messrs. Douglas H. Miller, J. Douglas Ramsey, Harold L. Hickey, J. David Choisser and Charles R. Evans, together with other of our continuing shareholders, agreed to customary non-compete provisions in connection with the EXCO Holdings employee bonus retention plan. The executive officers received the following payments in 2005, which includes three quarterly payments and the acceleration of the remaining bonus retention amounts payable thereunder: Douglas H. Miller—$2,254,945; Stephen F. Smith—$0; J. Douglas Ramsey—$110,000; and Harold L. Hickey—$55,000. None of Messrs. Douglas H. Miller, Stephen F. Smith, J. Douglas Ramsey or Harold L. Hickey is a party to an employment agreement.

Compensation committee interlocks and insider participation

Our compensation committee was formed in October 2005. Since its formation, it has been comprised of Messrs. Stillwell (chair), Ellis and Niehaus. Robert Stillwell, Jr., the son of Robert L. Stillwell, was employed by us from October 2002 until July 2005 as a financial analyst. In connection with the Equity Buyout in 2005, Robert Stillwell, Jr. received a payment of $71,187 for certain options granted to him as compensation for his employment with us and a payment of $41,064 under the Employee Stock Participation Plan. These payments were in addition to the prorated annualized salary of $45,000 that Robert Stillwell, Jr. received during the period of his employment in 2005.

None of our executive officers is a director or member of a compensation committee of any entity of which a member of our board of directors was or is an executive officer, except as described below. Two of our executive officers, Messrs. D. Miller and Smith, were directors of Carolina Soy Products, a private company with no compensation committee. One of our directors, Mr. Ellis, is the chief executive officer of Carolina Soy Products. Messrs. Miller and Smith have resigned from the board of Carolina Soy Products effective November 2, 2005, so no compensation committee interlock currently exists. Furthermore, Messrs. Miller and Smith were never involved in setting the compensation of Mr. Ellis during their tenure as directors of Carolina Soy Products and Mr. Ellis draws no compensation for his services as chief executive officer of Carolina Soy Products.

Limitations of liability and indemnification of directors and officers

As permitted by Texas law, our articles of incorporation provide that our directors will not be personally liable to us or our shareholders for or with respect to any acts or omissions in the performance of such person's duties as a director to the fullest extent permitted by applicable law. Our articles of incorporation and bylaws provide that we must indemnify our directors and officers to the fullest extent permitted by Texas law. Our bylaws further provide that we must pay or reimburse reasonable expenses incurred by one of our directors or officers who was, is or is threatened to be made a named defendant or respondent in a proceeding to the maximum extent permitted under Texas law. We believe that these provisions are necessary to attract and retain qualified persons as directors and officers.

We have entered into indemnification agreements with our directors and officers. These agreements, among other things, require us to indemnify the director or officer to the fullest extent permitted by Texas law, including indemnification for judgments, penalties, fines, settlements and reasonable expenses actually incurred by the director or officer in any action or proceeding, including any action by or in our right, arising out of the person's services as our director or officer or as the director or officer of any subsidiary of ours or any other company or enterprise to which the person provides services at our request. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers or persons controlling us pursuant to the foregoing

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provision, we have been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is therefore unenforceable.

The indemnification provisions contained in our articles of incorporation and bylaws are exclusive of any other right that a person may have or acquire under any statute, bylaw, resolution or shareholders or directors or otherwise. In addition, we maintain insurance on behalf of our directors and officers insuring them against any liability asserted against them in their capacities as directors or officers or arising out of their service in these capacities.

We are not aware of any pending or threatened litigation or proceeding involving any of our directors, officers, employees or agencies in which indemnification would be required or permitted. We believe that the provisions of our articles of incorporation and bylaws and our indemnification agreements are necessary to attract and retain qualified persons to serve as directors and officers of our company.

Section 16(a) beneficial ownership reporting compliance

Effective February 8, 2006, Section 16(a) of the Exchange Act and the rules thereunder require our executive officers and directors and persons who own more than 10% of our common stock to file reports of beneficial ownership and changes in beneficial ownership with the Securities and Exchange Commission.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLER MATTERS

Principal shareholders

The following table sets forth as of March 15, 2006 the number and percentage of shares of our common stock beneficially owned by:

•: each person known by us to beneficially own more than 5% of the outstanding shares of our common stock;
•: each of our directors;
•: each named executive officer; and
•: all of our directors and executive officers as a group.

Beneficial ownership is determined in accordance with the rules of the SEC. In computing the number of shares beneficially owned by a person and the percentage ownership of that person, shares of common stock subject to options held by that person that are currently exercisable or exercisable within 60 days of March 15, 2006 are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. Percentage of beneficial ownership is based upon 104,004,089 shares of common stock outstanding as of March 15, 2006. To our knowledge, except as set forth in the footnotes to this table and subject to applicable community property laws, each person named in the table has sole voting and investment power with respect to the shares set forth

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opposite such person's name. Unless otherwise indicated in a footnote, the address for each individual listed below is c/o EXCO Resources, Inc., 12377 Merit Drive, Suite 1700, Dallas, Texas 75251.

		Beneficial ownership
Beneficial owner		Shares(1)	Options exercisable within 60 days	Percentage of shares outstanding
*Holders of more than 5%*
	BP EXCO Holdings II LP 8117 Preston Road Suite 260W Dallas, TX 75225	13,193,722	—	12.7	%
	Ares Corporate Opportunities Fund, L.P 1999 Avenue of the Stars Suite 1900 Los Angeles, CA 90067	6,533,333	—	6.3	%
	Lucas Energy Total Return Partners, L.P.(2) Parkway 109 Center 328 Newman Springs Road Red Bank, NJ 07701	3,333,334	—	3.2	%
	OCM Principal Opportunities Fund III, L.P.(3) c/o Oaktree Capital Management, LLC 333 South Grand Avenue 28th Floor Los Angeles, CA 90071	3,200,000	—	3.1	%

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			Beneficial ownership
Beneficial owner			Shares(1)	Options exercisable within 60 days	Percentage of shares outstanding
Named executive officers
	Douglas H. Miller(4)		4,979,223	426,250	4.8	%
	Stephen F. Smith(5)		682,488	95,825	(9	)
	J. Douglas Ramsey, Ph.D.(6)		713,197	41,675	(9	)
	Harold L. Hickey		296,140	41,675	(9	)
Directors
	Jeffrey D. Benjamin		474,503	12,500	(9	)
	Earl E. Ellis		474,503	12,500	(9	)
	Robert H. Niehaus(7)		2,356,982	12,500	2.3	%
	Boone Pickens(8)		13,339,622	12,500	12.8	%
	Robert L. Stillwell		39,200	12,500	(9	)

	All executive officers and directors as a group
		(9 persons)	23,355,858	667,925	22.3	%

(1): Includes the options exercisable within 60 days shown in the option column.
(2): Includes 1,333,334 shares held by Lucas Energy Ventures Fund I, L.P. and 1,600,000 shares held by Lucas Energy Total Return, Master Fund, L.P., affiliates of Lucas Energy Total Return Partners, L.P.
(3): Includes 57,600 shares held by OCM Principal Opportunities Fund IIIA, L.P., an affiliate of OCM Principal Opportunities Fund III, L.P.
(4): Includes 720,265 shares held in six trusts for the benefit of immediate family members.
(5): Includes 50,000 shares held in two trusts for the benefit of immediate family members.
(6): Includes 614,309 shares held by a limited partnership in which Dr. Ramsey holds a 98.0% limited partnership interest.
(7): Beneficial ownership consists of 1,450,018 shares of common stock owned by Greenhill Capital Partners, L.P., 207,189 shares of common stock owned by Greenhill Capital Partners (Cayman), L.P., 228,860 shares of common stock owned by Greenhill Capital Partners (Executives), L.P., and 458,415 shares of common stock owned by Greenhill Capital, L.P. By virtue of their ownership and positions as Senior Members of GCP 2000, LLC and as Managing Directors of Greenhill Capital Partners, LLC, which control the general partners of Greenhill Capital Partners, L.P. and its affiliated investment funds, Scott L. Bok, Robert F. Greenhill and Robert H. Niehaus may be deemed to beneficially own these shares. In addition, GCP Managing Partner, L.P. and GCP, L.P., the general partners of Greenhill Capital Partners, L.P. and its affiliated investment funds, as well as Greenhill Capital Partners, LLC and GCP 2000, LLC, which control the general partners, and Greenhill & Co., Inc., the sole member of Greenhill Capital Partners, LLC, may be deemed to beneficially own these shares. Mr. Niehaus disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Beneficial ownership also includes options to purchase 12,500 shares pursuant to the 2005 Long-Term Incentive Plan.
(8): Includes 13,193,722 shares held by BP EXCO Holdings II LP and 133,400 shares held by his wife, Madeleine Pickens. Mr. Pickens is the controlling member of BP EXCO Holdings GP, LLC, the general partner of BP EXCO Holdings II LP.
(9): Less than 1%.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

TXOK acquisition

On September 16, 2005, Mr. Boone Pickens, one of our directors, provided $20.0 million in debt financing to TXOK, an affiliate of EXCO Holdings, to fund the $19.4 million in deposits paid in connection with the ONEOK Energy acquisition. This loan was amended on September 21, 2005 to reduce the principal amount of the loan to $15.0 million. The loan matured and was repaid, together with approximately $100,000 of interest under this loan, on October 7, 2005. On September 21, 2005, Mr. Pickens also entered into a contract with TXOK to render financial advisory services to it with respect to the ONEOK Energy acquisition pursuant to which he was paid $3.6 million on October 7, 2005. No other sums are due Mr. Pickens under this agreement.

On September 27, 2005, BP EXCO Holdings LP acquired 150,000 shares of TXOK preferred stock for $150.0 million to fund the ONEOK Energy acquisition in part. Mr. Pickens is the controlling member of BP EXCO Holdings GP, LLC, the general partner of BP EXCO Holdings LP. In connection with the sale of the TXOK preferred stock, each of TXOK and EXCO Holdings agreed, if the proceeds of an initial public offering of its or its subsidiary's capital stock are not sufficient to redeem all of the TXOK preferred stock, to use its reasonable best efforts to redeem all of the TXOK preferred stock with available cash and borrowings under its credit facilities. On February 14, 2006, TXOK redeemed the TXOK preferred stock for $158,750,000 in cash. In addition, EXCO Resources issued 388,889 shares of its common stock, or redemption shares, to an entity controlled by one of our current directors, Mr. Boone Pickens, as the redemption premium under the terms of the Amended and Restated Certificate of Incorporation of TXOK. The redemption shares were issued at a price of $12.00 per share in accordance with the redemption terms. The terms of the TXOK preferred stock were negotiated on terms believed to be fair to EXCO Holdings in order to arrange interim equity financing pending completion of the IPO. The redemption shares were issued pursuant to an exemption from registration under Section 4(2) of the Securities Act and Regulation D promulgated thereunder. As a result of the redemption of the TXOK preferred stock, TXOK became a wholly-owned subsidiary of EXCO Resources.

In connection with the formation of TXOK on September 15, 2005, TXOK issued 1,000 shares of its common stock to Holdings II in exchange for $1,000. On September 27, 2005, TXOK reclassified its capital structure in connection with the issuance of the TXOK preferred stock. In this recapitalization, Holdings II's 1,000 shares of TXOK common stock were converted into one share of Class B common stock of TXOK. On October 7, 2005, EXCO Holdings purchased 19,999 shares of Class B common stock for a purchase price of $19,999,000. TXOK used a portion of these proceeds to repay the $15.0 million of debt financing provided by Mr. Pickens as described above. Upon the merger of Holdings II with and into EXCO Holdings, EXCO Holdings became the owner of the 20,000 shares of Class B common stock.

In connection with the issuance of the TXOK preferred stock, EXCO Holdings gave BP EXCO Holdings LP a right of first refusal, a co-sale right and, if the TXOK preferred stock is converted into Class A common stock of TXOK, a drag along right on the Class B common stock of TXOK held by EXCO Holdings.

Effective October 15, 2005, EXCO Resources entered into an intercompany agreement with TXOK to manage TXOK's business affairs. Prior to the IPO and the redemption of the TXOK preferred stock, Mr. Pickens controlled TXOK through BP EXCO Holdings LP's ownership of the TXOK preferred stock. The agreement provides that we will provide TXOK with general management, treasury, finance, legal, audit, tax, information technology, and payroll and benefit administration services. TXOK has agreed to reimburse us on a monthly basis for the total amount of compensation, taxes and benefits we provide to employees providing services to TXOK. TXOK has also agreed to pay

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us $25,000 per month for the additional services we provide, as well as reimbursement of all costs directly related to the operations of TXOK.

Equity Buyout

On October 3, 2005, Holdings II acquired all the capital stock of EXCO Holdings and subsequently merged into EXCO Holdings. Upon its formation, Holdings II issued 3,333,330 shares of common stock to its founders for $0.01 per share. This group of founders included Mr. Douglas H. Miller, who purchased 1,655,000 shares, Mr. T. W. Eubank, who purchased 50,000 shares, Mr. Stephen F. Smith, who purchased 333,330 shares, Dr. J. Douglas Ramsey, who purchased 166,670 shares (these shares were issued to a limited partnership in which Dr. Ramsey owns a 98.0% limited partnership interest), Mr. Harold L. Hickey, who purchased 166,670 shares and Mr. Charles R. Evans, who purchased 66,660 shares, as well as a number of our employees. Each of these persons and many of our employees also exchanged shares of EXCO Holdings common stock for Holdings II common stock or purchased additional shares of Holdings II common stock for cash pursuant to the terms of the stock purchase agreements described below.

A summary of the main agreements entered into in connection with the Equity Buyout is set forth below.

The EXCO Holdings stockholders' stock purchase agreement

Overview. All EXCO Holdings stockholders, whether they received cash for their EXCO Holdings shares or common stock of Holdings II, were required to enter into a Stock Purchase Agreement with Holdings II, referred to in this annual report as the Rollover Investors SPA.

Consideration. The Rollover Investors SPA provided, among other things, that Holdings II would purchase for cash all of the outstanding shares of EXCO Holdings Class A common stock and Class B common stock for $5.1971277 and $3.6971277 per share, respectively, should the holder of such shares elect to receive cash for his, her or its shares. Should a stockholder elect to exchange all or a portion of such holder's EXCO Holdings stock for common stock of Holdings II, this holder would receive one share of Holdings II common stock for each $7.50 in EXCO Holdings capital stock exchanged.

Representations and warranties, covenants and conditions. The Rollover Investors SPA contained certain representations and warranties, conditions and covenants of both Holdings II and the selling stockholders. Holdings II made representations with respect to the following subjects: corporate existence, good standing and qualification to conduct business; requisite power and authorization to enter into and carry out its obligations under the Rollover Investors SPA; absence of any conflict or violation of organizational documents, third party agreements or law or regulation as a result of entering into or carrying out the obligations of the Rollover Investors SPA and the related documents and transactions; investment intent; capitalization; and valid issuance of the common stock of Holdings II.

Holdings II further covenanted with respect to the following subjects: execution of certain related documents and taking of reasonable actions required in connection with the Rollover Investors SPA; satisfaction of conditions; securing of required consents and approvals; required filings and actions under the Hart-Scott-Rodino Act of 1976, or HSR; cooperation with EXCO Holdings in fulfillment of EXCO Holdings' notice obligations under the related transaction documents, termination of the EXCO Holdings Employee Bonus Retention Plan, termination of the EXCO Holdings Employee Stock Participation Plan, and the collection by EXCO Holdings of certain obligations owed to it.

The selling stockholders made representations with respect to the following subjects: requisite power and authorization to enter into and carry out the obligations of the Rollover Investors SPA and the related documents and transactions; enforceability of the Rollover Investors SPA and the

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obligations entered into in connection with the Rollover Investors SPA; absence of any conflict or violation of organizational documents, third party agreements or law or regulation as a result of entering into or carrying out the obligations of the Rollover Investors SPA and the related documents and transactions; beneficial ownership, free and clear, of the EXCO Holdings stock to be transferred; absence of filing requirements or required consents; corporate existence and good standing; and absence of broker, finder, or agent fees in connection with the transactions contemplated by the Rollover Investors SPA.

The selling stockholders further covenanted with respect to the following subjects: execution of certain related documents and taking of reasonable actions required in connection with the Rollover Investors SPA; satisfaction of conditions; securing of required consents and approvals; HSR filings and actions; notification of breach or likely breach of representations and warranties; competing transactions; and confidentiality.

Release. The Rollover Investors SPA also provided that EXCO Holdings stockholders would release Holdings II, EXCO Holdings, EXCO Resources and their respective successors, officers, directors, employees and stockholders (and each of their respective heirs, executors and administrators acting in such capacities) of and from any and all manner of action or actions, or cause or causes of action of any nature whatsoever which they then had or may hereafter have against any of them, subject to certain exceptions. Holdings II, EXCO Holdings and EXCO Resources provided a similar release to the EXCO Holdings stockholders, subject to certain exceptions.

Indemnity. The Rollover Investors SPA provided for certain indemnities on the part of Holdings II and the EXCO Holdings stockholders. Each of the stockholders agreed to indemnify Holdings II and its respective successors and assigns and officers, directors, employees, representatives and others from and against losses with respect to any breach of a representation or warranty of such stockholder contained in the Rollover Investors SPA or the breach of any covenant or other agreement of such stockholder. Likewise, Holdings II agreed to indemnify each of the selling stockholders from and against losses with respect to any breach of a representation or warranty by Holdings II or of any of Holdings II's covenants or other agreements. EXCO Acquisition LLC, EXCO Holdings' controlling stockholder prior to the Equity Buyout, was appointed as the representative of, and attorney-in-fact for, all other selling stockholders under the indemnity provision with full power and authority to act on behalf of the selling stockholders with respect to indemnification claims.

The equity investors stock purchase agreement

Overview. All equity investors making a cash investment in Holdings II were required to enter into a Stock Purchase Agreement with Holdings II, referred to in the annual report as the Equity Investors SPA.

Consideration. The equity investors purchased 24,415,440 shares of common stock of Holdings II for a cash payment of $7.50 per share.

Representations and warranties, covenants and conditions. The Equity Investors SPA contains certain representations and warranties, conditions and covenants of both Holdings II and the equity investors. Holdings II made representations with respect to the following subjects: corporate existence, good standing and qualification to conduct business; requisite power and authorization to enter into and carry out its obligations under the Equity Investors SPA; capitalization; SEC filings and financial statements of EXCO Resources; absence of violations of law; absence of any material adverse change, prohibited distribution or dividend, or material change in accounting; possession of permits; preparation of reserve reports; completeness of information; absence of certain related party transactions; environmental matters, labor and employment matters; absence of litigation; property matters; hedging; absence of preemptive rights and rights of first refusal and exemption from

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registration and prospectus delivery requirements under the Securities Act; and the absence of material misstatements or omissions in the confidential disclosure statement accompanying the Equity Buyout.

Holdings II further covenanted with respect to the following subjects: access to information; supplementing of information that has been provided; execution of certain related documents and taking of reasonable actions required in connection with the Equity Investors SPA; satisfaction of conditions; required filings and actions under HSR; securing of required consents and approvals; use of proceeds to fund the Equity Buyout; and filing of a certificate of merger with respect to the merger of Holdings II into EXCO Holdings.

The equity investors made representations with respect to the following subjects: investment intent and other Securities Act matters; recognition that the common stock of Holdings II had not been registered under the Securities Act; accredited investor status; requisite power and authorization to enter into and carry out the obligations of the Equity Investors SPA and the related documents and transactions; absence of any conflict or violation of organizational documents, third party agreements or law or regulation as a result of entering into or carrying out the obligations of the Equity Investors SPA and the related documents and transactions; enforceability of the Equity Investors SPA and the obligations entered into in connection with the Equity Investors SPA; and absence of broker or finder fees in connection with the transactions contemplated by the Equity Investors SPA.

The equity investors further covenanted with respect to the following subjects: execution of certain related documents and taking of reasonable actions required in connection with the Equity Investors SPA; satisfaction of conditions; and securing of required consents and approvals.

Indemnification. The Equity Investors SPA also provided that Holdings II and the equity investors would indemnify each other (and their respective successors, officers, directors, employees, attorneys, consultants and agents) for losses arising from any material breach or inaccuracy of a representation or warranty, covenant, agreement or other obligations contained in the Equity Investors SPA or in any related document.

The stockholders' agreement

Overview. Each stockholder of Holdings II after the Equity Buyout was required to enter into a Stockholders' Agreement with Holdings II and the other stockholders of Holdings II. As a result of the merger of Holdings II with and into EXCO Holdings, the Stockholders' Agreement was assumed by EXCO Holdings. The Stockholders' Agreement generally prohibits stockholders of EXCO Holdings from selling or otherwise conveying their shares of EXCO Holdings common stock other than as permitted by the Stockholders' Agreement. The Stockholders' Agreement also provides, among other things, for the rights described below.

Right of first refusal. A right of first refusal exists with respect to any proposed transfer of EXCO Holdings common stock by management stockholders to a third party. Management stockholders are generally those stockholders of EXCO Holdings who are employees of EXCO Holdings or our subsidiaries. Generally, if a management stockholder intends to sell his or her shares and has a buyer for the shares, the selling management stockholder must notify the other non-selling management stockholders of the offer and the management stockholders then have the right to buy the shares, pro rata, at the offered price. If the non-selling management stockholders do not indicate their intention to acquire all of the offered shares, then EXCO Holdings has the right to purchase the remaining shares not being purchased by the non-selling management stockholders at the offered price. Finally, if neither the non-selling management stockholders nor EXCO Holdings purchase all of the offered shares, then the other stockholders have the right to purchase the offered shares. If there remain unpurchased shares, then the selling management stockholder may sell his or her shares to the third party buyer which made the initial offer.

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Right of first offer. At any time a non-management stockholder of EXCO Holdings proposes to sell or transfer any shares of EXCO Holdings common stock, the other stockholders have a right of first offer, allowing them to make an offer to purchase the shares proposed to be sold. The right of first offer provides that a non-management stockholder who desires to sell shares of EXCO Holdings common stock must first permit the other non-selling stockholders of EXCO Holdings the right to make the first offer to purchase the shares of common stock proposed to be sold. The other non-selling EXCO Holdings stockholders (which would include management stockholders) have a designated period of time to make an offer to the selling non-management stockholder to purchase all of the shares proposed to be sold. If the selling non-management stockholder rejects the offer, such selling stockholder has sixty (60) days in which to market the shares to a third party at a price that must be greater than the price offered by the non-selling EXCO Holdings stockholders.

Right of co-sale. Each EXCO Holdings stockholder has a right of co-sale that affords such stockholder the opportunity to sell a pro rata portion of its shares when another stockholder proposes to transfer shares to any third party or to EXCO Holdings. In effect, if non-selling stockholders or EXCO Holdings do not elect to purchase offered shares pursuant to the right of first refusal or right of first offer, the non-selling stockholders have the right to sell a pro rata portion of their shares with the selling stockholder.

Drag-along right. In the event that one or more stockholders holding at least 50% of the outstanding shares of common stock of EXCO Holdings proposes to sell or transfer all of the shares held by it to a third party, such stockholder may require the non-selling stockholders to sell or transfer all of their shares in the manner and on the same terms and conditions that apply to the selling stockholder or stockholders.

Preemptive rights. All stockholders are given preemptive rights. Subject to customary limitations, in the event EXCO Holdings proposes to issue, grant or sell additional common stock, each stockholder shall have the right to purchase its pro rata amount of additional shares of such common stock. Preemptive rights do not apply to shares issued pursuant to the IPO or in connection with a merger or other acquisition transaction with respect to EXCO Holdings.

Voting provisions. The Stockholders' Agreement provides that each party will vote all of its shares for the directors designated in the Stockholders' Agreement. In addition to its effect on the voting rights of the stockholders, the Stockholders' Agreement could have the effect of delaying or preventing a change in control.

Termination of the Stockholders' Agreement. The Stockholders Agreement terminated upon the consummation of the IPO.

The registration rights agreement

Overview. Each stockholder of Holdings II after the Equity Buyout was required to enter into a Registration Rights Agreement with Holdings II and the other stockholders of Holdings II. The Registration Rights Agreement was amended and restated pursuant to the terms and conditions of the First Amended and Restated Registration Rights Agreement, or the Registration Rights Agreement. As a result of the merger of Holdings II with and into EXCO Holdings and upon consummation of the merger of EXCO Holdings into us, the Registration Rights Agreement will be assumed by us. The Registration Rights Agreement entitles the EXCO Holdings stockholders to certain rights with respect to the registration of shares of our common stock for resale under the Securities Act.

Registrations. Pursuant to the Registration Rights Agreement, after the IPO, all holders of unregistered shares of our common stock who are subject to the Registration Rights Agreement can require us to register their shares in certain circumstances. In addition, at any time that we file a

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registration statement registering other shares, the holders of shares subject to the Registration Rights Agreement can require that we include their shares in such registration statement, subject to certain exceptions.

At any time on or after 180 days after the completion of the IPO, any holder of unregistered shares of our common stock who is party to the Registration Rights Agreement may request that we register up to one-third of the holder's registrable securities in a resale registration statement. At any time on or after 365 days after the completion of the IPO, any holder of registrable securities may again require us to register up to an additional one-third of the holder's registrable securities initially covered by the Registration Rights Agreement in the same manner as the initial resale registration was made. A similar demand right will be invocable by any holder with respect to its remaining registrable securities commencing 540 days after completion of the IPO. Upon any such request for registration, we would then be required to give notice of the requested registration to all other holders of registrable securities to allow such other holders to register up to one-third of their registrable securities on the same registration statement. We may request in writing that J.P. Morgan Securities Inc. (or the lead underwriter and sole stabilization agent of the IPO, if other than J.P. Morgan Securities Inc.) waive the registration waiting periods and registration volume limitations on resale registrations described in this paragraph. Upon or without such a request, J.P. Morgan Securities Inc. (or such other underwriter), in its sole discretion and based upon its evaluation of market conditions, the historical trading activity and liquidity of our common shares and other considerations it deems relevant, may waive continued application of the registration waiting periods and registration volume limitations described in this paragraph.

If EXCO Holdings (or, after the merger of EXCO Holdings into us, we) at any time or from time to time proposes to register any of its securities under the Securities Act, other than in an initial public offering or registrations on Form S-4 or Form S-8, then all holders, or all former holders, of EXCO Holdings registrable securities, if such shares have not been previously registered, will be entitled to piggyback registration rights, allowing them to have their shares included in the registration. These piggyback registrations are subject to delay or termination of the registration in certain circumstances.

Postponements and limitations. Under certain circumstances, we may postpone a registration if our board of directors determines in good faith that effecting such a registration or continuing the disposition of common stock would have a material adverse effect on us, or would not be in our best interests. Furthermore, the underwriters of the registration may, subject to certain limitations, limit the number of shares included in the registration.

Founders common stock. The Registration Rights Agreement provides, until the third anniversary of the Registration Rights Agreement, that the holders of our common stock representing common stock of Holdings II issued prior to the Equity Buyout, or the founders, may only sell their common stock pursuant to an effective registration statement covering the resale of such founder's shares and may not sell their shares pursuant to Rule 144 or any other exemption from registration or otherwise.

Amendments and waivers. The provisions of the Registration Rights Agreement may not be amended, terminated or waived without the written consent of us, of holders of a majority of the shares then held by the outside investors and holders of a majority of the shares then held by the management investors.

Holdback arrangements. Upon entering into the Registration Rights Agreement, each holder of registrable securities agrees that, at the request of the sole or lead managing underwriter in an underwritten offering, it will not make any short sale of, loan, grant any option for the purchase of or effect any public sale or distribution, including a sale pursuant to Rule 144 under the Securities Act, of any registrable securities during the five days prior to, and the time period (up to 90 days) requested by the underwriter following an underwritten offering. The holders of registrable securities will be subject

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to these restrictions for 180 days following the effective date of the registration statement filed with respect to the IPO.

Other

Robert Stillwell, Jr., the son of Robert L. Stillwell, one of our directors, was employed by us from October 2002 until July 2005 as a financial analyst. In connection with the Equity Buyout in 2005, Robert Stillwell, Jr. received a payment of $71,187 for certain options granted to him as compensation for his employment with us and a payment of $41,064 under the Employee Stock Participation Plan. These payments were in addition to the prorated annualized salary of $45,000 that Robert Stillwell, Jr. received during the period of his employment in 2005.

Corporate use of personal aircraft

During 2005, EXCO Resources reimbursed $0.5 million to DHM Aviation, LLC, a company owned by Mr. Douglas H. Miller, for the use of an aircraft owned by DHM Aviation on corporate business. We pay an hourly rate of $2,500 for the use of the aircraft plus expenses related to catering, crew meals and accommodations.

Intercompany promissory note

On October 7, 2005, EXCO Resources agreed to provide a revolving line of credit for the benefit of its parent, EXCO Holdings, in an aggregate principal amount not to exceed $10.0 million. This indebtedness was evidenced by an intercompany promissory note, which bears interest at 7.0% per annum and matures on October 7, 2007. In conjunction with the closing of our IPO on February 14, 2006, EXCO Holdings was merged with and into EXCO Resources. As a result, the intercompany promissory note was repaid in full and terminated.

We believe that the terms of the transactions described above, each taken as whole, were at least as favorable to us as could have been obtained through arm's length negotiations with unaffiliated third parties. Any transactions with our affiliates are subject to compliance with our conflicts of interest policy set forth in our Code of Business Conduct and Ethics. The policy defines a conflict of interest as any instance in which an individual's private interest interferes, or appears to interfere, with the interests of EXCO. Procedures are set out for reporting, assessing and handling a conflict of interest when it arises. In addition, any transaction that would influence an employee to act in a manner other than in the best interest of EXCO or that involves an undisclosed personal benefit is prohibited.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

PricewaterhouseCoopers LLP served as the Company's independent registered public accounting firm for the year ended December 31, 2005. Aggregate fees for professional services provided to the Company by PricewaterhouseCoopers LLP for the years ended December 31, 2004 and 2005 were as follows:

(in thousands)	2004		2005
Audit fees	$	274	$	419
Audit-related fees		110		1,276
Tax fees		—		—
All other fees		—		—

Total	$	384	$	1,695

Fees for audit services include fees associated with the annual audit and the reviews of EXCO's quarterly reports on Form 10-Q. Audit-related fees principally included accounting consultations and

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fees incurred related to our Form S-1 registration statements filed with the SEC in connection with our initial public offering that was completed on February 14, 2006. Tax fees, when incurred, include tax compliance and tax planning. Other fees include research materials.

AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES

The Audit Committee has adopted a policy that requires advance approval of all audit services and non-audit services performed by the independent registered public accounting firm or other public accounting firms. Audit services approved by the Audit Committee within the scope of the engagement of the independent registered public accounting firm are deemed to have been pre-approved. The policy further provides that pre-approval of non-audit services by the independent registered public accounting firm will not be required if:

•: the aggregate amount of all such non-audit services provided by the independent registered public accounting firm to EXCO does not constitute more than 5% of the total amount of revenues paid by EXCO to the independent auditor during that fiscal year;
•: such non-audit services were not recognized by EXCO at the time of the independent registered public accounting firm's engagement to be non-audit services; and
•: such non-audit services are promptly brought to the attention of the Audit Committee and approved by the Audit Committee prior to the completion of the audit.

The Audit Committee may delegate to one or more members of the Audit Committee the authority to grant pre-approval of non-audit services provided that such member or members reports any decision to the Committee at its next scheduled meeting.

The Audit Committee pre-approved all of the aggregate audit fees, and the audit-related fees set forth in the table.

190

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

1. Financial Statements

See Index to Financial Statements on page 91 to this annual report.

2. Financial Statement Schedules

All schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in our consolidated financial statements or related notes.

3. Exhibits

EXHIBIT NUMBER		Description Of Exhibit
3.1		Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 14, 2006 and incorporated by reference herein.
3.2		Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO's current report on Form 8-K filed on February 14, 2006 and incorporated by reference herein.
4.1		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.
4.2		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
4.3		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
4.4		Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
4.5		Form of 7¹/4% Global Note Due 2011.**
4.6		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*
4.7		Registration Rights Agreement by and among EXCO Resources, Inc., certain domestic subsidiaries of EXCO Resources, Inc., as guarantors, and Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc, dated April 1, 2004.**
4.8		Pledge Agreement by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, dated January 20, 2004.*

191

4.9		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
4.10		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
4.11		Specimen Stock Certificate for EXCO's common stock, filed as an Exhibit to EXCO's Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.
10.1		Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003, filed as an Exhibit to EXCO's Form 8-K filed March 12, 2003 and incorporated by reference herein.
10.2		Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein.*
10.3		First Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**
10.4		Second Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**
10.5		Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein.*
10.6		First Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**
10.7		Second Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**
10.8		Amended and Restated Agreement and Plan of Merger among NCE Acquisition, Inc., EXCO Resources, Inc., North Coast Energy, Inc. and Nuon Energy & Water Investments, Inc., dated as of December 4, 2003, filed as exhibit (d)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.
10.9		Escrow Agreement among Nuon Energy & Water Investments, Inc., EXCO Resources, Inc. and Citibank, N.A., dated as of December 9, 2003.*

192

10.10		Unconditional Guaranty Agreement by and between EXCO Resources, Inc. and n.v. NUON, dated as of December 9, 2003.*
10.11		Commitment Letter among Credit Suisse First Boston Bank One, NA, Banc One Capital Markets, Inc. and EXCO Resources, Inc., dated November 25, 2003, filed as exhibit (b)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.
10.12		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*
10.13		Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*
10.14		Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, Canada Branch, as agent.*
10.15		Second Restated Unlimited Guaranty dated as of January 27, 2004, by EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Taurus Acquisition, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*
10.16		Amended and Restated Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*
10.17		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, as Agent.*
10.18		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, as Agent.*
10.19		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Holdings Inc. in favor of Bank One, NA, as Agent.*
10.20		Amended and Restated Subsidiary Guaranty dated as of January 27, 2004, by Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*
10.21		Third Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.
10.22		Third Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.
10.23		EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. ***

193

10.24		First Amendment to the EXCO Holdings Inc. 2004 Long-term Incentive Plan, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.***
10.25		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.26		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.27		EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.***
10.28		EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.29		Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.30		Unlimited Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, Canada Branch, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.31		Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.32		Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO's Form 8-K filed January 21, 2005 and incorporated by reference herein.
10.33		First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
10.34		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
10.35		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
10.36		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.

194

10.37		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
10.38		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.39		Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.40		Form of 7¹/4% Global Note Due 2011.**
10.41		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*
10.42		EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.43		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.44		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.45		Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.46		Fourth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated September 30, 2005, as filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and incorporated by reference herein.
10.47		Letter Agreement, dated October 3, 2005, between EXCO Resources, Inc. and JPMorgan Chase Bank, N.A., as agent for certain lenders under the Credit Agreement by and among EXCO Holdings II, Inc. (EXCO Holdings Inc. as successor by merger) as Borrower and JPMorgan Chase Bank, N.A., as Administrative Agent for itself and the Lenders defined therein, dated October 3, 2005, as filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.48		Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., as filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.

195

10.49		First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.50		Fifth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA (successor by merger to Bank One, N.A. (Illinois), as Administrative Agent for itself and the Lenders defined therein, dated December 15, 2005, filed as an Exhibit to EXCO's Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.
10.51		Agreement and Plan of Merger between EXCO Holdings Inc. and EXCO Resources, Inc., dated February9, 2006, filed as an Exhibit to EXCO's Current Report on Form 8-K filed February 14, 2006 and incorporated by reference herein.
10.52		Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.53		Guarantee, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., ROJO Pipeline, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Pinestone Resources, L.L.C., as Guarantors, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined herein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.54		Credit Agreement for Senior Secured Revolving Credit Facility, dated as of September 27, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.55		First Amendment to Revolving Credit Agreement, dated as of December 15, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined herein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.56		Second Amendment to Revolving Credit Agreement, dated as of February 6, 2006, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.

196

10.57		Subsidiary Guaranty, dated February 14, 2006, among TXOK Acquisition, Inc., TXOK Energy Resources Company, TXOK Energy Holdings, L.L.C., TXOK Texas Energy Holdings, LLC and TXOK Texas Energy Resources, L.P., as Subsidiary Guarantors, in favor of JPMorgan Chase Bank, NA, as agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.58		Amended and Restated Credit Agreement, dated as of March 17, 2006, among EXCO Resource, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Manager, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on March 23, 2006 and incorporated by reference herein.
10.59		EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
10.60		Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
10.61		Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
10.62		Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
14.1		Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.2		Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
21.1		Subsidiaries of the registrant, filed herewith.
23.1		Consent of PricewaterhouseCoopers LLP, filed herewith.
23.2		Consent of Lee Keeling and Associates, Inc., filed herewith.
31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.

197

99.1

Audit Committee Charter, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.

*: Filed as an Exhibit to EXCO's Form S-4 filed March 25, 2004 and incorporated by reference herein.
**: Filed as an Exhibit to EXCO's Pre-effective Amendment No. 1 to the Form S-4 filed April 20, 2004 and incorporated by reference herein.
***: These exhibits are management contracts.

198

SIGNATURE PAGE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		EXCO RESOURCES, INC. (Registrant)
Date: March 31, 2006		By:	/s/ DOUGLAS H. MILLER Douglas H. Miller Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

Date: March 31, 2006		/s/ DOUGLAS H. MILLER Douglas H. Miller Director, Chairman and Chief Executive Officer
		/s/ STEPHEN F. SMITH Stephen F. Smith Director, Vice Chairman, President and Secretary
		/s/ J. DOUGLAS RAMSEY J. Douglas Ramsey Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer
		/s/ JEFFREY D. BENJAMIN Jeffrey D. Benjamin Director
		/s/ EARL E. ELLIS Earl E. Ellis Director
		/s/ ROBERT H. NIEHAUS Robert H. Niehaus Director
		/s/ BOONE PICKENS Boone Pickens Director
		/s/ ROBERT L. STILLWELL Robert L. Stillwell Director

199

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED
PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE
NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

Not applicable.

200

Index to Exhibits

EXHIBIT NUMBER		Description Of Exhibit
3.1		Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 14, 2006 and incorporated by reference herein.
3.2		Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO's current report on Form 8-K filed on February 14, 2006 and incorporated by reference herein.
4.1		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.
4.2		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
4.3		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
4.4		Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
4.5		Form of 7¹/4% Global Note Due 2011.**
4.6		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*
4.7		Registration Rights Agreement by and among EXCO Resources, Inc., certain domestic subsidiaries of EXCO Resources, Inc., as guarantors, and Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc, dated April 1, 2004.**
4.8		Pledge Agreement by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, dated January 20, 2004.*
4.9		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
4.10		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
4.11		Specimen Stock Certificate for EXCO's common stock, filed as an Exhibit to EXCO's Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.

10.1		Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003, filed as an Exhibit to EXCO's Form 8-K filed March 12, 2003 and incorporated by reference herein.
10.2		Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein.*
10.3		First Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**
10.4		Second Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**
10.5		Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein.*
10.6		First Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**
10.7		Second Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**
10.8		Amended and Restated Agreement and Plan of Merger among NCE Acquisition, Inc., EXCO Resources, Inc., North Coast Energy, Inc. and Nuon Energy & Water Investments, Inc., dated as of December 4, 2003, filed as exhibit (d)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.
10.9		Escrow Agreement among Nuon Energy & Water Investments, Inc., EXCO Resources, Inc. and Citibank, N.A., dated as of December 9, 2003.*
10.10		Unconditional Guaranty Agreement by and between EXCO Resources, Inc. and n.v. NUON, dated as of December 9, 2003.*
10.11		Commitment Letter among Credit Suisse First Boston Bank One, NA, Banc One Capital Markets, Inc. and EXCO Resources, Inc., dated November 25, 2003, filed as exhibit (b)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.
10.12		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*
10.13		Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*
10.14		Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, Canada Branch, as agent.*

10.15		Second Restated Unlimited Guaranty dated as of January 27, 2004, by EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Taurus Acquisition, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*
10.16		Amended and Restated Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*
10.17		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, as Agent.*
10.18		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, as Agent.*
10.19		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Holdings Inc. in favor of Bank One, NA, as Agent.*
10.20		Amended and Restated Subsidiary Guaranty dated as of January 27, 2004, by Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*
10.21		Third Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.
10.22		Third Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.
10.23		EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.24		First Amendment to the EXCO Holdings Inc. 2004 Long-term Incentive Plan, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.***
10.25		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.26		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.27		EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.***
10.28		EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***
10.29		Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.***

10.30		Unlimited Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, Canada Branch, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.31		Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.32		Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO's Form 8-K filed January 21, 2005 and incorporated by reference herein.
10.33		First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
10.34		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
10.35		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein.
10.36		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.
10.37		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
10.38		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.39		Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.40		Form of 7¹/4% Global Note Due 2011.**
10.41		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*
10.42		EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.43		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.44		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.45		Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.***
10.46		Fourth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated September 30, 2005, as filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and incorporated by reference herein.
10.47		Letter Agreement, dated October 3, 2005, between EXCO Resources, Inc. and JPMorgan Chase Bank, N.A., as agent for certain lenders under the Credit Agreement by and among EXCO Holdings II, Inc. (EXCO Holdings Inc. as successor by merger) as Borrower and JPMorgan Chase Bank, N.A., as Administrative Agent for itself and the Lenders defined therein, dated October 3, 2005, as filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.48		Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., as filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.49		First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.50		Fifth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA (successor by merger to Bank One, N.A. (Illinois), as Administrative Agent for itself and the Lenders defined therein, dated December 15, 2005, filed as an Exhibit to EXCO's Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.
10.51		Agreement and Plan of Merger between EXCO Holdings Inc. and EXCO Resources, Inc., dated February 9, 2006, filed as an Exhibit to EXCO's Current Report on Form 8-K filed February 14, 2006 and incorporated by reference herein.
10.52		Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.53		Guarantee, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., ROJO Pipeline, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Pinestone Resources, L.L.C., as Guarantors, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined herein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.

10.54		Credit Agreement for Senior Secured Revolving Credit Facility, dated as of September 27, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.55		First Amendment to Revolving Credit Agreement, dated as of December 15, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined herein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.56		Second Amendment to Revolving Credit Agreement, dated as of February 6, 2006, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.57		Subsidiary Guaranty, dated February 14, 2006, among TXOK Acquisition, Inc., TXOK Energy Resources Company, TXOK Energy Holdings, L.L.C., TXOK Texas Energy Holdings, LLC and TXOK Texas Energy Resources, L.P., as Subsidiary Guarantors, in favor of JPMorgan Chase Bank, NA, as agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
10.58		Amended and Restated Credit Agreement, dated as of March 17, 2006, among EXCO Resource, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Manager, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on March 23, 2006 and incorporated by reference herein.
10.59		EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
10.60		Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
10.61		Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
10.62		Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.
14.1		Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.2		Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
21.1		Subsidiaries of the registrant, filed herewith.

23.1		Consent of PricewaterhouseCoopers LLP, filed herewith.
23.2		Consent of Lee Keeling and Associates, Inc., filed herewith.
31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.
99.1		Audit Committee Charter, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.

*: Filed as an Exhibit to EXCO's Form S-4 filed March 25, 2004 and incorporated by reference herein.
**: Filed as an Exhibit to EXCO's Pre-effective Amendment No. 1 to the Form S-4 filed April 20, 2004 and incorporated by reference herein.
***: These exhibits are management contracts.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Good

Exco Resources (EXCO) Inactive 10-K2005 FY Annual report

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