10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2006

OR

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

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 x

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 x  NO o

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

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 x

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

As of March 1, 2007, the registrant had 104,221,015 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 aggregate market value of our common stock held by non-affiliates was $809,940,000.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement to be furnished to shareholders in connection with its 2007 Annual Meeting of Shareholders are incorporated by reference in Part III, Items 10-14 of this Annual Report on Form 10-K.

TABLE OF CONTENTS

			Page
PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	44
Item 2.	Properties	44
Item 3.	Legal Proceedings	44
Item 4.	Submission of Matters to a Vote of Security Holders	45
PART II		45
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
Item 6.	Selected Financial Data	46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	152
Item 9A.	Controls and Procedures	152
Item 9B.	Other Information	153
PART III		153
Item 10.	Directors and Executive Officers of the Registrant	153
Item 11.	Executive Compensation	153
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	154
Item 13.	Certain Relationships and Related Transactions	154
Item 14.	Principal Accountant Fees and Services	155
PART IV		155
Item 15.	Exhibits and Financial Statement Schedules	155

i

EXCO RESOURCES, INC.

PART I

ITEM 1.BUSINESS

General

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 merged into and was acquired by EXCO Holdings II, Inc., or Holdings II, in October 2005. On February 14, 2006, EXCO Holdings merged with and into EXCO Resources concurrent with our initial public offering, or IPO. As such, all periods presented reflect the merger and include EXCO Holdings.

The year ended December 31, 2004 and the period beginning January 1, 2005 and ending on October 2, 2005 are referred to as predecessor. The predecessor period represents the accounting period up to the Equity Buyout. For more information about the Equity Buyout, see “—Significant transactions during 2005.” The period beginning October 3, 2005 and ending on December 31, 2006 is referred to as successor.

We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of selected oil and natural gas terms” beginning on page 26.

EXCO Resources, 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 East Texas/North Louisiana, Appalachia, Mid-Continent and Permian. As of December 31, 2006, our Proved Reserves were approximately 1.2 Tcfe, of which 92% were natural gas and 60% were Proved Developed Reserves. As of December 31, 2006, the related PV-10 of our Proved Reserves was $1.6 billion, and the Standardized Measure of our Proved Reserves was $1.3 billion (see “—Summary of geographic areas of operation” for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the twelve months ended December 31, 2006, we produced 49.6 Bcfe of oil and natural gas. Based on our December 2006 average daily production, this translates to a reserve life of approximately 16.8 years. For the twelve month period ended December 31, 2006, we generated $355.8 million of oil and natural gas revenues.

We are a party to two pending acquisitions from Anadarko Petroleum Corporation and its affiliates, or Anadarko, that we expect will have a significant impact on our results of operations and financial condition during 2007. In January 2007, we sold our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado for $131.9 million. For more information about the pending acquisitions from Anadarko and the sale of our Wattenberg Field operations, see “—Significant subsequent events.” On February 14, 2007, we issued a press release pursuant to Rule 135c of the Securities Act of 1933 to announce a proposed private placement of up to $2.0 billion of preferred stock. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, capital resources and capital commitments—Proposed recapitalization.”

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, 2004 to December 31, 2006, we drilled 584 wells and completed 572 wells resulting in a 98% drilling

1

success rate. We have identified over 6,225 drilling locations and exploitation projects across our properties.

·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 acquisitions of North Coast Energy, Inc., or North Coast, in the Appalachian Basin, TXOK Acquisition, Inc., or TXOK, in the East Texas and the Mid-Continent areas and Winchester Energy Company, Ltd., or Winchester, in the East Texas and North Louisiana areas and our pending acquisitions from Anadarko are examples of this strategy.

·Actively manage our portfolio and associated costs

We 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 $443.4 million in February 2005 and the sale of our Wattenberg Field operations in Colorado for $131.9 million in January 2007.

·Maintain financial flexibility

We employ the use of debt and equity along with a comprehensive derivative financial instrument 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 1.2 Tcfe at December 31, 2006, and our average daily production increased from less than 1 Mmcfe per day in 1997 to 200.0 Mmcfe per day in December 2006. Importantly, as of March 1, 2007, our management team and employees (excluding our outside directors) own approximately 9.3% of our fully-diluted capital stock and our outside directors or their affiliates own approximately 15.4% 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 East Texas/North Louisiana, Appalachia, Mid-Continent and Permian 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.

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·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, 2006, we were the operator of 7,794 gross wells which represented 90% of our Proved Reserves.

Significant transactions during 2005

Sale of Addison.   On February 10, 2005, we sold Addison Energy Inc., or Addison, our former wholly-owned subsidiary through which all of our Canadian operations were conducted, for an aggregate sales price of Cdn. $551.3 million ($443.4 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 5. Sale of Addison Energy Inc.” of the notes to our consolidated financial statements for additional information.

TXOK acquisition.   On September 16, 2005, Holdings II formed TXOK for the purpose of acquiring ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C., collectively 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 $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.

Concurrent with our IPO 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 $158.8 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 had 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 “Note 16. Related party transactions” of the notes to our consolidated financial statements.

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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 the 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, 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 “Note 1. Organization—The Equity Buyout” of the notes to our consolidated financial statements.

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 7¼% Senior Notes due 2011, or 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.

Significant transactions during 2006

Initial public offering.   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:

·$360.0 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;

·$158.8 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 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

·$6.0 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, or the Indenture. 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.

4

Summary of 2006 acquisition activity.   During 2006, we completed the following acquisitions of oil and natural gas properties and undeveloped acreage, including the acquisition of Winchester, our largest acquisition to date. A summary of these acquisitions and the values allocated to oil and natural gas properties and gathering facilities, net of contractual adjustments, is presented on the following table.

(in thousands)	Effective dates	Values allocated
Asset acquisitions:
West Texas properties from private producer	April 2006		$	84,925
East Texas properties from private producer	May 2006		50,904
Wyoming properties from private producer	August 2006		27,519
Appalachia properties from private producer	September 2006		49,426
Mid-Continent region and other	Various		8,329
Corporate acquisitions:
TXOK Acquisition, Inc	February 2006		569,995
Power Gas Marketing & Transmission, Inc.	April 2006		125,966
Winchester Energy Company, Ltd.	October 2006		889,123
Total 2006 acquisitions			$	1,806,187

Details of the components of the purchase price and related allocation of the purchase price to the acquired assets and liabilities of our corporate acquisitions in 2006 are as follows:

(in thousands)	TXOK Acquisition, Inc.				Power Gas Marketing & Transmission, Inc.				Winchester Energy Company, Ltd.
Purchase price:
Carrying value of initial investment in TXOK Acquisition, Inc.		$	21,531			$	—			$	—
Acquisition of preferred stock, including accrued and unpaid dividends		158,750				—				—
Value of preferred stock redemption premium		4,667				—				—
Cash payments for acquired equity		—				63,615				1,095,028
Assumption of debt:
Term loan, plus accrued interest		202,755				—				—
Revolving credit facility plus accrued interest		309,701				13,096				—
Assumption of derivative financial instruments		—				38,098				—
Less cash acquired		(32,261		)		(1,839		)		(118		)
Net purchase price		$	665,143			$	112,970			$	1,094,910
Allocation of purchase price:
Oil and natural gas properties—proved		$	489,076			$	122,972			$	583,683
Oil and natural gas properties—unproved		60,840				421				154,291
Gathering and other fixed assets		20,079				2,573				151,149
Goodwill		64,887				21,249				163,935
Current and non-current assets		37,460				2,024				31,872
Deferred income taxes		26,783				(31,424		)		—
Accounts payable and other accrued expenses		(30,377		)		(3,318		)		(39,420		)
Asset retirement obligations		(8,203		)		(1,527		)		(7,793		)
Fair value of oil and natural gas derivatives		4,598				—				57,193
Total purchase price allocation		$	665,143			$	112,970			$	1,094,910

5

Redemption of preferred stock and acquisition of TXOK.   On February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights and an 89% economic interest in TXOK. The redemption price for the TXOK preferred stock was cash in the amount of $150.0 million plus $8.8 million of unpaid dividends at a rate of 15% and 388,889 shares of our common stock. The EXCO common stock issued in connection with the preferred redemption represented the value necessary to produce an overall 23% annualized rate of return on the stated value of the TXOK preferred stock as of the date of redemption pursuant to the terms of the preferred stock agreement. For purposes of calculating the rate of return, the common stock of EXCO was valued at $12.00 as required by the terms of the TXOK preferred stock. Once the TXOK preferred stock was redeemed, our acquisition of TXOK was complete and it became our wholly-owned subsidiary. We accounted for the acquisition of TXOK as a step acquisition using the purchase method of accounting and began consolidating its operations effective February 14, 2006. As a result, 89% of the fair value of the assets and liabilities of TXOK was recorded at the redemption date and the remaining 11% was recorded as an adjustment to book value as of the date of the initial investment. The total purchase price of TXOK was $665.1 million representing the redemption of the TXOK preferred stock, the initial investment in TXOK common stock and the assumption of liabilities.

Acquisition of Power Gas Marketing & Transmission, Inc.   On April 28, 2006, our wholly-owned subsidiary, North Coast, closed an acquisition of 100% of the common stock of Power Gas Marketing & Transmission, Inc., or PGMT, for a purchase price of $115.0 million before contractual adjustments, and a net purchase price of $113.0 million. The purchase price included the assumption of $13.1 million of debt and $38.1 million of derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under the EXCO Resources credit agreement, we paid the assumed debt and terminated the assumed derivative financial instruments. The acquisition was accounted for as a purchase in accordance with Statement of Financial Accounting Standards, or SFAS, No. 141 “Accounting for Business Combinations,” or SFAS No. 141.

Winchester acquisition.   On October 2, 2006, our wholly-owned subsidiary, Winchester Acquisition, LLC, or Winchester Acquisition, acquired Winchester and its affiliated entities from Progress Fuels Corporation, or PFC, for approximately $1.1 billion in cash. The acquisition consisted of producing and undeveloped oil and natural gas properties located in East Texas and North Louisiana, six gathering systems with approximately 300 miles of pipe and a 53 mile pipeline system. The average acquired working interest was 76% with an average 58% net revenue interest. The properties are located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. As of the closing date, the properties included approximately 734 gross drilling locations, 48% of which were proved, and approximately 114,000 net acres of leasehold of which 63% was held by production.

Concurrent with the acquisition, we contributed Winchester Acquisition to our wholly-owned subsidiary, EXCO Partners, LP, or EXCO Partners. Accordingly, Winchester Acquisition is now an indirect subsidiary of EXCO Partners. In addition, we also contributed all of our East Texas oil and natural gas properties, related pipeline and gathering systems, compressors and other production related equipment, and contracts, including financial derivative instruments associated with our East Texas production, to EXCO Partners in exchange for a payment to EXCO Resources of $150.0 million in cash. The proceeds were applied to reduce indebtedness outstanding under the EXCO Resources credit agreement. Included in the assets conveyed to EXCO Partners were four of our subsidiaries, ROJO Pipeline, LP (f/k/a ROJO Pipeline, Inc.), TXOK Energy Resources Holdings, LLC, TXOK Texas Energy Holdings, LLC and TXOK Texas Energy Resources, L.P. Following the equity contribution, these entities are no longer guarantors or restricted subsidiaries under the EXCO Resources credit agreement or the Indenture. EXCO Partners, its subsidiaries and its general partners are deemed unrestricted subsidiaries under the Indenture and the EXCO Resources credit agreement.

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To finance the acquisition and the $150.0 million payment to EXCO Resources for our East Texas assets, EXCO Partners’ wholly-owned subsidiary, EXCO Partners Operating Partnership, LP, or EPOP, entered into a Senior Revolving Credit Agreement, or EPOP Revolving Credit Facility, and a Senior Term Credit Agreement, or EPOP Senior Term Credit Agreement with a group of lenders led by JPMorgan Chase Bank, N.A. In connection with the arrangement of the EPOP Senior Term Credit Agreement, the lenders required us to enter into an Equity Contribution Agreement, or Contribution Agreement, dated October 2, 2006, as amended and restated on October 4, 2006 and October 13, 2006. For more information about the EPOP Revolving Credit Facility, the EPOP Senior Term Credit Agreement and the Contribution Agreement, see “Item 7. Management’s discussion and analysis of financial condition and results of operations—Our liquidity, capital resources and capital commitments.”

Significant subsequent events

Pending acquisition of Vernon Assets

On December 22, 2006, Vernon Holdings, LLC, or Vernon, our wholly-owned subsidiary, entered into a Purchase and Sale Agreement, or the Vernon Purchase Agreement, with Anadarko Petroleum Corporation and Anadarko Gathering Company. Subject to the terms and conditions in the Vernon Purchase Agreement, Vernon will acquire substantially all of the oil and natural gas properties and related assets, including derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009, or collectively the Vernon Assets, of Anadarko in the Vernon and Ansley Fields located in Jackson Parish, Louisiana.

Vernon will pay Anadarko a purchase price of approximately $1.6 billion in cash for the Vernon Assets, subject to certain purchase price adjustments. The purchase price will be: (i) reduced by proceeds earned (including, from the sale of hydrocarbons), and increased by costs incurred, with respect to the operation of the Vernon Assets during the period from 7:00 a.m., local time, on November 1, 2006, or the Effective Time, to the closing date, (ii) reduced by the aggregate amount of material title defects and material environmental defects exceeding $32.0 million, (iii) increased by the aggregate amount of material aggregate title benefits exceeding $32.0 million, (iv) reduced by the aggregate amounts payable to owners of working interests and other interests in the Vernon Assets held in suspense as of the closing date, (v) increased or reduced by the net amount of any gas imbalances as of the Effective Time, and (vi) increased by the value of merchantable stored hydrocarbons attributable to the Vernon Assets as of the Effective Time. In connection with the acquisition, derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009 were entered into by the seller and will be assumed by EXCO.

The Vernon Purchase Agreement contains customary representations, warranties and covenants. The acquisition is expected to close on or about March 30, 2007, subject to the satisfaction of various closing conditions, including, among others, (i) the aggregate amount of uncured title defects, environmental defects and casualty losses, net of title benefits, not exceeding $160.0 million and (ii) the sum of allocated values not exceeding $32.0 million for any Vernon Assets that are retained by Anadarko because of the failure to obtain, prior to closing, third-party consents required to transfer such Vernon Assets.

Concurrently with the execution of the Vernon Purchase Agreement, Vernon deposited with Anadarko an earnest money deposit in the amount of $80.0 million to be applied against the purchase price at closing or, if Anadarko terminates the Vernon Purchase Agreement because Vernon has materially breached Vernon’s representations, warranties or covenants under the Vernon Purchase Agreement, to be retained by Anadarko, as its sole and exclusive remedy, as liquidated damages. If the Vernon Purchase Agreement is terminated for any reason other than as stated in the preceding sentence, Anadarko is obligated to return the deposit to Vernon.

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Anadarko has agreed to indemnify Vernon after the closing, subject to certain limitations, for losses incurred by Vernon to the extent resulting from, arising out of or relating to (i) Anadarko’s breach of any representation or warranty of Anadarko contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (ii) Anadarko’s failure to perform any covenant or agreement contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (iii) liabilities associated with assets or properties not part of the Vernon Assets, (iv) scheduled litigation and other proceedings and other litigation and other proceedings that arise out of or are attributable to Anadarko’s ownership or operation of the Vernon Assets after December 22, 2006 but before the closing, (v) litigation and other proceedings that arise after closing for personal injury or death arising and occurring before the closing which is attributable to Anadarko’s ownership or operation of the Vernon Assets, (vi) obligations or liabilities attributable to scheduled incidences of noncompliance with laws by Anadarko, (vii) certain retained employee liabilities, and (viii) any off-site environmental liabilities occurring prior to the closing that relate to the Vernon Assets. Vernon has agreed to indemnify Anadarko after the closing, subject to certain limitations, for losses incurred by Anadarko to the extent resulting from, arising out of or relating to (a) Vernon’s breach of any representation or warranty of Vernon contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (b) Vernon’s failure to perform any covenant or agreement contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (c) the ownership, use or operation of the Vernon Assets after the Effective Time, (d) other than off-site environmental liabilities retained by Anadarko, any environmental liabilities associated with the Vernon Assets, and (e) certain obligations and liabilities of Anadarko with respect to the Vernon Assets that will be assumed by Vernon at the closing. Neither Anadarko, on the one hand, nor Vernon, on the other hand, will be obligated to indemnify the other (and other related indemnified persons specified in the Vernon Purchase Agreement) for losses until the amount of all losses incurred by such person and such other indemnified persons exceeds, in the aggregate, $40.0 million, in which event the party seeking indemnification may recover all losses incurred in excess of $40.0 million, up to a maximum liability of $400.0 million.

On December 22, 2006, in connection with the Vernon Purchase Agreement, EXCO entered into a guaranty agreement, or Vernon Guaranty, with Anadarko to guarantee Vernon’s payment obligations and Vernon’s performance of all covenants required to be performed by it pursuant to the terms of the Vernon Purchase Agreement and ancillary documents delivered in connection therewith. EXCO is the primary obligor under the Vernon Guaranty and must pay or perform, or cause the payment or performance, of any obligation not punctually paid or performed when due by Vernon. EXCO is not obligated to pay or perform any obligation to the extent that Vernon would not be required to pay or perform such obligation due to any defenses available to Vernon.

Pending acquisition of Southern Gas Assets

On February 1, 2007, EXCO Resources entered into a Purchase and Sale Agreement, or the Southern Gas Purchase Agreement, with Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, whereby, subject to the terms and conditions in the Southern Gas Purchase Agreement, EXCO Resources will acquire substantially all of the oil and natural gas properties and related assets, including derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009, or collectively the Southern Gas Assets, of Anadarko in multiple fields located in the Mid-Continent, South Texas and Gulf Coast areas, which fields are primarily located in Oklahoma, Texas and Louisiana.

EXCO Resources will pay Anadarko a purchase price of approximately $860.0 million in cash for the Southern Gas Assets, subject to certain purchase price adjustments. The purchase price will be:  (i) reduced by proceeds earned (including, from the sale of hydrocarbons), and increased by costs incurred, with respect to the operation of the Southern Gas Assets during the period from 7:00 a.m., local time, on

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January 1, 2007, or the Effective Date, to the closing date, (ii) reduced by the value of any Southern Gas Asset not conveyed to EXCO in the event a required preference right or transfer requirement has not been satisfied or waived as of the closing, (iii) reduced by the aggregate amount of material title defects and material environmental defects exceeding $17.0 million, (iv) increased by the aggregate amount of material aggregate title benefits exceeding $17.0 million, (v) reduced by the aggregate amounts payable to owners of working interests and other interests in the Southern Gas Assets held in suspense as of the closing date, (vi) reduced by the net amount of any gas imbalances as of the Effective Date, and (vii) increased by the value of merchantable stored hydrocarbons attributable to the Southern Gas Assets as of the Effective Date.

The Southern Gas Purchase Agreement contains customary representations, warranties and covenants. The acquisition is expected to close on or about May 2, 2007, subject to the satisfaction of various closing conditions, including, among others, (i) the termination of any applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (ii) the aggregate amount of uncured title defects, environmental defects and casualty losses, net of title benefits, not exceeding $86.0 million, and (iii) the sum of allocated values not exceeding $17.2 million for any Southern Gas Assets that are retained by Anadarko because of the failure to obtain, prior to closing, third-party consents required to transfer such Southern Gas Assets.

In connection with the execution of the Southern Gas Purchase Agreement, EXCO Resources deposited with Anadarko an earnest money deposit in the amount of $43.0 million to be applied against the purchase price at closing or, if Anadarko terminates the Southern Gas Purchase Agreement because EXCO Resources has materially breached its representations, warranties or covenants under the Southern Gas Purchase Agreement, to be retained by Anadarko, as its sole and exclusive remedy, as liquidated damages. If the Southern Gas Purchase Agreement is terminated for any reason other than as stated in the preceding sentence, Anadarko is obligated to return the deposit to EXCO Resources.

Anadarko has agreed to indemnify EXCO Resources after the closing, subject to certain limitations, for losses incurred by EXCO Resources to the extent resulting from, arising out of or relating to (i) Anadarko’s breach of any representation or warranty of Anadarko contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (ii) Anadarko’s failure to perform any covenant or agreement contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (iii) liabilities associated with assets or properties not part of the Southern Gas Assets, (iv) certain scheduled litigation and other proceedings and other litigation and other proceedings that arise out of or are attributable to Anadarko’s ownership or operation of the Southern Gas Assets after February 1, 2007 but before the closing, (v) litigation and other proceedings that arise after closing for personal injury or death arising and occurring before the closing which is attributable to Anadarko’s ownership or operation of the Southern Gas Assets, (vi) obligations or liabilities attributable to scheduled incidences of noncompliance with laws by Anadarko, (vii) certain retained employee liabilities, and (viii) any off-site environmental liabilities occurring prior to the closing that relate to the Southern Gas Assets. EXCO Resources has agreed to indemnify Anadarko after the closing, subject to certain limitations, for losses incurred by Anadarko to the extent resulting from, arising out of or relating to (a) EXCO Resources’ breach of any representation or warranty contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (b) EXCO Resources’ failure to perform any covenant or agreement contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (c) the ownership, use or operation of the Southern Gas Assets after the Effective Date, (d) other than off-site environmental liabilities retained by Anadarko, any environmental liabilities associated with the Southern Gas Assets, and (e) certain obligations and liabilities of Anadarko with respect to the Southern Gas Assets that will be assumed by EXCO Resources at the closing. Neither Anadarko, on the one hand, nor EXCO Resources, on the other hand, will be obligated to indemnify the other (and other related indemnified persons

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specified in the Southern Gas Purchase Agreement) for losses until the amount of all losses incurred by such person and such other indemnified persons exceeds, in the aggregate, $21.5 million, in which event the party seeking indemnification may recover all losses incurred in excess of $21.5 million, up to a maximum liability of $215.0 million.

In connection with the pending acquisitions, the following derivative financial instruments covering estimated production for 2007, 2008 and 2009 were entered into by the seller and will be assumed by us:

Vernon Assets

	Swaps
			Weighted					Weighted
			average					average
	NYMEX gas		contract			NYMEX oil		contract
	volume—		price per			volume—		price per
(in thousands, except average contract prices)	Mmbtus		Mmbtu			Bbls		Bbl
Q1 2007		12,600		$	7.35		—		$	—
Q2 2007		12,740		7.35			—		—
Q3 2007		12,880		7.35			—		—
Q4 2007		12,880		7.35			—		—
2008		38,430		8.16			—		—
2009		32,850		7.84			—		—

Southern Gas Assets

	Swaps
			Weighted					Weighted
			average					average
	NYMEX gas		contract			NYMEX oil		contract
	volume—		price per			volume—		price per
(in thousands, except average contract prices)	Mmbtus		Mmbtu			Bbls		Bbl
Q1 2007		4,130		$	7.51		177		$	54.32
Q2 2007		6,370		7.43			273		56.03
Q3 2007		5,520		7.58			184		57.51
Q4 2007		5,520		8.28			184		58.67
2008		18,300		8.14			732		59.60
2009		14,600		7.83			730		59.98

To ensure that EXCO has sufficient financing to complete the acquisitions from Anadarko of oil and natural gas properties in the Vernon and Ansley Fields in Jackson Parish, Louisiana, EXCO received a revised commitment letter dated as of February 1, 2007, from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A. This commitment letter supersedes and replaces the commitment letter we received on December 22, 2006, in conjunction with our entering into the Vernon Purchase Agreement. The new commitment letter, as subsequently supplemented, provides for a senior secured revolving credit facility commitment in the amount of $1.8 billion and an undertaking to arrange a bridge loan facility in the amount of $1.1 billion if requested, or collectively the new credit facilities. If used to finance these acquisitions, the new credit facilities will contain customary representations, warranties and covenants, and the closing of the new credit facilities will be subject to the satisfaction of customary closing conditions. EXCO is also pursuing other financing alternatives, including a proposed private placement of preferred stock. For a discussion of the proposed terms of the preferred stock, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, capital resources and capital commitments—Proposed recapitalization.”

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Sale of Wattenberg Field

In January 2007, we completed the sale of our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. The transaction included substantially all of our assets in the area. Proved reserves sold were approximately 55.7 Bcfe. The adjusted purchase price paid at closing was $131.9 million.

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, 2006:

Areas	Total proved reserves (Bcfe)(1)		PV-10 (in millions) (1)(2)			Average December daily net production (Mmcfe/d)	Reserve life (years)(3)
East Texas/North Louisiana		513.7		$	614.1	100.7	14.0
Appalachia		444.7		504.7		45.0	27.1
Mid-Continent		105.5		239.7		27.0	10.7
Permian		85.4		159.8		17.4	13.4
Rockies		71.8		82.8		7.1	27.7
Gulf Coast/Other		2.4		4.9		2.8	2.3
Total		1,223.5		$	1,606.0	200.0	16.8

Areas	Identified drilling locations(4)		Identified exploitation projects(5)		Total gross acreage	Total net acreage(6)
East Texas/North Louisiana		811		455	187,198	153,875
Appalachia		3,120		84	887,662	818,677
Mid-Continent		190		175	179,393	105,875
Permian		710		47	63,055	34,896
Rockies		264		355	190,868	157,820
Gulf Coast/Other		5		9	7,673	4,555
Total		5,100		1,125	1,515,849	1,275,698

(1)The total Proved Reserves and PV-10 of the Proved Reserves as used in this table were prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. For each area set forth in the table, the Proved Reserves and PV-10 were determined by our internal engineers.

(2)   The PV-10 data used in this table is based on December 31, 2006 spot prices of $5.64 per Mmbtu for natural gas and $60.82 per Bbl for oil, in each case adjusted for historical differentials. 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, 2006 was $1.3 billion. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with SFAS No. 69 “Disclosures about Oil and Gas Producing Activities,” or SFAS No. 69. The amount of estimated future abandonment costs, the PV-10 of these costs and the Standardized Measure were determined by us. We do not designate our derivative financial instruments as hedges

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and accordingly, do not include the impact of derivative financial instruments when computing the Standardized Measure.

The following table provides a reconciliation of our PV-10 to our Standardized Measure as of December 31, 2006:

(in millions)
PV-10	$	1,606.0
Future income taxes	(721.2		)
Discount of future income taxes at 10% per annum	427.0
Standardized Measure	$	1,311.8

(3)For purposes of this table, the reserve life is calculated by dividing the Proved Reserves (on an 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.

(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, 2,719 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, 523 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 46,756, 60,730, and 36,426 net acres with leases expiring in 2007, 2008 and 2009, respectively.

Our development and exploitation project areas

East Texas/North Louisiana

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 15,000 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 Harrison, Panola, Smith, Rusk, Upshur and Gregg Counties in Texas primarily across six fields—Waskom, Overton, Oak Hill, Minden, Glenwood and White Oak. We are also active in Caddo Parish and DeSoto Parish in Louisiana primarily across four fields—Holly, Kingston, Caspiana and Longwood. At December 31, 2006, we had Proved Reserves of 513.7 Bcfe and 1,179 gross producing wells. We operate 96% of our 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. We currently plan to drill 125 wells during 2007.

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Appalachia

The Appalachian Basin includes portions of the states of Kentucky, 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 11 counties in central Pennsylvania. At December 31, 2006, we had Proved Reserves of 203.4 Bcfe and 1,736 gross producing wells. We operate 99.7% of our Proved Reserves in this area. Production is primarily from the Venango, Bradford, and Elk groups at depths from 1,800 to 4,600 feet. We currently plan to drill 156 wells during 2007.

Northeast Ohio Area

The Northeast Ohio Area includes a 14 county area located south of Lake Erie in northeastern Ohio. At December 31, 2006, we had Proved Reserves of 49.2 Bcfe and 854 gross producing wells. We operate 99.97% of our Proved Reserves in this area. Production  in the Northeast Ohio area is primarily from the Silurian Clinton Sandstone found at depths of 3,500 to 5,600 feet. We currently plan to drill 36 wells during 2007.

Jamestown Area

The Jamestown Area is located in western Pennsylvania. At December 31, 2006, we had Proved Reserves of 19.8 Bcfe. We operate 162 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 2007.

Ravenswood Area

The Ravenswood Area is located in the western portion of West Virginia. At December 31, 2006, we had Proved Reserves of 45.9 Bcfe and 593 gross producing wells. We operate 98.1% 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 11 wells during 2007.

Maben Area

The Maben Area is located in southwest West Virginia. At December 31, 2006, we had Proved Reserves of 31.4 Bcfe and 317 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

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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 nine wells during 2007.

Adamsville Area

The Adamsville Area is located in south central Ohio. At December 31, 2006, we had Proved Reserves of 10.6 Bcfe and 336 gross producing wells. We operate 98.9% 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 seven wells during 2007.

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, 2006, we had Proved Reserves of 41.7 Bcfe and we had 497 gross producing wells. We operate 77% of our Proved Reserves. At Mocane-Laverne, we are targeting eight productive formations at depths from 2,500 to 9,000 feet. We currently plan to drill 22 wells during 2007.

Cement Field

Our Cement Field, which was acquired in the TXOK acquisition, is located in Caddo and Grady Counties of Oklahoma. At December 31, 2006, we had Proved Reserves of 27.0 Bcfe and we had 134 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. We currently plan to participate in the drilling of eight wells during 2007.

Chitwood Field

Our Chitwood Field, which was acquired in the TXOK acquisition, is near our Cement Field and is located in Grady County, Oklahoma. At December 31, 2006, we had Proved Reserves of 21.7 Bcfe and we had 55 gross producing wells. We operate 65% of our Proved Reserves. At Chitwood, we are targeting four productive formations at depths of 15,000 to 17,600 feet. We currently plan to drill six wells during 2007.

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 natural 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.

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Sugg Ranch Field

Our Sugg Ranch Field is located primarily in Irion County, Texas. At December 31, 2006, we had Proved Reserves of 33.7 Bcfe and 88 gross producing wells, all operated by others. At Sugg Ranch, production is primarily from the Canyon Sand depths of 6,700 to 7,300 feet. We currently plan to participate in the drilling of 84 wells during 2007.

Our oil and natural gas reserves

The following tables summarize historical information regarding Proved Reserves at December 31, 2004, 2005 and 2006 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 Securities and Exchange Commission, or SEC.

	At December 31,
	2004		2005		2006
Oil (Mmbbls)
Developed	6.0		5.5		11.3
Undeveloped	1.2		1.3		4.9
Total	7.2		6.8		16.2
Natural gas (Bcf)
Developed	319.5		321.7		665.3
Undeveloped	43.1		79.5		461.3
Total	362.6		401.2		1,126.6
Pre-tax present value, discounted at 10% (PV-10) (in millions)(1)
Developed	$	642.2	$	1,046.7	$	1,353.7
Undeveloped	58.2		201.9		252.3
Total	$	700.4	$	1,248.6	$	1,606.0
Standardized Measure (in millions)	$	473.7	$	823.3	$	1,311.8

(1)The PV-10 data does not include the effects of income taxes or derivative financial instruments, and is based on the following spot prices, in each case adjusted for historical differentials.

	Spot price
Date	Natural gas (per Mmbtu)			Oil (per Bbl)
December 31, 2004		$	6.19		$	43.33
December 31, 2005		10.08			61.03
December 31, 2006		5.64			60.82

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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,
(in millions)	2004			2005			2006
PV-10	$	700.4		$	1,248.6		$	1,606.0
Future income taxes	(588.9		)	(1,097.6		)	(721.2		)
Discount of future income taxes at 10% per annum	362.2			672.3			427.0
Standardized Measure	$	473.7		$	823.3		$	1,311.8

The total reserve estimates presented as of December 31, 2004, 2005 and 2006 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 and natural gas 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 and natural gas prices, 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 22. Supplemental information relating to oil and natural gas producing activities—continuing operations (unaudited)” of the notes to our consolidated financial statements for additional information regarding our oil and natural gas reserves and our Standardized Measure.

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Our production, prices and expenses

The following table summarizes revenues (before cash settlements of derivative financial instruments), net production of oil and natural gas sold, average sales price per unit of oil and natural gas and costs and expenses associated with the production of oil and natural gas. This table includes information for acquisitions from the date of closing and excludes information with respect to Canada as a result of the sale of Addison in February 2005.

	Predecessor						Successor
				For the 275 day period			For the 90 day period
				from January 1, 2005			from October 3, 2005
(in thousands, except	Year ended			to			to			Year ended
production and per unit amounts)	December 31, 2004			October 2, 2005			December 31, 2005			December 31, 2006
Sales:
Oil:
Revenue(1)		$	24,694		$	19,528		$	6,666		$	57,043
Production sold (Mbbl)		638			375			116			916
Average sales price per Bbl(1)		$	38.71		$	52.07		$	57.47		$	62.27
Natural gas:
Revenue(1)		$	117,299		$	113,293		$	63,395		$	298,737
Production sold (Mmcf)		19,220			15,490			5,112			44,123
Average sales price per Mcf(1)		$	6.10		$	7.31		$	12.40		$	6.77
Costs and expenses:
Average production cost per Mcfe		$	1.23		$	1.25		$	1.54		$	1.39
General and administrative expense per Mcfe(2)		$	0.67		$	5.04		$	1.10		$	0.83
Depreciation, depletion and amortization per Mcfe		$	1.24		$	1.39		$	2.42		$	2.74

(1)Excludes the effects of derivative cash settlements and derivative financial instruments.

(2)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.” 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.

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	At December 31, 2006
	Gross wells(1)			Net wells
Areas	Oil	Gas	Total	Oil	Gas	Total
East Texas/North Louisiana	70	1,109	1,179	62.8	825.2	888.0
Appalachia	409	5,908	6,317	404.0	5,399.0	5,803.0
Mid-Continent	232	658	890	100.9	259.7	360.6
Permian	108	143	251	43.2	86.7	129.9
Rockies	114	178	292	56.5	147.3	203.8
Gulf Coast/Other	24	11	35	5.2	4.4	9.6
Total	957	8,007	8,964	672.6	6,722.3	7,394.9

(1)As of December 31, 2006, we owned interests in 38 gross wells with multiple completions.

As of December 31, 2006, we were the operator of 7,794 gross (7,012.1 net) wells, which represented approximately 90% of our Proved Reserves as of December 31, 2006.

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 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, 2004		91		2		93		85.4		1.3	86.7
Year ended December 31, 2005		104		2		106		101.1		1.5	102.6
Year ended December 31, 2006		366		5		371		298.2		2.3	300.5

	Exploratory wells
	Gross						Net
	Productive		Dry		Total		Productive		Dry		Total
Year ended December 31, 2004		6		1		7		6.0		1.0	7.0
Year ended December 31, 2005		4		1		5		2.7		0.2	2.9
Year ended December 31, 2006		1		1		2		0.3		0.3	0.6

At December 31, 2006, we had 15 gross (10.1 net) wells being drilled and 18 gross (15.1 net) wells being completed.

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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 at December 31, 2006:

	At December 31, 2006
	Developed acreage		Undeveloped acreage
Areas	Gross	Net	Gross	Net
East Texas/North Louisiana	123,775	96,345	63,423	57,530
Appalachia	425,489	389,465	462,173	429,212
Mid-Continent	157,700	91,617	21,693	14,258
Permian	37,161	21,795	25,894	13,101
Rockies	47,344	29,622	143,524	128,198
Gulf Coast/Other	5,095	2,817	2,578	1,738
Total	796,564	631,661	719,285	644,037

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. We have 46,756, 60,730 and 36,426 net acres with leases expiring in 2007, 2008 and 2009, respectively.

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 $443.4 million and the sale of our Wattenberg Field operations in Colorado for $131.9 million in January 2007. During the years ended December 31, 2004, 2005 and 2006, we received proceeds of $51.9 million, $45.3 million and $5.2 million, respectively, from the sale of properties in the United States.

Midstream operations

We own and operate a network of natural gas gathering systems comprised of approximately 500 miles of pipeline in our East Texas/North Louisiana area of operation, which gathers and transports natural gas to larger gathering systems and intrastate, interstate and local distribution pipelines owned by third parties. Of all the natural gas gathered and transported by this system, approximately 83% represents production from our assets and approximately 17% represents production from the assets of third parties. We transport natural gas from unaffiliated producers on our gathering and pipeline assets under fixed fee arrangements pursuant to which our gathering and transportation fee income represents an agreed rate per unit of throughput. The revenues we earn from these arrangements are directly related to the volume of natural gas that flows through our systems and are not directly dependent on commodity prices.

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In connection with the Winchester acquisition, we acquired a 53-mile intrastate pipeline, or the TGG Pipeline, composed of 23 miles of 12-inch diameter and 30 miles of 16-inch diameter pipelines. The TGG Pipeline connects to several processing plants owned by others and interconnects 12 interstate pipeline markets. During December 2006, average throughput volume on the TGG Pipeline was 105 Mmcf/d with a total capacity of 175 Mmcf/d. Of all the natural gas transported by the TGG Pipeline, approximately 25% represents production from our assets and approximately 75% represents production from the assets of third parties.

Our principal customers

For the twelve months ended December 31, 2006, sales to one interstate pipeline company accounted for 11.6% of total oil and natural gas revenues. For the twelve months ended December 31, 2005 and 2004 sales to one industrial customer accounted for 10.1% and 10.6%, respectively, of total oil and natural gas revenues. We believe that the loss of any one customer would not have a material adverse effect on our results of operations or financial condition.

Competition

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

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

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We regularly evaluate acquisition opportunities and submit bids as part of our growth strategy.

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.

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FERC Matters

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 the FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

Federal, state or Indian oil and natural gas leases

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.

Other regulatory matters relating to our pipeline and gathering system assets

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 March 2006, the PHMSA issued a final rule regarding the definition of, and safety standards for, gas gathering pipelines, which establishes a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We could incur significant expenses as a result of this rule.

U.S. federal taxation

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

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U.S. environmental regulations

The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to federal environmental laws and regulations, including, but not limited to:

·the Oil Pollution Act of 1990, 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.

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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 a 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

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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, or CZMA, 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;

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·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 agreements.

Our employees

As of December 31, 2006, we employed 471 persons of which 284 were involved in field operations and 187 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 of 1933, or 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 use of derivative financial instruments; 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 and economic assumptions used in connection with our acquisitions;

·geological concentration of our reserves;

·risks associated with drilling and operating wells;

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

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

·cash flow and liquidity;

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

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·availability of drilling and production equipment;

·marketing of oil and natural gas;

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

·competition;

·title to our properties;

·litigation;

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

·governmental regulations;

·receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument 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; and

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

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, 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.

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

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.

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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.

Commercial Well; Commercially Productive Well.An oil and natural gas well which produces oil and natural gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

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.

Developed Acreage.   The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well.   A well drilled within the proved area of an oil or natural gas reservoir, or which extends a proved reservoir, to the depth of a stratigraphic horizon known to be productive.

Dry Hole; Dry Well.   A well found to be incapable of producing either oil or naural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploratory Well.   A well drilled to find and produce oil or natural gas in an unproved area or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Farmout.   An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Formation.   A succession of sedimentary beds that were deposited under the same general geologic conditions.

Full Cost Pool.   The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross Acres or Gross Wells.   The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal Wells.   Wells which are drilled at angles greater than 70 degrees from vertical.

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.

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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.

NYMEX.   New York Mercantile Exchange.

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.

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 derivative financial instrument 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 natural 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

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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.

Tcf.   One trillion cubic feet of natural gas.

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

Undeveloped Acreage.   Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains Proved Reserves.

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 at www.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

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operations,” 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, 2006, 92% of our 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 use of derivative financial instruments 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 derivative financial instrument 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. Derivative financial instruments 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 derivative financial instrument contract may default on its contractual obligations to us;

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·there may be a change in the expected differential between the underlying price in the derivative financial instrument 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 use of derivative financial instruments 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 year ended December 31, 2005, we made cash settlement payments on our derivative financial instrument contracts totaling $85.0 million. During the year ended December 31, 2006, we received cash settlements from our counterparties totaling $29.4 million. For the year ended December 31, 2006, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments (or a decrease in settlements received) of approximately $30.0 million. As of December 31, 2006, the net unrealized gains on our derivative financial instrument contracts was $96.4 million. The ultimate settlement amount of these unrealized derivative financial instrument contracts is dependent on future commodity prices. In connection with the acquisitions of TXOK and Winchester, we assumed additional derivative financial instruments that TXOK and Winchester had entered into covering a significant portion of their estimated future production. In connection with the pending acquisitions of the Vernon Assets and the Southern Gas Assets, we expect to assume additional derivative financial instruments from Anadarko covering a significant portion of estimated future production. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices 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—Derivative financial instruments.”

We will face risks associated with our recent and pending acquisitions relating to difficulties in integrating operations, potential disruptions of operations, and related negative impact on earnings.

The acquisitions of TXOK and Winchester represented a significant increase in our reserves and production. These acquisitions are the largest acquisitions that we have completed to date. As a result of the TXOK and Winchester acquisitions, as of December 31, 2006, we added 1,751 gross (1,042.7 net) wells to our consolidated portfolio of wells, including approximately 1,083 gross operated wells, which materially increased the number of wells we currently operate. If the pending acquisitions of the Vernon Assets for $1.6 billion in cash, subject to post-closing purchase price adjustments, and the Southern Gas Assets for $860.0 million in cash, subject to post-closing purchase price adjustments, are consummated, they will be significant acquisitions for us. We expect to add approximately 1,677 gross wells in connection with the pending acquisitions from Anadarko.

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 theses acquisitions 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. We may not be successful in overcoming these risks or any other problems encountered in connection with these acquisitions, 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.

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We incurred a substantial amount of indebtedness to fund the acquisition of Winchester, 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.

Concurrent with the acquisition of Winchester, we contributed Winchester Acquisition to our wholly-owned subsidiary, EXCO Partners. In addition, we also contributed all of our East Texas oil and natural gas properties, related pipeline and gathering systems, compressors and other production related equipment, and contracts, including financial derivative instruments associated with our East Texas production, to EXCO Partners in exchange for a payment to us of $150.0 million in cash. To finance the acquisition and the $150.0 million payment to us for our East Texas assets, EXCO Partners’ wholly-owned subsidiary, EPOP, entered into the EPOP Revolving Credit Facility. The initial amount borrowed under this facility was $651.0 million at closing of the acquisition of Winchester. As of December 31, 2006, $643.5 million was outstanding under the EPOP Revolving Credit Facility. In connection with the acquisition and our asset contribution, EPOP also entered into the EPOP Senior Term Credit Agreement. The aggregate principal amount of the Senior Term Credit Agreement is $650.0 million.

In connection with the arrangement of the Senior Term Credit Agreement, the lenders required us to enter into the Contribution Agreement. The Contribution Agreement generally provides that on the date 18 months from the Equity Contribution Date, we will make a cash common equity contribution to EPOP in an amount equal to the lesser of (i) $150.0 million or (ii) the aggregate amount then outstanding under the Senior Term Credit Agreement; provided, that in no event can this obligation exceed during the term of the Contribution Agreement the maximum amount that we could contribute under the terms of the Indenture governing our senior notes. Alternatively, we can cause EXCO Partners to make the equity contribution to EPOP in the amount of $150.0 million to satisfy this obligation. In lieu of requiring the equity contribution to be made, the lenders can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become “Restricted Subsidiaries” under our credit agreement and require us to provide and cause all then Restricted Subsidiaries as defined and constituted under our credit agreement to provide guarantees and collateral in respect of the Senior Term Credit Agreement on terms substantially consistent with the guarantees and collateral provided under our credit agreement. This requirement is subject to compliance with our credit agreement. Any cash so contributed shall be used by EPOP to prepay loans under the Senior Term Credit Agreement. EXCO Resources and its subsidiaries are prohibited from making restricted payments (as defined in the Indenture) that would constitute a utilization of the Indenture restricted payment baskets, other than Restricted Payments not to exceed $5.0 million. In addition, we have covenanted to redeem or defease our senior notes if the Indenture would not permit the equity contribution or the lenders’ election to cause us to designate EPOP and its subsidiaries as Restricted Subsidiaries under our credit agreement (subject to certain restrictions on the indebtedness that may be incurred for any such redemption or defeasance if the election to cause the designation of EPOP as a Restricted Subsidiary is chosen).

The success of our natural gas gathering and transportation business depends upon our ability to continually obtain new sources of natural gas supply, and any decrease in supplies of natural gas could reduce our transportation revenues.

Our gathering and transportation pipelines are connected to natural gas reserves and wells, for which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our pipelines, we must continually obtain new natural gas supplies. We may not be able to obtain additional third party contracts for natural gas supplies. The primary factors affecting our ability to connect new supplies of gas and attract new customers to our gathering and transportation pipelines include: (1) the level of successful drilling activity near our gathering systems and (2) our ability to compete for the commitment of such additional volumes to our systems.

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Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations other than our own drilling, the amount of reserves underlying the wells or the rate at which production from a well will decline. In addition, we have no control over third party producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.

We face strong competition in acquiring new natural gas supplies. Competitors to our pipeline operations include major interstate and intrastate pipelines, and other natural gas gatherers. Competition for natural gas supplies is primarily based on the location of pipeline facilities, pricing arrangements, reputation, efficiency, flexibility and reliability. Many of our competitors have greater financial resources than we do.

If we are unable to maintain or increase the throughput on our gathering and transportation pipelines because of decreased drilling activity in the areas in which we operate or because of an inability to connect new supplies of gas and attract new customers to our gathering and transportation pipelines, then our business and financial results could be materially adversely affected.

If third-party pipelines and other facilities interconnected to our gathering and transportation pipelines become unavailable to transport or process natural gas, our revenues and cash could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options from our transportation and gathering pipelines for the benefit of our customers. All of the natural gas transported by Winchester’s pipeline must be processed by processing plants before delivery into a pipeline for natural gas. Winchester does not own or control any of these processing plants. If the processing plants to which we deliver natural gas were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers would be unable to deliver natural gas to end markets. Either of such events could materially and adversely affect our business, results of operations and financial condition.

We do not own all of the land on which our transportation and gathering pipelines and gathering system are located, which could disrupt our operations.

We do not own all of the land on which our transportation and gathering pipelines have been constructed, and we are therefore subject to the possibility of increased costs to retain necessary land use. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

We expect to incur a substantial amount of indebtedness to fund the acquisitions of the Vernon Assets and the Southern Gas Assets, 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.

To finance the acquisitions of the Vernon Assets and the Southern Gas Assets, we received a Commitment Letter from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A., providing for a senior secured revolving credit facility commitment in the amount of $1.8 billion and an undertaking to arrange a bridge loan facility in the amount of $1.1 billion, if requested. If used to finance the acquisitions, the new credit facilities will contain customary representations, warranties and covenants, and the closing

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of the new credit facilities will be subject to the satisfaction of customary closing conditions. To service this 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. 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. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt under the new credit facilities, which could cause us to default on our obligations and could impair our liquidity. We are also pursuing other financing alternatives.

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 the TXOK and Winchester 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 TXOK and Winchester acquisitions are subject to floors and caps and do not cover all these types of risks.

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 agreements, 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

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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 size and scope of our business from an operational, personnel, financial reporting and accounting perspective has substantially increased due to the TXOK and Winchester acquisitions and will further increase due to the pending acquisitions of the Vernon Assets and the Southern Gas Assets. 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 prevent or address material weaknesses 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. In addition, prior to the quarter ended September 30, 2006, our management concluded that our disclosure controls and procedures were not effective due to a material weakness relating to accounting for income taxes.

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 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 have resulted 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 have been prevented or detected. Accordingly, management concluded that this deficiency in internal control over financial reporting was a material weakness. Although we believe we have taken the necessary steps to remediate this material weakness, as described in Item 9A of this Annual Report on Form 10-K, we may identify additional material weaknesses or other deficiencies in our internal control over financial reporting in the future.

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

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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.

Any material weaknesses or other deficiencies in our internal control over financial reporting may affect our ability to comply with SEC reporting requirements and New York Stock Exchange, or 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, Chief Financial Officer and Chief Accounting 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, 2005 and 2006 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.

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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 Winchester and TXOK acquisitions 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, 2006, third parties operate wells that represent approximately 10% of our Proved Reserves. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

·the timing and amount of capital expenditures;

·the operators’ expertise and financial resources;

·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 and natural gas 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 and natural gas reserves, including many factors beyond our control. This annual report contains estimates of our proved oil and natural gas reserves and the PV-10 of our proved oil and natural gas 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 and natural gas 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

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estimating oil and natural gas 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 and natural gas 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

·attorneys’ 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 potential 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.

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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 could 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 could 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, 2006, sales of natural gas to one interstate pipeline company accounted for 11.6% of our total oil and natural gas revenues. For the years ended December 31, 2005 and 2004, sales of natural gas to one industrial customer accounted for 10.1% and 10.6%, respectively, of our total oil and natural gas revenues. In 2006, our top eight customers accounted for approximately 38.2% of our total oil and natural gas revenues. To the extent any significant customer reduces the volume of its

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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 personnel 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.

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 1, 2007, we had approximately $2.1 billion of indebtedness, including $1.7 billion of indebtedness which is subject to variable interest rates. Our total interest expense on an annual basis would be approximately $180.0 million and would change by approximately $17.0 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

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·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 agreements 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 agreements, 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 agreements, 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 agreements 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;

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·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 agreements require 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 agreements 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 arrangements and our senior notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit arrangements 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. We amended certain financial covenants under the EPOP Revolving Credit Facility due to our inability to meet certain financial covenants associated with our EPOP Revolving Credit Facility (—See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, capital resources and commitments—EPOP Revolving Credit Facility.”)

Risks relating to our common stock

Our stock price may fluctuate significantly.

Our common stock began trading on the NYSE on February 9, 2006. An active trading market may not 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.

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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, 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 1, 2007, we had 104,221,015 shares of common stock outstanding. Of these shares, 70,628,370 shares are freely tradable, unless any of these shares are held by our affiliates.

Many of our shareholders, including our executive officers and directors, are subject to agreements that limit their ability to sell our common stock held by them. 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 were covered by this agreement. Any holder who is a party to this agreement has the right, commencing 180 days after completion of the IPO on February 14, 2006, to require us to register for resale up to one-third of their 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. On January 17, 2007, our registration statement covering 16,796,244 shares was declared effective by the SEC.

The same rights exist commencing 365 days and 540 days after February 14, 2006 for an additional one-third of their shares at each such anniversary. 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. On January 11, 2007, J.P. Morgan Securities Inc. and EXCO executed a waiver letter that allows selling shareholders to request that we register for resale the remaining two-thirds of their shares at any time after February 14, 2007. On February 15, 2007, we received a request from one of our shareholders to register the remaining two-thirds of his shares in accordance with the registration rights agreement. We expect to register 33,592,645 shares, the remaining two-thirds of the shares subject to the registration rights agreement, as soon as practicable after the filing of this annual report. 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

43

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 are considering the issuance of up to $2.0 billion of preferred stock to institutional accredited investors in a private placement under the Securities Act of 1933. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, capital resources and capital commitments—Proposed recapitalization.” We have not entered into definitive agreements with potential investors to issue any preferred stock. As a result, we may never issue any preferred stock. In addition, any preferred stock that we ultimately issue may contain terms different from those provided in this annual report.

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 agreements and the 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 17,000 square feet and requires monthly rental payments of approximately $23,700. The Akron office lease expires December 15, 2012. 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. We lease 15,246 square feet of office space in Shreveport, Louisiana. The lease expires September 30, 2008. This lease requires monthly rental payments of approximately $12,100 per month. We also have small offices for technical and field operations in Texas, Oklahoma, Colorado, Nebraska, Ohio and West Virginia.

Other

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

ITEM 3.LEGAL PROCEEDINGS

On October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styled PRC Holdings, LLC, et al. v. North Coast Energy, Inc. and was filed in the Circuit Court of Roane County, West Virginia. This action has been removed to the United States District Court for the Southern District of West Virginia. The action has been brought by certain landowners and lessors in West

44

Virginia for themselves and on behalf of other similarly situated landowners and lessors in West Virginia. The lawsuit alleges that North Coast Energy, Inc. has not been paying royalties to the plaintiffs in the manner required under the applicable leases, has provided misleading documentation to the plaintiffs regarding the royalties due, and has breached various other contractual, statutory and fiduciary duties to the plaintiffs with regard to the payment of royalties. In a case styled The Estate of Garrison Tawney v. Columbia Natural Resources, LLC announced in June 2006, the West Virginia Supreme Court held that language such as “at the wellhead” and similar language contained in leases when used in describing how to calculate royalties due lessors was ambiguous and, therefore, should be construed strictly against the lessee. Accordingly, in the absence of express language in a lease that is intended to allocate between a lessor and lessee post-production costs such as the costs of marketing the product and transporting it to the point of sale, no post-production costs may be deducted from the lessor’s royalty payment due from the lessee. The claims alleged by the plaintiffs in the lawsuit filed against us are similar to the claims alleged in the Tawney case. Plaintiffs are seeking common law and statutory compensatory and punitive damages, interest and costs and other remedies. We are vigorously defending the existing lawsuit. The action is in a very preliminary stage. The preliminary status of the lawsuit leaves the ultimate outcome of this litigation uncertain. We believe that we have substantial defenses to this lawsuit and that the adverse affects from this litigation, if any, are reflected in our financial statements and we do not expect the ultimate outcome of the lawsuit to have a material effect on our financial position, results of operations or cash flows.

In the ordinary course of business, we are periodically a party to lawsuits and claims. 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.

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 NYSE under the symbol “XCO”.

The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the NYSE:

	Common Stock
	High		Low
Year ended December 31, 2006:
First Quarter	$	13.70	$	11.81
Second Quarter	13.03		9.55
Third Quarter	15.00		10.05
Fourth Quarter	18.20		12.15
Year ended December 31, 2005:
First Quarter	N/A		N/A
Second Quarter	N/A		N/A
Third Quarter	N/A		N/A
Fourth Quarter	N/A		N/A

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Our shareholders

According to our transfer agent, Continental Stock Transfer & Trust Company, there were approximately 147 holders of record of our common stock on March 1, 2007 (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 agreements currently prohibit 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.

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 operations,” 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 2002 that materially impact the comparability of this data between periods.

The selected financial data for the twelve months ended December 31, 2002 and the 209 day period from January 1, 2003 to July 28, 2003 is referred to as public predecessor and represents accounting periods when EXCO was a publicly traded company on the Nasdaq. On July 29, 2003, EXCO completed a going private transaction which resulted in a change of accounting basis. The selected financial data for the 156 day period from July 29, 2003 to December 31, 2003, the twelve months ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005 is referred to as predecessor and represents the period of time when EXCO was privately held. The period from the Equity Buyout on October 3, 2005, which resulted in an additional change in accounting basis, through December 31, 2006 is referred to as successor.

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	Public predecessor					Predecessor
			209 day period from January 1 to July 28,			156 day period from July 29 to December 31,
(in thousands, except per share amounts)	2002		2003			2003
Statement of operations data(1):
Revenues and other income:
Oil and natural gas	$	34,287		$	22,403		$	21,767
Derivative financial instruments(2)	—			—			(10,800)
Other	6,599			(1,129)			(141)
Total revenues and other income	40,886			21,274			10,826
Costs and expenses:
Oil and natural gas production	19,018			11,380			7,331
Depreciation, depletion and amortization	9,031			5,125			5,413
Accretion of discount on asset retirement obligations(3)	—			320			205
General and administrative	6,777			11,347			3,874
Interest expense	1,191			1,058			1,921
Impairment of marketable securities	1,136			—			—
Total costs and expenses	37,153			29,230			18,744
Income (loss) before income taxes	3,733			(7,956)			(7,918)
Income tax benefit	(2,672)			(181)			(7,764)
Income (loss) before discontinued operations and change in accounting principle	6,405			(7,775)			(154)
Discontinued operations:
Income (loss) from operations	(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:	(7,372)			8,552			4,300
Income (loss) before change in accounting principle	(967)			777			4,146
Cumulative effect of change in accounting principle, net of income tax	—			255			—
Net income (loss)	(967)			1,032			4,146
Dividends on preferred stock	5,256			2,620			—
Earnings (loss) on common stock	$	(6,223)		$	(1,588)		$	4,146
Basic earnings (loss) per share from continuing operations	$	0.16		$	(1.25)		$	—
Basic loss per share—total	$	(0.88)		$	(0.19)		$	0.04
Diluted earnings (loss) per share from continuing operations	$	0.16		$	(1.25)		$	—
Diluted income (loss) per share—total	$	(0.88)		$	(0.19)		$	0.04
Weighted average common and common equivalent shares outstanding:
Basic	7,061			8,084			115,947
Diluted	12,533			8,084			115,947
Statement of cash flow data:(2)
Net cash provided by (used in):
Operating activities	$	31,660		$	20,418		$	21,495
Investing activities	(76,937)			(23,520)			(237,623)
Financing activities	45,928			9,982			214,284
Balance sheet data:(2)
Current assets	$	26,198		n/a			$	31,641
Total assets	241,174			n/a			505,056
Current liabilities	33,193			n/a			45,188
Long-term debt, less current maturities	97,943			n/a			—
Shareholders’ equity	99,894			n/a			183,895
Total liabilities and shareholders’ equity	241,174			n/a			505,056

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Selected consolidated financial and operating data (continued)

	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				2006
Statement of operations data(1):
Revenues and other income:
Oil and natural gas	$	141,993			$	132,821			$	70,061		$	355,780
Derivative financial instruments(2)	(50,343		)		(177,253		)		(256		)	198,664
Other	1,184				7,096				2,374			5,005
Total revenues and other income	92,834				(37,336		)		72,179			559,449
Costs and expenses:
Oil and natural gas production	28,256				22,157				8,949			68,874
Depreciation, depletion and amortization	28,519				24,687				14,071			135,722
Accretion of discount on asset retirement obligations(3)	800				617				226			2,014
General and administrative(4)	15,466				89,442				6,375			41,206
Interest expense	34,570				26,675				19,414			84,871
Total costs and expenses	107,611				163,578				49,035			332,687
Equity in net income of TXOK Acquisition, Inc.	—				—				837			1,593
Income (loss) before income taxes	(14,777		)		(200,914		)		23,981			228,355
Income tax expense (benefit)	5,126				(63,698		)		7,631			89,401
Income (loss) before discontinued operations	(19,903		)		(137,216		)		16,350			138,954
Discontinued operations:
Income (loss) from operations	36,274				(4,403		)		—			—
Gain on disposition of Addison Energy Inc.	—				175,717				—			—
Income tax expense	10,358				49,282				—			—
Income from discontinued operations:	25,916				122,032				—			—
Net income (loss)	$	6,013			$	(15,184	)		$	16,350		$	138,954
Basic earnings (loss) per share from continuing operations	$	(0.17	)		$	(1.18	)		$	0.35		$	1.44
Basic earnings (loss) per share—total	$	0.05			$	(0.13	)		$	0.35		$	1.44
Diluted earnings (loss) per share from continuing operations	$	(0.17	)		$	(1.18	)		$	0.35		$	1.41
Diluted earnings (loss) per share—total	$	0.05			$	(0.13	)		$	0.35		$	1.41
Weighted average common and common equivalent shares outstanding:
Basic	115,947				116,504				47,222			96,727
Diluted	115,947				116,504				47,222			98,453
Statement of cash flow data:(2)
Net cash provided by (used in):
Operating activities	$	118,528			$	(81,122	)		$	8,177		$	227,659
Investing activities	(381,476		)		337,880				(13,337		)	(1,791,517		)
Financing activities	283,708				(47,035		)		(4,018		)	1,359,727
Balance sheet data:(2)
Current assets	$	75,877			n/a				$	342,525		$	236,710
Total assets	922,052				n/a				1,530,493			3,707,057
Current liabilities	105,695				n/a				465,725			190,924
Long-term debt, less current maturities	487,453				n/a				461,802			2,081,653
Shareholders’ equity	203,885				n/a				370,882			1,179,850
Total liabilities and shareholders’ equity	922,052				n/a				1,530,493			3,707,057

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(1)We have completed numerous acquisitions and dispositions since January 1, 2002 that materially impact the comparability the selected financial data between periods.

(2)On July 28, 2003, EXCO completed a going private transaction which resulted in a change of control and a new basis of accounting. Upon consummation of the going private transaction, we discontinued the designation of our derivative financial instruments as hedges. Beginning with July 29, 2003, changes in the fair value of our derivative financial instruments are recognized directly in our statement of operations. See “Item 7. Managements discussion and analysis of financial condition and results of operations—Critical accounting policies—Accounting for derivatives” for a description of this accounting method.

(3)We adopted SFAS No. 143, “Accounting for asset retirement obligations,” or SFAS No. 143, on January 1, 2003. See “Note 2. Summary of significant accounting policies—Deferred abandonment and asset retirement obligations” in the notes to our consolidated financial statements included in this annual report.

(4)The 275 day period from January 1, 2005 to October 2, 2005 includes non-cash based compensation of $44.1 million and Equity Buyout compensation expenses of $29.6 million. We adopted SFAS No. 123(R), “Share-Based Payment” on October 3, 2005. Share-based compensation pursuant to SFAS No. 123(R) included in general and administrative expenses is $3.0 million and $6.5 million for the 90 day period from October 3, 2005 to December 31, 2005 and the twelve months ended December 21, 2006, respectively. See “Note 2. Summary of significant accounting policies—stock options” in the notes to our consolidated financial statements included in this annual report.

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ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 results and the 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 and history

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 and, until February 10, 2005, in Canada. 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 derivative financial instrument 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. On February 14, 2006, we acquired TXOK for approximately $665.1 million and on October 2, 2006, we completed the acquisition of Winchester for approximately $1.1 billion in cash after closing adjustments. The Winchester acquisition was completed within our newly-formed subsidiary, EXCO Partners. Concurrent with the closing of this acquisition we contributed to EXCO Partners all of our East Texas assets, including four of our subsidiaries that own or operate certain of our East Texas assets, in exchange for $150.0 million of cash and additional equity interests in EXCO Partners. EPOP borrowed $1.3 billion to fund these transactions. Our 2006 acquisitions, including TXOK and Winchester, totaled in excess of $2.1 billion. In addition, we spent $214.3 million for development drilling, acreage and related oil and natural gas facilities during 2006. For a discussion of these acquisitions as well as other transactions that we completed during 2005 and 2006, see “Item 1. Business—Significant transactions during 2005” and “Item 1. Business—Significant transactions during 2006.” We expect that our pending acquisitions with Anadarko will have a significant impact on our results of operations, liquidity and financial condition during 2007. For a discussion of these pending acquisitions, see “Item 1. Business—Significant subsequent events.”

Oil and natural gas prices have historically been volatile. During 2006, the NYMEX price for natural gas has fluctuated from a high of $10.63 per Mmbtu to a low of $4.20 per Mmbtu. On December 31, 2006, the spot market price for natural gas at Henry Hub was $5.64 per Mmbtu, a 45% decrease from December 31, 2005. The price of oil has shown similar volatility. In 2006, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $62.27 per Bbl and $6.77 per Mcf compared with 2005 prices of $53.35 per Bbl and $8.58, respectively. The volatile commodity price environment from 2004 through 2006, which was accentuated in 2005 by historical high prices for natural gas after the hurricanes in the third quarter of 2005, caused an increase in demand for drilling rigs, field supplies and related oil field service costs. EXCO, as well as other producers of oil and natural gas, experienced some difficulty in timely scheduling drilling and related services during this period. However, we did not encounter any significant operational problems or operational delays as a result of these scheduling difficulties. We cannot predict the impact that the recent declines in oil and natural gas prices could cause to our operating revenues, results of operations, or capital budgets nor can we predict the impact on the pricing for drilling rigs and related oil field services. Management continuously monitors its operations and capital budget and employs the use of derivative financial instruments to lessen the impact of fluctuating prices for oil and natural gas.

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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 identify and 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 which provided for a borrowing base of $750.0 million with an aggregate commitment of $500.0 million. As a result of the acquisition of Winchester on October 2, 2006, and the contribution of our East Texas assets to EXCO Partners, our credit agreement was further amended to reflect the contribution of these assets by reducing the borrowing base to $600.0 million with a $500.0 million aggregate commitment. EPOP has a separate $750.0 million credit agreement with a $650.0 conforming borrowing base and $650.0 million term loan which was used to finance the acquisition of Winchester. We believe we will have adequate unused borrowing capacity under our credit agreements and available 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.

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 policies used in the preparation of our consolidated financial statements. We determined the critical policies 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, accounting for business combinations, derivatives accounting, 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. Upon closing of the Equity Buyout, we adopted SFAS No. 123(R), “Share-Based Payment,” or 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.

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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 quantities directly and 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 and natural gas 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 and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil and natural gas, that may occur in undrilled prospects; and (D) crude oil and natural gas that may be recovered from oil shales, coal, gilsonite and other such sources.

Business combinations

We follow SFAS No. 141 to record our acquisitions of oil and natural gas properties or entities which we acquire. SFAS No. 141 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of SFAS No. 141 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.

Accounting for derivatives

We use derivative financial instruments 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 derivative financial instruments is to manage price fluctuations and achieve a more predictable cash flow to fund our development, acquisition activities and support debt incurred with our acquisitions. These derivative financial instruments are not held for trading purposes. We do not designate our derivative

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financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value as a component of current earnings.

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. Upon closing of the Equity Buyout, we adopted SFAS No. 123(R). At December 31, 2006, our employees and directors held options under EXCO’s 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 8,267,373 shares of EXCO common stock at prices ranging from $7.50 per share to $14.62 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. We use the Black-Scholes model to calculate the fair value of issued options. The gross fair value of the granted options using the Black-Scholes model range from $2.29 per share to $5.01 per share. SFAS No. 123(R) requires share-based compensation be recorded with cost classifications consistent with cash compensation. EXCO uses the full cost method to account for its oil and natural gas properties. As a result, part of our share-based payments are capitalized. Total share-based compensation for 2006 was $7.9 million, of which $1.4 million was capitalized to the full cost pool. In 2005, a total of $3.2 million of share-based compensation was incurred, of which $1.0 million was capitalized to the full cost pool.

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.

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 oil and natural gas property costs on an ongoing basis, and we expect these costs to be evaluated in one to five years and transferred to the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus 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.

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). Until February 10, 2005, this ceiling test calculation was done separately for the United States and for the Canadian full cost pools. When computing our full cost ceiling limitation, we evaluate the limitation at the end of each reporting period date. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation for price changes that

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occur after the balance sheet to assess impairment as permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. In addition, in February 2007, we sought, and received an exemption from the SEC to exclude our 2006 acquisitions of oil and natural gas properties from our ceiling test for a period of 12 months, provided that we could demonstrate beyond a reasonable doubt that the fair value of the oil and natural gas reserves acquired in 2006 exceeded their unamortized carrying costs. Assuming we can demonstrate the fair value exceeds the carrying costs for the next 12 months, we will initially test the 2006 acquisitions at December 31, 2007.

The quarterly 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 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 SEC released SAB No. 106 concerning the application of SFAS No. 143 “Accounting for Asset Retirement Obligations,” or SFAS No. 143, 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 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. Additional goodwill in 2006 of $64.9 million, $21.2 million and $163.9 million was recognized from the acquisitions of TXOK, PGMT and Winchester, respectively. As of December 31, 2006, our consolidated goodwill totals $470.1 million. Our strategy is to concentrate on accumulating assets in East Texas, North Louisiana, the Mid-Continent region and Appalachia. We believe the strategic value paid for the assets substantiates the goodwill we have incurred.

None of the goodwill is currently deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, “Goodwill and Intangible Assets,” or SFAS No. 142, 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, subject to various assumptions and judgments. Actual future results of these assumptions could differ as a result of economic changes which are not within our control. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations.

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Asset retirement obligations

In June 2001, the Financial Accounting Standards Board, or FASB, issued SFAS No. 143. 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 SFAS No. 143 on January 1, 2003. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. Recent cost increases have impacted our evaluation of asset retirement obligations. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.

Accounting for income taxes

Income taxes are accounted for using the liability method of accounting in accordance with SFAS No. 109, “Accounting for Income Taxes,” or SFAS No. 109. 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

In July 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. FIN 48 is effective as of January 1, 2007. The adoption of FIN 48 did not have a material impact on our financial statements.

In September 2006, the SEC Staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” or SAB 108, in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We adopted SAB 108 in the fourth quarter of 2006. The adoption of SAB 108 did not have a material impact on our financial statements.

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In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will be required to adopt SFAS No. 157 in the first quarter of fiscal year 2008. We are currently evaluating the impact of SFAS No. 157 on our financial statements.

Our results of operations

Due to the application of purchase accounting for the Equity Buyout in October 2005, our results of operations contain predecessor and successor periods. Because the application of purchase accounting can inhibit meaningful comparison of historical results before and after such transactions, we analyzed the impact of the Equity Buyout on our statements of operations. We believe that our results of operations for 2004, 2005 and 2006 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 2005. As a result we believe that the non-GAAP measurements for 2005, discussed below, provide a more meaningful basis for comparing our results of operations. A summary of key financial data for 2004, 2005 and 2006 related to our results of operations for the years then ended is presented below.

	Predecessor								Successor
					For the 275				For the 90
					day period				day period
					from				from
					January 1,				October 3,				Non-				Successor
	Year ended				2005 to				2005 to				GAAP				Year ended			Year to year change(b)
	December 31,				October 2,				December 31,				combined				December 31,			2004 -			2005 -
(dollars in thousands)	2004				2005				2005				2005				2006			2005			2006
Production:
Oil (Mbbls))		638				375				116				491				916		(147		)	425
Natural gas (Mmcf)(a)		19,220				15,490				5,112				20,602				44,123		1,382			23,521
Total production (Mmcfe)		23,048				17,740				5,808				23,548				49,619		500			26,071
Oil and natural gas revenues before derivative financial instrument activities:
Oil revenues		$	24,694			$	19,528			$	6,666			$	26,194			$	57,043	$	1,500		$	30,849
Natural gas sales(a)		117,299				113,293				63,395				176,688				298,737		59,389			122,049
Total oil and gas sales		$	141,993			$	132,821			$	70,061			$	202,882			$	355,780	$	60,889		$	152,898
Derivative financial instruments:
Cash settlements on derivative financial instruments		$	(26,083	)		$	(62,842	)		$	(22,210	)		$	(85,052	)		$	29,423	$	(58,969	)	$	114,475
Non-cash change in fair value of derivative financial instruments		(24,260		)		(114,411		)		21,954				(92,457		)		169,241		(68,197		)	261,698
Total derivative financial instruments management activities		$	(50,343	)		$	(177,253	)		$	(256	)		$	(177,509	)		$	198,664	$	(127,166	)	$	376,173
Average sales price (before cash settlements of derivative financial instruments):
Oil (Bbl)		$	38.71			$	52.07			$	57.47			$	53.35			$	62.27	$	14.64		$	8.92
Natural gas (per Mcf)		6.10				7.31				12.40				8.58				6.77		2.48			(1.81		)
Natural gas equivalent (per Mcfe)		6.16				7.49				12.06				8.62				7.17		2.46			(1.45		)
Oil and natural gas production costs:
Oil and natural gas operating costs		$	19,834			$	14,581			$	5,485			$	20,066			$	46,534	$	232		$	26,468
Production and ad valorem taxes		8,422				7,576				3,464				11,040				22,340		2,618			11,300
Depreciation, depletion and amortization		28,519				24,687				14,071				38,758				135,722		10,239			96,964
General and administrative		15,466				89,442				6,375				95,817				41,206		80,351			(54,611		)
Interest expense		34,570				26,675				19,414				46,089				84,871		11,519			38,782
Expenses (per Mcfe):
Operating costs		0.86				0.82				0.94				0.85				0.94		$	(0.01	)	$	0.09
Production and ad valorem taxes		0.37				0.43				0.60				0.47				0.45		0.10			(0.02		)
Depreciation, depletion and amortization		1.24				1.39				2.42				1.65				2.74		0.41			1.09
General and administrative		0.67				5.04				1.10				4.07				0.83		3.40			(3.24		)
Income (loss) from continuing operations		$	(19,903	)		$	(137,216	)		$	16,350			$	(120,866	)		$	138,954	$	(100,963	)	$	259,820

(a)Natural gas production and sales include volumes and values previously reported as natural gas liquids for 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the non-GAAP combined 2005. Barrels of natural gas liquids volumes have been calculated by converting one barrel of natural gas liquids to six Mcf of natural gas.

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

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The following is a discussion of our financial condition and results of operations for the years ended December 31, 2004, 2005 and 2006. Information presented for the year ended December 31, 2005 represents the non-GAAP combined total for the 275 day period from January 1, 2005 to October 2, 2005 (predecessor) and the 90 day period from October 3, 2005 to December 31, 2005 (successor).

The comparability of our results of operations from 2004, 2005 and 2006 is impacted by:

·the acquisition of North Coast on January 27, 2004;

·property acquisitions and dispositions, including the sale of Addison on February 10, 2005;

·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;

·changes in our Proved Reserves and their impact on depreciation, depletion and amortization;

·fluctuations associated with use of mark-to-market for derivative financial instruments;

·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 and the adoption of SFAS No. 123(R);

·the IPO that closed on February 14, 2006;

·the acquisition of TXOK on February 14, 2006, PGMT on April 28, 2006 and Winchester on October 2, 2006; and

·the incurrence of $1.3 billion of debt incurred to finance the Winchester acquisition.

The availability of a ready market for oil and natural gas and the prices of oil and natural gas 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 and natural gas from any producing well in which we have or may acquire an interest.

Marketing arrangements and backlog

We produce oil and natural gas. 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

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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 oil 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 natural gas 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 prices 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., or Alliance, 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 connected 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 and 2006 aggregated $20.6 million and $17.5 million, respectively, or 10.1% and 4.9%, respectively, of our total oil and natural gas revenues. During 2006, oil and natural gas sales to Duke Energy and its affiliates totaled 11.6% of our total oil and natural gas revenues.

We may be unable to market all the oil and natural gas we produce. If our oil and natural gas 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 and natural gas 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.

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Summary

For purposes of comparative analysis, we have combined the predecessor and successor operating results for the 2005 periods and refer to the combined results as non-GAAP 2005.

For the year ended December 31, 2006, we had income from continuing operations of  $139.0 million on consolidated revenues (before impacts of derivative financial instruments) of $355.8 million compared with a net loss from continuing operations of $120.9 million on consolidated revenues of $202.9 million for the non-GAAP combined 2005 period (before impacts of derivative financial instruments). Net income for the 2005 non-GAAP combined period was $1.2 million which reflects a $122.0 million gain from the sale of Addison in February 2005. For the year ended December 31, 2004, net income was $6.0 million on consolidated revenues (before impacts of derivative financial instruments) of $142.0 million. The impact of acquisitions and derivative financial instruments are significant to our results of operations. During 2006, we closed over $1.8 billion of acquisitions of oil and natural gas properties which significantly increased our revenues and related operating costs. In addition, we do not designate our derivative financial instruments as hedges. Therefore, we mark the changes in the fair value of our derivative financial instruments to market at the end of each reporting period. Due to significant fluctuations in the price of oil and natural gas during 2004, 2005 and 2006, the impacts of derivative financial instruments, including the mark-to-market impacts, totaled losses of $50.3 million and $177.5 million for 2004 and non-GAAP combined 2005, respectively, while 2006 activities resulted in derivative gains of $198.7 million, of which $169.2 million is unrealized.

Oil and natural gas sales, production and prices

Total oil and natural gas sales, excluding the impact of derivative financial instruments, for 2006 were $355.8 million compared with $202.9 million for non-GAAP combined 2005 and $142.0 million in 2004. For 2006, natural gas represented 84.0% of our revenues and 88.9% of equivalent production. Both 2005 and 2004 also have natural gas percentages in excess of 80.0% of total revenues and total production. Our equivalent sold production volumes for 2006 were 49.6 Bcfe  compared with 23.5 Bcfe for non-GAAP combined 2005, an increase of 111.1%. Equivalent production from our 2006 acquisitions represented over 50% of 2006 total volumes. Sold production volumes for 2004 were 23.0 Bcfe, 2.1% less than non-GAAP combined 2005. The average price per Mcfe, before the impact of derivative financial instruments, was $7.17, $8.62 and $6.16 for 2006, non-GAAP combined 2005 and 2004, respectively.

For 2006, our average price received for natural gas, excluding the impact of derivative financial instruments, was $6.77 per Mcf compared with $8.58 per Mcf in non-GAAP combined 2005 and $6.10 in 2004. The average price received for oil, also excluding the impacts of derivative financial instruments was $62.27 per Bbl, or 16.7% higher than the non-GAAP combined 2005 price of $53.35 per Bbl.  The average price per Bbl for 2004 was $38.71. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal condition, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows and related liquidity. Assuming our December 2006 production levels, a change of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues and cash flow of approximately $6.5 million and a change of $1.00 per Bbl of oil sold would result in an increase or decrease in revenues and cash flow of approximately $1.2 million without considering the effects of derivative financial instruments.

Changes in oil and natural gas volumes from our acquisitions, development drilling and exploitation projects combined with significant price fluctuations significantly impacted our operating revenues and

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cash flows from operations. In 2006, our revenues (before the impact of derivative financial instruments) increased to $355.8 million from $202.9 million for non-GAAP combined 2005. The total increase of $152.9 million was attributable to an increase of $185.9 million from increased volumes primarily due to 2006 acquisitions. This increase was partially offset by a reduction in our realized price per Mcfe, which lowered revenue by $33.0 million.

During 2006, our acquisitions were focused on East Texas/North Louisiana and Appalachia regions of the United States. TXOK also significantly increased our presence in the Mid-Continent region. Following is a summary of production grouped by our significant producing regions for the years ended December 31, 2004, non-GAAP combined 2005 and 2006.

	Years ended December 31,
	2004		Non-GAAP 2005		2006
Areas	Mmcfe	%	Mmcfe	%	Mmcfe	%
East Texas/North Louisiana	813	3.5	2,894	12.3	17,423	35.1
Appalachia	11,105	48.2	12,892	54.7	15,028	30.3
Mid-Continent	1,288	5.6	994	4.2	9,494	19.1
Permian	3,821	16.6	3,591	15.2	4,725	9.5
Rockies	2,662	11.5	2,553	10.8	2,484	5.0
Gulf Coast and other	3,359	14.6	624	2.6	465	0.9
Total production	23,048	100.0	23,548	100.0	49,619	100.0

In January 2007, we completed the sale of our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. This transaction included substantially all of our assets in the Rockies area. If the pending acquisitions of the Vernon Assets and the Southern Gas Assets are consummated, we expect to significantly increase our production in the East Texas/North Louisiana and Mid-Continent areas during 2007.

Derivative financial instruments

Our objective in entering into derivative financial instrument 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 derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instrument 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.

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The following table presents our derivative financial instrument activities and components of other income. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments. As a result of the pending acquisitions from Anadarko, we will assume additional derivative financial instruments covering a substantial portion of the acquired production.

	Predecessor		Successor		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 ended December 31, 2006	Year to year  change 2004-2005(a)	Year to year change 2005-2006(a)
Derivative financial instrument activities:

Cash settlements on derivative financial instruments	$	(26,083	)	$	(62,842	)	$	(22,210	)	$	(85,052	)	$	29,423	$	(58,969	)	$	114,475
Non-cash change in fair value ofderivative financial instruments	(24,260		)	(114,411		)	21,954			(92,457		)	169,241		(68,197		)	261,698
Total derivative financial instrument activities	$	(50,343	)	$	(177,253	)	$	(256	)	$	(177,509	)	$	198,664	$	(127,166	)	$	376,173

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

Our cash settlements for 2006 increased revenue by $29.4 million compared with cash payments of $85.1 million for non-GAAP combined 2005. The cash payments in 2005 reduced revenue while the 2006 cash receipts increased revenue. The NYMEX oil and natural gas prices that we used to settle our derivative financial instruments varied significantly during 2005 and 2006. In 2005, the impacts of hurricanes caused natural gas prices to reach record highs which resulted in us making significant payments to our counterparties. Cash payments for the non-GAAP combined 2005 period includes payments totaling $52.6 million made in January and March 2005 to counterparties to terminate existing derivative contracts and enter into new derivative contracts at higher underlying product prices.

Our mark-to-market non-cash changes in the value of derivative financial instruments for 2006 resulted in a gain of $169.2 million compared with a $92.5 million loss in the prior year. The significant fluctuation was again attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

We expect to continue our comprehensive derivative financial instrument 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, 2006, we had derivative financial instruments, excluding the pending acquisitions from Anadarko, in place hedging approximately 79% of our expected 2007 oil production and approximately 83% of our expected 2007 natural gas production . These levels are consistent with our acquisition and financing strategy and average historical levels of hedged production.

Oil and natural gas operating costs

Operating costs, which include labor, materials and supplies necessary to produce our oil and natural gas were $46.5 million, or $0.94 per Mcfe for 2006, compared with $20.1 million, or $0.85 per Mcfe for non-GAAP combined 2005. The increase of $26.5 million is due primarily to $21.9 million of costs associated with the 2006 acquisitions, including TXOK, PGMT and Winchester. The per unit increase in cost reflects a general increase in the cost of goods and services for all of our producing areas.

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Operating costs for 2004 were $19.8 million, or $0.86 per Mcfe, compared with $20.1 million, or $0.85 per Mcfe, for non-GAAP 2005. Operating costs per unit outside of our Appalachia area decreased to $0.89 per Mcfe in non-GAAP combined 2005 from $0.97 in 2004. This decrease was due primarily to sales of producing properties in 2004 which had higher operating costs. Per unit costs in our Appalachia region increased to $0.82 per Mcfe in non-GAAP combined 2005 from $0.74 in 2004 due primarily to higher personnel related costs and increased costs of goods and services used in the operations.

Production and ad valorem taxes

Production and ad valorem taxes were $22.3 million, $11.0 million and $8.4 million for 2006, non-GAAP combined 2005 and 2004, respectively. Production taxes are set by state and local governments and vary as to the tax rate and the value to which the rate is applied. Further, ad valorem taxes in Texas, where a substantial amount of our oil and natural gas is produced, are based partially on the value of oil and natural gas reserves, which can fluctuate significantly depending on prices for these products. On a percentage of sales basis, our 2006 production and ad valorem taxes were 6.3% of oil and natural gas sales, excluding the impact of derivative financial instruments compared with 5.4% for non-GAAP combined 2005 and 5.9% in 2004. The change in the consolidated rate in 2006 compared with non-GAAP combined 2005 is due to a higher percentage of revenues from our East Texas, North Louisiana and Mid-Continent producing areas which have higher combined production and ad valorem tax rates than our Appalachia producing area.

Depreciation, depletion and amortization

The following table presents our depreciation, depletion and amortization expenses for 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, non-GAAP combined 2005 and 2006. The depreciation, depletion and amortization rate per Mcfe produced varies significantly for each of the periods presented due to the Equity Buyout on October 3, 2005 which resulted in a new stepped-up basis of accounting, which increased the calculated rate per Mcfe from $1.65 per Mcfe to $2.42 per Mcfe for the 90 day period from October 3, 2005 to December 31, 2005. During 2006, our acquisition of TXOK, PGMT and Winchester further increased the depreciation, depletion and amortization rate to $2.74 per Mcfe in 2006.

	Predecessor		Successor
		For the 275 day	For the 90 day		Successor
(in thousands)	Year ended December 31, 2004	period from January 1, 2005 to October 2, 2005	period from October 3, 2005 to December 31, 2005	Non-GAAP combined 2005	Year ended December 31, 2006	Year to year change 2004-2005(a)	Year to year change 2005-2006(a)
Depreciation, depletion and amortization costs:

Depreciation, depletion and amortization expense	$	28,519	$	24,687	$	14,071	$	38,758	$	135,722	$	10,239	$	96,964
Mmcfe produced	23,048		17,740		5,808		23,548		49,619		500		26,071
Calculated rate per Mmcfe	$	1.24	$	1.39	$	2.42	$	1.65	$	2.74	$	0.41	$	1.09

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

Accretion of discount on asset retirement obligations increased to $2.0 million in 2006 from $0.8 million each in non-GAAP combined 2005 and the year ended December 31, 2004. The increase in 2006 is due to the combination of significant well additions and related plugging liabilities in connection with our 2006 acquisitions and increased estimates for the costs to plug and abandon properties. The increased estimates for plugging and abandoning properties reflect increased costs for labor, rig rates and materials used in those operations.

General and administrative expenses

The following table presents our general and administrative expenses for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from

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October 3, 2005 to December 31, 2005, the twelve months non-GAAP combined 2005 and the year ended December 31, 2006 and changes for each of the years then ended. The table also reflects significant non-recurring expenses incurred in connection with the October 3, 2005 Equity Buyout.

	Predecessor		Successor
		For the 275 day	For the 90 day		Successor
(in thousands except per unit amounts)	Year ended December 31, 2004	period from January 1, 2005 to  October 2, 2005	period from October 3, 2005 to  December 31, 2005	Non-GAAP combined 2005	Year ended December 31, 2006	Year to year change 2004-2005(a)	Year to year change 2005-2006(a)
General and administrative costs:

Gross general and administrative expense	$	19,157		$	18,220		$	7,329		$	25,549		$	52,357		$	6,392		$	26,808
Operator overhead reimbursements	(2,109		)	(1,291		)	(532		)	(1,823		)	(7,824		)	286			(6,001		)
Nonrecurring bonus expense from equity buyout	—			29,624			—			29,624			—			29,624			(29,624		)
Equity buyout non cash-stock based compensation	—			44,092			—			44,092			—			44,092			(44,092		)
Capitalized acquisition, development and exploitation charges	(1,582		)	(1,203		)	(422		)	(1,625		)	(3,327		)	(43		)	(1,702		)
Net general and administrative expense	$	15,466		$	89,442		$	6,375		$	95,817		$	41,206		$	80,351		$	(54,611	)
General and administrative expense per Mcfe	$	0.67		$	5.04		$	1.10		$	4.07		$	0.83		$	3.40		$	(3.24	)

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

Net general and administrative expenses for the year ended December 31, 2006 were $41.2 million compared with $95.8 million in non-GAAP combined 2005, a decrease of $54.6 million. Each of the respective years contains significant and notable variances. In 2006, we experienced significant increases in personnel and related support facilities. These  increased personnel related expenses totaled approximately $7.2 million of increased cash expenses and increases of approximately $4.3 million from share-based compensation. We also incurred approximately $9.2 million of legal and project-oriented costs including (i) audit and legal fees in connection with our 2006 acquisitions, (ii) fees associated with services related to the formation of EXCO Partners, (iii) costs for implementation and compliance with Section 404 of the Sarbanes-Oxley Act of 2002 and (iv) expenses incurred for conversion of our information technology systems to a common platform. General and administrative costs for 2005 included non-recurring costs of $73.7 million ($44.1 million of which was non-cash stock compensation) related to the Equity Buyout.

When comparing non-GAAP combined 2005 general and administrative costs to the year ended December 31, 2004, the most significant variances are related to the non-recurring costs related to the Equity Buyout in 2005 of $73.7 million. Other significant increases between the periods included increased costs in 2005 for share-based compensation resulting from the adoption of SFAS No. 123R in October 2005, increased personnel costs and higher legal and accounting expenses for the analysis of strategic alternatives considered in light of the sale of Addison.

Stock based and other compensation expense

We adopted the provisions of SFAS No. 123(R) on October 3, 2005 upon closing of the Equity Buyout. Upon closing of the IPO, Holdings merged with us and we assumed the EXCO Holdings 2005 Long-Term Incentive Plan, or the 2005 Long-Term Incentive Plan.

During 2006, we issued options to purchase approximately 3.6 million shares of common stock under our 2005 Long-Term Incentive Plan to our employees, which resulted in non-cash compensation expenses of $6.5 million to general and administrative expenses and $1.4 million of capital charges to our full cost pool.

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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 under the 2005 Long-Term Incentive Plan. The offset to this expense was to shareholder’s equity as additional paid-in capital.

Interest expense

During 2006, our consolidated debt, including our senior notes, increased to $2.1 billion from $811.8 million as of December 31, 2005. The December 31, 2005 debt included $350.0 million associated with an interim bank loan which was funded on October 2, 2005 to finance the Equity Buyout. This interim bank loan was paid in full upon completion of our IPO on February 14, 2006. Prior to October 2, 2005, our borrowings under the EXCO Resources credit agreement were not significant. The increase to our

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consolidated debt in 2006 reflects borrowings under the EXCO Resources credit agreement and the EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement to fund our 2006 acquisitions which occurred between February 14, 2006 and continued throughout the year. As a result, our 2006 interest expenses increased to $84.9 million from $46.1 million in non-GAAP combined 2005. On October 2, 2006, EPOP, a wholly-owned unrestricted subsidiary, closed on the acquisition of Winchester Energy. This acquisition was funded by a $650.0 million loan under the EPOP Senior Term Credit Agreement and $651.0 million of borrowings under the EPOP Revolving Credit Facility. EPOP’s debt is not guaranteed by EXCO. The following table presents our interest expense, including increases of $31.6 million during the fourth quarter of 2006 of interest and amortization of deferred financing costs for EPOP.

	Predecessor		Successor
		For the	For the
		275 day	90 day
		period from	period from			Year to	Year to
		January 1,	October 3,		Successor	year	year
	Year ended	2005 to	2005 to	Non-GAAP	Year ended	change	change
	December 31,	October 2,	December 31,	combined	December 31,	2004-	2005-
(in thousands)	2004	2005	2005	2005	2006	2005(a)	2006(a)
Interest expense:

71¤4% senior notes due 2011	$	28,638	$	24,615	$	7,269	$	31,884	$	29,275	$	3,246		$	(2,609	)
JP Morgan bridge loan	—		—		8,750		8,750		1,216		8,750			(7,534		)
EXCO Resources credit agreement	868		193		90		283		15,951		(585		)	15,668
Amortization and write-off of deferred financing costs on EXCO facilities	4,157		1,618		3,301		4,919		6,789		762			1,870
EPOP Revolving Credit Facility	—		—		—		—		11,937		—			11,937
EPOP Senior Term Credit Agreement	—		—		—		—		18,827		—			18,827
Amortization of deferred financing costs on EPOP loans	—		—		—		—		858		—			858
$50 million senior term loan	222		245		2		247		—		25			(247		)
Interest rate swaps	685		—		—		—		—		(685		)	—
Other interest expense	—		4		2		6		18		6			12
Total interest expense	$	34,570	$	26,675	$	19,414	$	46,089	$	84,871	$	11,519		$	38,782

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

Interest expense for non-GAAP combined 2005 was $46.1 million compared with $34.6 million in 2004, an increase of $11.5 million, which is primarily attributable to the interest on the interim bank loan.

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Income taxes

The following table presents a reconciliation of our income tax provision (benefit) for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006.

	Predecessor								Successor
					For the 275 day				For the 90 day
					period from				period from
	Year ended				January 1, 2005				October 3, 2005				Year ended
	December 31,				to				to				December 31,
(in thousands)	2004				October 2, 2005				December 31, 2005				2006
United States federal income taxes (benefit) at statutory rate of 35%		$	(5,120	)		$	(70,293	)		$	8,150			$	79,925
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				1,420
Non-deductible intercompany foreign interest expense		1,840				—				—				—
State taxes net of federal benefit		880				(6,665		)		1,095				8,704
Other		198				(741		)		468				(648		)
Total income tax provision		$	5,126			$	(63,698	)		$	7,321			$	89,401

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

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liability of $5.2 million as of December 31, 2005, which reflects the change in Ohio tax rates and the impacts of our stepped-up basis resulting from the Equity Buyout. 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 May 18, 2006, the Texas governor signed into law a Texas Margin tax that replaces the current franchise tax effective January 1, 2007. We had recorded the effect of the change in the tax rate on our existing deferred balances in the second quarter of 2006. Our deferred income tax related to the Texas Margin tax is $0.9 million at December 31, 2006.

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:

	275 day period
	ended
(unaudited, in thousands)	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.

Liquidity, capital resources and capital commitments

General

Most of our growth has resulted from acquisitions and our development and exploitation programs. 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 flow from operations, bank financing, cash received from the sale of oil and natural gas properties and the sale or issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. The EXCO Resources credit agreement, as amended, is a $1.25 billion facility with a $600.0 million borrowing base and a $500.0 million aggregate commitment. The EPOP Revolving Credit Agreement is a $750.0 million facility with a $750.0 million borrowing base and aggregate commitment. On April 1, 2007, the conforming borrowing base on the

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EPOP Revolving Credit Facility becomes $650.0 million. The EPOP Senior Term Credit Agreement is a $650.0 million facility. 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 agreements 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 of $215.3 million and additional borrowings of $65.0 million under EXCO’s credit agreement, were used as follows:

·$360.0 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;

·$158.8 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends 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

·$6.0 million to pay fees and expenses in connection with the IPO.

On February 21, 2006, we issued 3,615,200 additional shares of our 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 the EXCO Resources credit agreement.

On February 10, 2005, we sold Addison for $443.3 million after contractual adjustments. The net cash proceeds could 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 were 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.

Net cash provided by operating activities was $227.7 million for the twelve months ended December 31, 2006. At December 31, 2006, our cash and cash equivalents balance was $22.8 million, a decrease of $204.1 million from December 31, 2005 primarily as a result of the repayment of indebtedness incurred in connection with the Equity Buyout and our acquisition of TXOK in the first quarter of 2006.

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Acquisitions and capital expenditures

The following table presents our capital expenditures and entity acquisitions for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, non-GAAP combined 2005 and the year ended December 31, 2006.

	Predecessor						Successor
				For the 275 day period from			For the 90 day period from						Successor
(in thousands)	Year ended December 31, 2004			January 1, 2005 to October 2, 2005			October 3, 2005 to December 31, 2005			Non-GAAP combined 2005			Year ended December 31, 2006
Property acquisitions		$	88,347		$	103,222		$	—		$	103,222		$	221,103
Acquisition of North Coast Energy, Inc., net of cash acquired		215,133			—			—			—			—
Acquisition of TXOK Acquisition, Inc. preferred stock, net of cash acquired		—			—			—			—			126,489
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired, excluding debt and derivative financial instruments assumed		—			—			—			—			61,776
Acquisition of Winchester Energy, Ltd., net of cash acquired		—			—			—			—			1,094,910
Lease purchases		—			—			—			—			8,991
Development capital expenditures		36,742			39,900			13,194			53,094			194,312
Other		7,543			5,944			1,712			7,656			10,980
Total expenditures		$	347,765		$	149,066		$	14,906		$	163,972		$	1,718,561

On January 27, 2004, we completed the North Coast acquisition for $215.1 million. We funded the North Coast acquisition with the net proceeds from the $350.0 million offering of our senior notes.

In July and August 2004, we acquired natural gas properties located in Rusk County, Texas for a total purchase price of $36.9 million. We funded the acquisition with $32.0 million in borrowings under our credit agreement and from surplus cash. The properties acquired consisted of 32 producing natural gas wells, which we operate, and a 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, unproved drilling locations and related natural gas gathering systems in Centre and Clearfield Counties, Pennsylvania. The total purchase price, after contractual adjustments, was approximately $40.0 million and was funded with borrowings under our credit agreement.

On January 21, 2005, we acquired producing natural gas properties and unproved drilling locations located in the Minden Field in East Texas for a total purchase price of $17.7 million. We funded the acquisition with $13.3 million in borrowings under the EXCO Resources credit agreement and from surplus cash. 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. We funded these acquisitions with surplus cash. The properties acquired consisted of 744 producing natural gas wells, which we operate, and over 500 future drilling locations, of which 320 were classified as proved.

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

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During 2006, we completed the following acquisitions of oil and natural gas properties and undeveloped acreage, including the acquisition of Winchester, our largest acquisition to date. A summary of these acquisitions and their related values to oil and natural gas properties and gathering facilities, net of contractual adjustments is presented on the following table.

(in thousands)	Effective dates	Values allocated
Asset acquisitions:
West Texas properties from private producer	April 2006		$	84,925
East Texas properties from private producer	May 2006		50,904
Wyoming properties from private producer	August 2006		27,519
Appalachia properties from private producer	September 2006		49,426
Mid-Continent region and other	Various		8,329
Corporate acquisitions:
TXOK Acquisition, Inc.	February 2006		569,995
Power Gas Marketing & Transmission, Inc.	April 2006		125,966
Winchester Energy Company, Ltd.	October 2006		889,123
Total 2006 acquisitions			$	1,806,187

Details of the components of the purchase price and related allocation of the purchase price to the acquired assets and liabilities of our corporate acquisitions in 2006 are as follows:

(in thousands)	TXOK Acquisition, Inc.				Power Gas Marketing & Transmission, Inc.				Winchester Energy Company, Ltd.
Purchase price:
Carrying value of initial investment in TXOK Acquisition, Inc.		$	21,531			$	—			$	—
Acquisition of preferred stock, including accrued and unpaid dividends		158,750				—				—
Value of preferred stock redemption premium		4,667				—				—
Cash payments for acquired equity		—				63,615				1,095,028
Assumption of debt:
Term loan, plus accrued interest		202,755				—				—
Revolving credit facility plus accrued interest		309,701				13,096				—
Assumption of derivative financial instruments		—				38,098				—
Less cash acquired		(32,261		)		(1,839		)		(118		)
Net purchase price		$	665,143			$	112,970			$	1,094,910
Allocation of purchase price:
Oil and natural gas properties—proved		$	489,076			$	122,972			$	583,683
Oil and natural gas properties—unproved		60,840				421				154,291
Gathering and other fixed assets		20,079				2,573				151,149
Goodwill		64,887				21,249				163,935
Current and non-current assets		37,460				2,024				31,872
Deferred income taxes		26,783				(31,424		)		—
Accounts payable and other accrued expenses		(30,377		)		(3,318		)		(39,420		)
Asset retirement obligations		(8,203		)		(1,527		)		(7,793		)
Fair value of oil and natural gas derivatives		4,598				—				57,193
Total purchase price allocation		$	665,143			$	112,970			$	1,094,910

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On February 14, 2006, at closing of our IPO, we acquired the 89% of TXOK that we did not already own by redeeming their outstanding preferred stock and assuming TXOK’s outstanding debt of $512.5 million. The purchase price, net of cash acquired was $665.1 million.

In April and May 2006, we acquired producing properties and undeveloped acreage in West Texas and the Cotton Valley trend in East Texas. The purchase price of these assets was $135.8 million, after contractual adjustments, which was funded with indebtedness drawn under the EXCO Resources credit agreement.

On April 28, 2006, we closed an acquisition and acquired 100% of the common stock of PGMT for a net purchase price of $113.0 million. The purchase price included the assumption of $13.1 million of debt and $38.1 million outstanding derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under the EXCO Resources credit agreement, we paid the assumed debt and terminated the assumed commodity hedges. The acquisition was accounted for as a purchase in accordance with SFAS No. 141.

On August 4, 2006, we acquired producing properties and undeveloped acreage in Wyoming. The purchase price of these assets was $27.5 million, subject to post-closing contractual adjustments, and was funded by $20.0 million of indebtedness drawn under the EXCO Resources credit agreement and $7.5 million of available cash.

On September 19, 2006, we acquired producing properties and undeveloped acreage in West Virginia. The purchase price, after contractual adjustments, was $49.4 million.

On October 2, 2006, we closed our acquisition of Winchester and its affiliated entities from Progress Energy, Inc. for approximately $1.1 billion in cash, net of purchase price adjustments. The assets included producing and undeveloped acreage located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. The assets also include six gathering systems with 300 miles of pipe and a 54 mile pipeline system. The acquisition was financed with a $650.0 million loan under the EPOP Senior Term Credit Agreement and $651.0 million of borrowings under the EPOP Revolving Credit Facility. We formed a new subsidiary to purchase Winchester and that subsidiary became an unrestricted subsidiary as defined under the Indenture governing our senior notes and the EXCO Resources credit agreement. Concurrent with the closing of the purchase of Winchester, we contributed to EPOP all of our East Texas properties, with an estimated value of approximately $425.0 million, and related indebtedness of approximately $150.0 million. EPOP is not a guarantor of the EXCO Resources credit agreement nor does EXCO Resources guarantee the debt of EPOP.

On December 22, 2006, Vernon, our wholly-owned subsidiary, entered into the Vernon Purchase Agreement with Anadarko Petroleum Corporation and Anadarko Gathering Company to acquire the Vernon Assets for a purchase price of approximately $1.6 billion in cash, subject to certain purchase price adjustments. This acquisition is expected to close on or about March 30, 2007. On February 1, 2007, EXCO Resources entered into the Southern Gas Purchase Agreement with Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP to acquire the Southern Gas Assets for a purchase price of approximately $860.0 million in cash, subject to certain purchase price adjustments. This acquisition is expected to close on or about May 2, 2007. See “Item 1. Business—Significant subsequent events” for a description of our pending acquisitions of the Vernon Assets and the Southern Gas Assets from Anadarko.

To ensure that we have sufficient financing to complete the pending acquisitions from Anadarko, we received a revised commitment letter dated as of February 1, 2007, from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A. This commitment letter supersedes and replaces the commitment letter we received on December 22, 2006 in conjunction with our entering into the Vernon Purchase Agreement. The new commitment letter, as subsequently supplemented, provides for a senior secured revolving credit

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facility commitment in the amount of $1.8 billion and an undertaking to arrange a bridge loan facility in the amount of $1.1 billion if requested, or collectively the new credit facilities. If used to finance these acquisitions, the new credit facilities will contain customary representations, warranties and covenants, and the closing of the new credit facilities will be subject to the satisfaction of customary closing conditions. We are also pursuing other financing alternatives, including a proposed private placement of preferred stock. For a discussion of the proposed terms of the preferred stock, see “—Proposed recapitalization.”

During 2006, we sold oil and natural gas properties for proceeds totaling approximately $5.2 million. On January 5, 2007, we completed the sale of our oil and natural gas properties in the Wattenberg field in Colorado for $131.9 million. The proceeds from this sale were deposited with a qualified intermediary to effect a like-kind-exchange for Federal income tax purposes. The proceeds from this sale will be used to fund our pending acquisitions from Anadarko.

For 2007, we have budgeted approximately $314.7 million, excluding the pending acquisitions from Anadarko, for our development, exploitation and operational activities in the United States. We have also budgeted approximately $7.9 million in 2007 for our additional acquisition-related expenditures and approximately $2.0 for our information technology expenditures. In addition, we expect to add $80.4 million for projects associated with the pending acquisitions on a pro forma basis for 2007 (as if we acquired the pending acquisitions as of January 1, 2007). This additional capital brings our expected pro forma 2007 development, exploitation and operational program to $395.1 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. We also plan on selling non-strategic assets to assist with meeting our business objectives.

We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreements are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes, fluctuations in oil and natural gas prices and our ability to service the debt incurred in connection with the Winchester acquisition. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may affect our production in future periods. Our 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 2005 and 2006. 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 the 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.

71¤4% senior notes due January 15, 2011

On January 20, 2004, we issued $350.0 million principal amount of our senior notes pursuant to Rule 144A and Regulation S under 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 103.3% of the principal amount having the same terms and governed

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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.

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. If a change of control occurs, subject to certain conditions, we must offer holders of the senior notes an opportunity to sell us their senior notes at a purchase price of 101% of the principal amount of the senior notes, plus accrued and unpaid interest to the date of the purchase.

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. On May 4, 2006, PGMT became a guarantor of the senior notes. In conjunction with the formation of EXCO Partners and the Winchester acquisition on October 2, 2006, certain of our existing subsidiaries, specifically ROJO Pipeline, Inc. and those TXOK subsidiaries that hold direct or indirect interests in certain of our East Texas assets were released from their guaranties under the senior notes and are now deemed unrestricted subsidiaries thereunder. EXCO Resources also contributed all of its directly held East Texas assets to EXCO Partners. EXCO Partners and its general partners, which are also subsidiaries of EXCO Resources, and all of EXCO Partners’ subsidiaries are deemed unrestricted subsidiaries under the Indenture governing the senior notes and are not guarantors of the senior notes.

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Credit agreements

EXCO Resources credit agreement

On March 17, 2006, EXCO Resources, Inc. and certain of its subsidiaries entered into an amended and restated credit agreement, or the EXCO Resources credit agreement, with certain lenders, JPMorgan Chase Bank, N.A., as administrative agent, and J.P. Morgan Securities Inc., as sole bookrunner and lead arranger. This amendment established a new borrowing base of $750.0 million under the EXCO Resources credit agreement reflecting the addition of the assets of TXOK. TXOK and its subsidiaries became guarantors of the EXCO Resources  credit agreement. The amendment also provided for an extension of the EXCO Resources  credit agreement maturity date to December 31, 2010. The borrowing base is 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 the EXCO Resources 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 the EXCO Resources  credit agreement) to be greater than 3.5 to 1.0 at the end of each fiscal quarter.

Borrowings under the EXCO Resources credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our oil and natural gas properties including TXOK’s Oklahoma properties and North Coast. and their respective subsidiaries. Our borrowings are 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 was $300.0 million. This aggregate commitment increased to $500.0 million on May 11, 2006, was reduced to $400.0 million on October 2, 2006, and was increased back to $500.0 million on February 2, 2007.

At our option, borrowings under the EXCO Resources  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.

We typically elect to borrow funds using the LIBOR interest rate option described above. At December 31, 2005 and 2006, the six month LIBOR rates were 4.70% and 5.37% which would result in interest rates of approximately 5.95% and 6.62%, respectively, on any new indebtedness we may incur under the EXCO Resources credit agreement. At December 31, 2005 and 2006, we had $1,000 and $339.0 million, respectively, of outstanding indebtedness under the EXCO Resources credit agreement.

Additionally, the EXCO Resources credit agreement contains 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, 2006, we were in compliance with the covenants contained in the EXCO Resources credit agreement.

In connection with the contribution by EXCO Resources to EXCO Partners of EXCO Resources’ East Texas assets, EXCO Resources entered into an amendment to its credit agreement, or First

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Amendment. The First Amendment generally consents to and facilitates the contribution of the East Texas assets to EXCO Partners and provides that EXCO Partners, its subsidiaries and its general partners, all of which are subsidiaries of EXCO, are unrestricted subsidiaries under the EXCO Resources credit agreement, are not subject to the terms thereof and are no longer guarantors thereof. In addition, the assets contributed by EXCO Resources were released from the mortgages securing the credit agreement. Moreover, the assets of EXCO Partners and its subsidiaries have not been pledged under the EXCO Resources credit agreement and none of EXCO Partners or the other unrestricted subsidiaries have guaranteed the EXCO Resources credit agreement. The First Amendment also provides that the borrowing base under the EXCO Resources credit agreement shall be reduced to $600.0 million, with an aggregate commitment of $400.0 million (increased back to $500.0 million on February 2, 2007). The First Amendment also revises the covenants regarding the format of the financial statements to be delivered by EXCO Resources and consents to the contingent equity contribution obligation described below under “EXCO Resources Equity Contribution Agreement” subject to certain conditions. The First Amendment also amends certain covenants to address the relationship with EXCO Partners. Prior to any public offering by EXCO Partners, EXCO Resources may not permit the subsidiaries through which EXCO Resources owns the equity of EXCO Partners to incur any indebtedness or incur any lien. Prior to any public offering by EXCO Partners, EXCO Resources is required to own 100% of the equity of EXCO Partners. As of February 28, 2007, $407.0 million of indebtedness was outstanding under the EXCO Resources credit agreement and we had $91.5 million of availability under the EXCO Resources credit agreement. Our consolidated debt as of February 28, 2007, which includes EPOP’s debt, the EXCO Resources credit agreement and our senior notes, totals $2.2 billion. We are in compliance with the financial covenants of the EXCO Resources credit agreement as of December 31, 2006.

EPOP Revolving Credit Facility

To finance the Winchester acquisition and the $150.0 million payment to EXCO Resources for its East Texas assets, EXCO Partners’ wholly-owned subsidiary, EPOP, entered into the EPOP Revolving Credit Facility dated October 2, 2006, with a group of lenders led by JPMorgan Chase Bank, N.A. The EPOP Revolving Credit Facility has a face amount of $750.0 million with an initial borrowing base of $750.0 million and an initial conforming borrowing base of $650.0 million. The conforming borrowing base is the amount of borrowings upon which interest is computed on a lower premium to LIBOR than borrowings which exceed the conforming borrowing base. The borrowing base must be conforming by April 1, 2007. The EPOP Revolving Credit Facility is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries. We executed an amendment dated effective December 31, 2006, the EPOP Revolver First Amendment, which amends certain financial covenants contained in the EPOP Revolving Credit Facility. The EPOP Revolver First Amendment was sought due to our inability to comply with the leverage ratio and interest coverage ratio tests, as defined below, as of December 31, 2006. The original financial covenant ratios were negotiated assuming a more accelerated drilling program, which would have resulted in higher forecasted production. In addition, interest expense attributable to the EPOP Senior Term Credit Agreement was higher than originally forecast as the final negotiated interest rate exceeded our initial estimates when the covenants were being negotiated. Management and the lenders believe these revised covenants are more consistent with the actual operational activities contemplated at EPOP during 2007. As amended, the EPOP Revolving Credit Facility contains the following financial covenants:

·EPOP’s Consolidated Current Ratio (as defined) as of the end of any fiscal quarter ending after September 30, 2006 is not permitted to be less than 1.00 to 1.00. The EPOP Revolver First Amendment did not revise this covenant.

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·EPOP’s ratio of (A) Consolidated Funded Indebtedness (as defined) as of the end of a fiscal quarter to (B) Consolidated EBITDAX (as defined) shall not be greater than:

·6.00 to 1.00 (increased from 5.00 to 1.00) for the quarter ending December 31, 2006. For purposes of the December 31, 2006 Consolidated EBITDAX, the December 31, 2006 quarter shall be multiplied by four (4);

·5.50 to 1.00 (increased from 4.00 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX calculated using a defined trailing period multiplied by a fraction);

·5.50 to 1.00 (increased from 4.00 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);

·5.25 to 1.00 (increased from 4.00 to 1.00) for the quarter ended December 31, 2007, and

·4.00 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.

·EPOP will not permit its ratio of Consolidated EBITDAX to Consolidated Interest Expenses (as defined) to be less than:

·1.50 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2006 (Consolidated EBITDAX and Consolidated Interest Expenses for such quarter to be multiplied by four);

·1.75 to 1.00 (lowered from 2.50 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX and Consolidated Interest Expenses calculated using a defined trailing period multiplied by a fraction);

·1.75 to 1.00 (lowered from 2.50 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX and Consolidated Interest Expenses calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);

·2.00 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2007, and

·2.50 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.

·Finally, EPOP will not permit its ratio of net present value (calculated pursuant to the terms of the EPOP Revolving Credit Facility) to Consolidated Funding Indebtedness (as defined) to be less than (i) 1.15 to 1.00 (unchanged) determined as of December 31, 2006 or (ii)1.25 to 1.00 (unchanged) determined as of each succeeding June 30 and December 31.

The EPOP Revolving Credit Facility, as amended, contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Revolving Credit Facility matures four years from the closing date and has an initial drawn interest rate of LIBOR + 175 basis points (“bps”) and an undrawn commitment fee of 37.5 bps on the first $650.0 million of the EPOP Revolving Credit Facility. To the extent usage exceeds the initial conforming borrowing base, the EPOP Revolving Credit Facility will have an initial drawn interest rate of LIBOR + 250 bps and an undrawn commitment fee of 50 bps on the portion of the borrowings that exceed the initial conforming borrowing base. Finally, as a condition precedent to the funding of the EPOP Revolving Credit Facility, EPOP is required to hedge 75% of proved developed producing production through 2010. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP. The initial amount borrowed under this facility was $651.0 million at closing of the Winchester merger and the weighted

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average interest rate as of December 31, 2006, is 7.19%. As of February 28, 2007, $643.5 million was outstanding under this facility. We are in compliance with the financial covenants contained in the EPOP Revolving Credit Facility, as amended, as of December 31, 2006.

EPOP Senior Term Credit Agreement

In connection with the Winchester acquisition and the EXCO Resources asset contribution, EPOP entered into the EPOP Senior Term Credit Agreement, dated October 2, 2006 (as amended and restated as of October 13, 2006), with JPMorgan Chase Bank, N.A., as administrative agent. The aggregate principal amount is $650.0 million. The EPOP Senior Term Credit Agreement is secured by a second priority lien on all of the properties securing the EPOP Revolving Credit Facility, including 100% of the stock of subsidiaries, and is guaranteed by all existing and future subsidiaries. Financial covenants governing the EPOP Senior Term Credit Agreement include the same net present value ratio contained in the EPOP Revolving Credit Facility, a Leverage Ratio computed similarly to the covenant contained in the EPOP Revolving Credit Facility that cannot exceed 5.50 to 1.00 for applicable periods, and an Interest Coverage Ratio that cannot be less than 2.00 to 1.00 for any applicable period. The debt covenant tests for the EPOP Senior Term Credit Agreement begin with the quarter ended March 31, 2007. In addition, EPOP cannot make Capital Expenditures (as defined) exceeding $125.0 million in any fiscal year. The EPOP Senior Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The EPOP Senior Term Credit Agreement has an interest rate of LIBOR + 600 bps, with 25 bps step-ups on October 2, 2007 and January 2, 2008, and a total cap of LIBOR + 650 bps. Additionally, the EPOP Senior Term Credit Agreement matures five years from the closing date, requires payments of principle at 1% per year, with the balance of unpaid principle due at maturity. Upon an initial public offering by EXCO Partners, EPOP shall prepay the principal outstanding (plus accrued interest) under the EPOP Senior Term Credit Agreement at par plus an applicable premium. Commencing with the fiscal year ended December 31, 2007, and each year thereafter, EPOP must apply 100% of its Excess Cash Flow (as defined in the EPOP Senior Term Credit Agreement) toward prepayment at par of the EPOP Senior Term Credit Agreement. Such payments shall be made no later than the later of April 15 or five business days following delivery of the annual financial statements required under the EPOP Senior Term Credit Agreement. Any principal payment prior to the first anniversary, other than the mandatory cash flow and amortization prepayments described above, must be paid at 102% of the principal amount and after the first anniversary date to and including the second anniversary at 101% of par. Thereafter, any prepayments are at par. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP.

EXCO Resources Equity Contribution Agreement

In connection with the arrangement of the EPOP Senior Term Credit Agreement, the lenders required EXCO Resources to enter into an Equity Contribution Agreement, dated October 2, 2006, and amended and restated on October 4, 2006 and October 13, 2006. The Equity Contribution Agreement generally provides that on the date 18 months from October 2, 2006 (Equity Contribution Date), EXCO Resources will make a cash common equity contribution to EPOP in an amount equal to the lesser of (i) $150.0 million or (ii) the aggregate amount then outstanding under the EPOP Senior Term Credit Agreement; provided, that in no event can this obligation exceed during the term of the Equity Contribution Agreement the maximum amount that EXCO Resources could contribute under the terms of the Indenture governing its senior notes. Alternatively, EXCO Resources can cause EXCO Partners to make the equity contribution to EPOP in the amount of $150.0 million to satisfy this obligation. In lieu of requiring the equity contribution, the holders of at least 662¤3% of the aggregate principal amount of the

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loans outstanding under the EPOP Senior Term Credit Agreement can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become “Restricted Subsidiaries” under the EXCO Resources credit agreement and require EXCO Resources to provide, and cause all then restricted subsidiaries as defined and constituted under the EXCO Resources credit agreement to provide, guarantees and collateral in respect of the EPOP Senior Term Credit Agreement on terms substantially consistent with the guarantees and collateral provided under the EXCO Resources credit agreement. This requirement is subject to compliance with the credit agreement. Any cash so contributed shall be used by EPOP to prepay loans under the EPOP Senior Term Credit Agreement. EXCO Resources is prohibited from making restricted payments (as defined in the Indenture) that would constitute a utilization of the Indenture restricted payment baskets, other than restricted payments not to exceed $5.0 million In addition, EXCO Resources has covenanted to redeem or defease its senior notes if the Indenture would not permit the equity contribution or the lenders’ election to cause EXCO Resources to designate EPOP and its subsidiaries as restricted subsidiaries under the EXCO Resources credit agreement (subject to certain restrictions on the indebtedness that may be incurred for any such redemption or defeasance if the election to cause the designation of EPOP as a restricted subsidiary is chosen). The Equity Contribution Agreement will terminate upon payment in full of the EPOP Senior Term Credit Agreement.

Proposed recapitalization

If we consummate the proposed private placement of up to $2.0 billion of preferred stock, we plan to contribute $1.75 billion of the net proceeds to EPOP, of which approximately $1.6 billion will be used to purchase the Vernon Assets and approximately $150.0 million will be used to refinance EPOP’s debt agreements. We expect the proposed refinancing of EPOP’s debt agreements to include a new revolving credit facility, or the Proposed EPOP Revolving Credit Facility, and a new term loan, or the Proposed EPOP Term Loan, each with JPMorgan Chase Bank, N.A., as administrative agent. We anticipate that the EPOP Senior Term Credit Agreement will be paid in full and terminated in connection with the proposed recapitalization. We plan to use the remaining $250.0 million of the net proceeds of the preferred stock to restructure and repay indebtedness under the EXCO Resources credit agreement and pay fees and expenses associated with the offering.

We are in discussion with our lenders concerning all of our credit agreements. There is no assurance that any of these transactions will be completed. Even if the proposed recapitalization is completed, it may involve terms and conditions other than those provided in this annual report.

Proposed private placement of preferred stock

On February 14, 2007, we issued a press release pursuant to Rule 135c of the Securities Act of 1933 to announce a proposed offering of up to $2.0 billion in preferred stock through the private placement of up to $400.0 million of 6% Cumulative Convertible Perpetual Preferred Stock, or the 6% Convertible Preferred Stock, and $1.6 billion of 11% Cumulative Preferred Stock, or the 11% Preferred Stock, to accredited institutional investors pursuant to Regulation D of the Securities Act of 1933. We have not entered into definitive agreements with potential investors to issue any preferred stock. As a result, we may never issue any preferred stock. In addition, any preferred stock that we ultimately issue may contain terms different from those provided in this annual report.

The securities proposed to be offered in the private placement will not been registered under the Securities Act of 1933 or any state securities laws, and unless so registered may not be offered or sold in the United States, except pursuant to an exemption from, or in a transaction subject to, the registration requirements of the Securities Act of 1933 and applicable state securities laws. This annual report does not constitute an offer to sell, or the solicitation of an offer to buy, the securities nor shall there be any sale of the securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction.

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The 6% Convertible Preferred Stock will be convertible into our common stock at a price of $20.00 per share, as may be adjusted in accordance with the terms of the 6% Convertible Preferred Stock, and we may force the conversion of the 6% Convertible Preferred Stock at any time if our common stock trades for 20 days within a period of 30 consecutive days at a price, subject to adjustment, above $35.00 per share in the 24 months after issuance, $30.00 per share thereafter through the 48th month after issuance and $25.00 per share at any time thereafter. Upon the occurrence of a change of control, holders of the 6% Convertible Preferred Stock may require us to repurchase their shares for cash or shares of common stock at the liquidation preference plus accumulated dividends. Holders of the 6% Convertible Preferred Stock will  have a right of first offer with respect to our subsequent issuance of shares of common stock at a price per share less than the then-effective conversion price, subject to customary exceptions.

The 11% Preferred Stock will automatically convert into an equal number of shares of 6% Convertible Preferred Stock upon shareholder approval as required by New York Stock Exchange rules. We expect to hold a shareholders meeting in the third quarter of 2007. If the 11% Preferred Stock has not been converted into 6% Convertible Preferred Stock within 180 days of issuance, the annual dividend rate will increase by 0.50% per quarter (up to a maximum rate of 18% per annum) until the shares of 11% Preferred Stock have been converted into 6% Convertible Preferred Stock. The 11% Preferred Stock must be redeemed for cash at 125% of the liquidation preference plus accumulated dividends following the maturity of our senior notes and is otherwise redeemable at such price at our option at any time. Upon the occurrence of a change of control, holders of the 11% Preferred Stock may require us to repurchase their shares for cash at 101% of the liquidation preference plus accumulated dividends. In the event that any person or group of persons consummates a tender offer to acquire more than 50% of our total voting power at a price per common share equivalent of greater than the then effective conversion price of the 6% Convertible Preferred Stock, then, within 30 days after expiration of the change of control offer made to the holders of the 11% Preferred Stock following such tender offer, we must issue to each holder of 11% Preferred Stock, for all such shares of 11% Preferred Stock so held, the number of additional shares of 11% Preferred Stock having a liquidation preference equal to the product of (i) such number of shares of 11% Preferred Stock so held multiplied by (ii) the remainder of the tender offer price minus the then effective conversion price of the 6% Convertible Preferred Stock multiplied by (iii) the quotient of $1,000 divided by the then effective conversion price of the 6% Convertible Preferred Stock. No shares will be issued to any holder that requires us to purchase any of its 11% Preferred Stock pursuant to a change of control offer.

The holders of 11% Preferred Stock will have a class vote to approve (i) any sale or disposition of all or substantially all of our assets to a third party or (ii) any merger or consolidation of EXCO in which either the holders of our voting stock prior to the merger or consolidation do not beneficially own more than 50% of the voting stock of the continuing or surviving corporation immediately after such merger or consolidation or individuals not nominated by our current directors (or their successors nominated by the remaining directors) constitute two-thirds of our board of directors immediately following the merger or consolidation, unless each holder of the 11% Preferred Stock receives in the asset sale or the merger or consolidation the consideration it would have received had it been able to convert its 11% Preferred Stock into 6% Convertible Preferred Stock and the 6% Convertible Preferred Stock into our common stock immediately prior to the merger or consolidation. After 180 days from the date of issuance, holders of the 11% Preferred Stock will have a right of first offer with respect to our subsequent debt or equity issuances, subject to customary exceptions.

We must pay dividends quarterly either in cash at 6% per annum or the dividend due shall be added to the liquidation preference (thereby increasing the amount due at liquidation or upon conversion) at a rate equal to 8% per annum. After the sixth anniversary of the issue date, the dividend rate on the 6% Convertible Preferred Stock will increase to 8.0% per annum and dividends will be payable only in cash. Dividends on the 11% Preferred Stock are only payable in cash.

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Holders of the 6% Convertible Preferred Stock and the 11% Preferred Stock will have certain director appointment rights. We will be obligated to register for resale under the Securities Act of 1933 the shares of common stock issuable in connection with the 6% Convertible Preferred Stock.

We will use the net proceeds from the sale of the preferred stock to finance our previously announced acquisition from Anadarko of oil and natural gas properties in the Vernon and Ansley Fields in Louisiana and to repay a portion of our outstanding indebtedness and indebtedness of our subsidiary, EPOP.

Proposed EPOP Revolving Credit Facility

The Proposed EPOP Revolving Credit Facility is expected to have a face amount of $1.0 billion with an initial borrowing base of $1.3 billion. The aggregate outstanding amount of the Proposed EPOP Term Loan will be deemed usage of the borrowing base. The borrowing base will be redetermined on a semi-annual basis, with EPOP and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each year, beginning October 1, 2007. The Proposed EPOP Revolving Credit Facility will be secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EPOP. We expect the Proposed EPOP Revolving Credit Facility to contain financial covenants similar to those contained in the current EXCO Resources credit agreement, including:

·a Consolidated Current Ratio;

·a ratio of (A) Consolidated Funded Indebtedness as of the end of a fiscal quarter to (B) Consolidated EBITDAX; and

·a ratio of Consolidated EBITDAX to Consolidated Interest Expense.

The Proposed EPOP Revolving Credit Facility will contain representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The Proposed EPOP Revolving Credit Facility matures five years from the closing date and has an initial drawn interest rate of LIBOR + 150 basis points (“bps”) and an undrawn commitment fee of 37.5 bps.

The initial amount borrowed under this facility is expected to be $769.0 million at the closing of the acquisition of the Vernon Assets.

Proposed EPOP Term Loan

We expect that the Proposed EPOP Term Loan will have an aggregate principal amount of $300.0 million to be available in a single drawing on the closing date. The Proposed EPOP Term Loan will be secured by a first priority lien on all of the properties securing the Proposed EPOP Revolving Credit Facility, including 100% of the stock of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EPOP. We expect the financial covenants governing the Proposed EPOP Term Loan to be substantially similar to those contained in the Proposed EPOP Revolving Credit Facility. We expect the Proposed EPOP Term Loan to contain representations, warranties, covenants, events of default and indemnities customary for agreements of this type. We expect the Proposed EPOP Term Loan to have an interest rate of LIBOR + 150 bps. Additionally, the Proposed EPOP Term Loan will mature six years from the closing date, require payments of principal at 1% per year, with the balance of unpaid principal due at maturity. We anticipate that any principal payment prior to the first anniversary, other than the mandatory amortization prepayments described above, must be paid at par.

We expect to draw down the full $300.0 million at the closing of the acquisition of the Vernon Assets.

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Proposed EXCO Resources credit agreement

In connection with the proposed private placement of preferred stock, we plan to refinance the existing EXCO Resources credit agreement with a new EXCO Resources credit agreement, the Proposed EXCO Resources credit agreement, having a face amount of $750.0 million and a new borrowing base of $1.0 billion. The aggregate outstanding amount of a new term loan, or the Proposed EXCO Resources Term Loan, will be deemed usage of the borrowing base. The borrowing base will be redetermined on a semi-annual basis, with EXCO Resources and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each year, beginning October 1, 2007. Borrowings under the Proposed EXCO Resources credit agreement will be collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. We anticipate that the financial covenants under the Proposed EXCO Resources credit agreement will be similar to those contained in the current EXCO Resources credit agreement, including:

·a Consolidated Current Ratio;

·a ratio of (A) Consolidated Funded Indebtedness as of the end of a fiscal quarter to (B) Consolidated EBITDAX; and

·a ratio of Consolidated EBITDAX to Consolidated Interest Expense.

The Proposed EXCO Resources credit agreement will contain representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The Proposed EXCO Resources credit agreement matures five years from the closing date and has an initial drawn interest rate of LIBOR + 125 basis points (“bps”) and an undrawn commitment fee of 30.0 bps

Additionally, we expect the Proposed EXCO Resources credit agreement to 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.

The initial amount borrowed under this facility is expected to be $482.0 million at the closing of the acquisition of the Southern Gas Assets.

Proposed EXCO Resources Term Loan

We expect that the Proposed EXCO Resources Term Loan will have an aggregate principal amount of $250.0 million to be available in a single drawing on the closing date. The Proposed EXCO Resources Term Loan will be secured by a first priority lien on all of the properties securing the Proposed EXCO Resources credit agreement. We expect the financial covenants governing the Proposed EXCO Resources Term Loan to be identical to those contained in the Proposed EXCO Resources credit agreement. We expect the Proposed EXCO Resources Term Loan to contain representations, warranties, covenants, events of default and indemnities customary for agreements of this type. We expect the Proposed EXCO Resources Term Loan to have an interest rate of LIBOR + 150 bps. Additionally, the Proposed EXCO Resources Term Loan will mature six years from the closing date, require payments of principal at 1% per year, with the balance of unpaid principal due at maturity. We anticipate that any principal payment prior to the first anniversary, other than the mandatory amortization prepayments described above, must be paid at par.

We expect to draw down the full $250.0 million of the Proposed EXCO Resources Term Loan at the closing of the acquisition of the Southern Gas Assets.

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Derivative financial instruments

We use derivative financial instruments to manage exposure to commodity prices 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.

Our production is generally sold at prevailing market prices. However, we periodically enter into derivative financial instrument contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.

Our objective in entering into derivative financial instrument contracts is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. During the year ended December 31, 2005, we closed several of our derivative financial instrument contracts upon the payment of $67.6 million to our counterparties, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production. We also entered into new derivative financial instrument contracts at higher prices. As of December 31, 2006, we had contracts in place for the volumes and prices shown in the table below, which includes contracts we entered into or assumed in connection with the acquisition of Winchester.

EXCO Resources, Inc. hedge positions as of December 31, 2006

	Swaps
			Weighted					Weighted
			average					average
	NYMEX gas		contract			NYMEX oil		contract
	volume—		price per			volume—		price per
(in thousands, except average contract prices)	Mmbtus		Mmbtu			Bbls		Bbl
Q1 2007		11,880		$	9.30		182		$	70.03
Q2 2007		11,934		8.42			183		69.74
Q3 2007		11,988		8.46			185		69.40
Q4 2007		11,988		8.74			185		68.97
2008		43,140		8.63			327		62.67
2009		25,705		8.02			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			—		—

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Pro forma including the acquisitions of the Vernon Assets and the Southern Gas Assets from Anadarko as of December 31, 2006

	Swaps
			Weighted					Weighted
			average					average
	NYMEX gas		contract			NYMEX oil		contract
	volume—		price per			volume—		price per
(in thousands, except average contract prices)	Mmbtus		Mmbtu			Bbls		Bbl
Q1 2007		28,610		$	8.18		359		$	62.27
Q2 2007		31,044		7.78			456		61.53
Q3 2007		30,388		7.83			369		63.46
Q4 2007		30,388		8.07			369		63.83
2008		99,870		8.36			1,059		60.55
2009		73,155		7.89			850		60.10
2010		6,985		6.63			108		59.85
2011		1,825		4.51			—		—
2012		1,830		4.51			—		—
2013		1,825		4.51			—		—

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at December 31, 2006:

	Payments due by period
(in thousands)	Less than one year			One to three years			Three to five years		More than five years			Total
71¤4% senior notes(1)		$	—		$	—	$	444,720		$	—	$	444,720
EXCO Resources credit agreement(2)		—			—		339,000			—		339,000
EPOP Revolving Credit Facility(3)		—			—		643,500			—		643,500
EPOP Senior Term Credit Agreement(4)		6,500			12,806		630,694			—		650,000
Operating leases.		5,834			9,877		6,238			2,236		24,185
Deferred compensation(5)		600			1,200		1,200			—		3,000
Drilling/work commitments		40,960			37,616		—			—		78,576
Total contractual cash obligations		$	53,894		$	61,499	$	2,065,352		$	2,236	$	2,182,981

(1)Our senior notes are due on January 15, 2011. The annual interest obligation is $32.2 million.

(2)The EXCO Resources credit agreement was amended and restated on March 17, 2006 and matures on December 31, 2010.

(3)The EPOP Revolving Credit Facility matures on October 2, 2010.

(4)The EPOP Senior Term Credit Agreement matures on October 2, 2011.

(5)Deferred compensation represents a Rabbi Trust for an officer of one of our subsidiaries.  This obligation vests 20% each year and will fully vest on December 31, 2011.

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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 use of derivative financial instruments activities as of December 31, 2006:

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl			Fair value at December 31, 2006
Natural Gas:
Swaps:
2007		47,790		$	8.73		$	82,659
2008		43,140		8.63			23,237
2009		25,705		8.02			3,943
2010		6,985		6.63			(4,664		)
2011		1,825		4.51			(3,673		)
2012		1,830		4.51			(2,929		)
2013		1,825		4.51			(2,639		)
Total Natural Gas		129,100					95,934
Oil:
Swaps:
2007		734		69.52			3,234
2008		327		62.67			(1,455		)
2009		120		60.80			(670		)
2010		108		59.85			(605		)
Total Oil		1,289					504
Total Oil and Natural Gas							$	96,438

At December 31, 2006, the average forward spot oil prices per Bbl for calendar 2007 and for 2008 were $65.02 and $67.50, respectively, and the average forward spot natural gas prices per Mmbtu for calendar 2007 and for 2008 were $6.97 and $8.06, respectively.

Realized gains or losses from the settlement of derivative financial instruments are recorded in our financial statements as increases or decreases in use of derivative financial instruments activities. For

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example, using the oil swaps in place at December 31, 2006, if the settlement price exceeded the actual weighted average strike price of $69.52, then a reduction in use of derivative financial instruments activities revenue would have been recorded for the difference between the settlement price and $69.52 multiplied by the hedged volume of 733,750 Bbls. Conversely, if the settlement price was less than $69.52, then an increase in use of derivative financial instruments activities revenue would have been recorded for the difference between the settlement price and $69.52 multiplied by the hedged volume of 733,750 Bbls. For example, for a hedged volume of 733,750 Bbls, if the settlement price was $70.52, then use of derivative financial instruments activities revenue would have decreased by $0.7 million. Conversely, if the settlement price was $68.52, use of derivative financial instruments activities revenue would have increased by $0.7 million.

Interest rate risk

At December 31, 2006, our exposure to interest rate changes related primarily to borrowings under our credit agreements and interest earned on our short-term investments. The interest rate is fixed at 71¤4% on the $444.7 million in senior notes we have outstanding. As of December 31, 2006, we were not using any derivatives to manage interest rate risk. Interest is payable on borrowings under our credit agreements 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, 2006, we had $1.6 billion in outstanding borrowings under our credit agreements. On February 14, 2006, we increased our borrowings under the EXCO Resources credit agreement 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 the EXCO Resources credit agreement and used these borrowings to repay in full the TXOK credit facility. This increased the outstanding balance under the EXCO Resources credit agreement to $143.5 million. As of March 1, 2007, the outstanding balance under our credit agreement was $407.0 million. The interest rate under the EXCO Resources credit agreement as of that date was 6.67%. A 1% change in interest rates based on the borrowings as of March 1, 2007 would result in an increase or decrease in our interest costs of $4.1 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

The EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement, both of which we entered into in connection with the Winchester acquisition on October 2, 2006, bear interest based on floating rates. As of December 31, 2006, we had $643.5 million and $650.0 million in outstanding borrowings under the EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement, respectively. As of March 1, 2007, our outstanding balance under the EPOP Revolving Credit Facility was $643.5 million and under the EPOP Senior Term Credit Agreement was $650.0 million. As of that date, the interest rate under the EPOP Revolving Credit Facility averaged 7.19% and under the EPOP Senior Term Credit Agreement averaged 11.44%. A 1% change in interest rates based on the borrowings as of March 1, 2007 under the EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement would result in an increase or decrease in interest costs of $6.4 million and $6.5 million per year, respectively.

The interest we pay on these borrowings is set periodically based upon market rates.

Marketable securities risk

On January 5, 2007, we deposited $129.6 million of proceeds, net of contractual adjustments, with a qualified intermediary to effect a like-kind exchange under Section 1031 of the Internal Revenue Code from the sale of our Wattenberg properties. These proceeds are invested in overnight money market funds.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EXCO RESOURCES, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Contents

Reports of Independent Registered Public Accounting Firms	87
Consolidated balance sheets at December 31, 2005 and 2006	91
Consolidated statements of operations for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006	93
Consolidated statements of cash flows for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006	94
Consolidated statements of changes in shareholders’ equity for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006	95
Consolidated statements of comprehensive income (loss) for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006	96
Notes to consolidated financial statements	97

Financial information for the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, represents predecessor (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.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
EXCO Resources, Inc.:

We have audited the accompanying consolidated balance sheet of EXCO Resources, Inc. and subsidiaries (the Company) as of December 31, 2006, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for the year ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EXCO Resources, Inc. and subsidiaries as of December 31, 2006, and the results of their operations and their cash flows for the year ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

	KPMG LLP
Dallas, Texas
March 16, 2007

87

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of shareholders’ 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 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.

As discussed in Note 1 to the consolidated financial statements, all financial information presented reflects the consolidated financial position and results of operations of EXCO Resources, Inc. and its former parent, EXCO Holdings Inc. in order to account for transactions between entities under common control as required by Statement of Financial Accounting Standards No. 141, “Business Combinations”.

/s/ PRICEWATERHOUSECOOPERS LLP

Dallas, Texas

May 15, 2006, except for Note 21,

as to which the date is March 15, 2007

88

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated statements of operations, of shareholders’ 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 (Predecessor Company) for the period from January 1, 2005 to October 2, 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.

As discussed in Note 1 to the consolidated financial statements, all financial information presented reflects the consolidated financial position and results of operations of EXCO Resources, Inc. and its former parent, EXCO Holdings Inc. in order to account for transactions between entities under common control as required by Statement of Financial Accounting Standards No. 141, “Business Combinations”.

/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
May 15, 2006, except for Note 21,
as to which the date is March 15, 2007

89

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of shareholders’ 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 (Predecessor Company) for the year ended December 31, 2004 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, except for Note 21,
as to which the date is March 15, 2007

90

EXCO Resources, Inc.
Consolidated balance sheets

	December 31,
(in thousands)	2005			2006
Assets
Current assets:
Cash and cash equivalents	$	226,953		$	22,822
Accounts receivable:
Oil and natural gas sales	36,895			84,078
Joint interest	1,081			14,902
Canadian income taxes receivable	18,483			—
Interest and other	12,189			12,199
Related party	2,621			—
Deferred income taxes	29,968			—
Deferred costs of initial public offering	3,380			—
Oil and natural gas derivatives	—			91,614
Other	10,955			11,095
Total current assets	342,525			236,710
Investment in TXOK Acquisition, Inc.	20,837			—
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	53,121			297,919
Proved developed and undeveloped oil and natural gas properties	873,595			2,492,863
Accumulated depreciation, depletion and amortization	(13,281		)	(142,591		)
Oil and natural gas properties, net	913,435			2,648,191
Gas gathering assets	27,028			203,537
Accumulated depreciation, depletion and amortization	(333		)	(4,181		)
Gas gathering assets, net	26,695			199,356
Office and field equipment, net	6,576			14,805
Advance on Vernon Assets	—			80,000
Oil and natural gas derivatives	—			41,469
Deferred financing costs, net	—			15,929
Goodwill	220,006			470,077
Other assets	419			520
Total assets	$	1,530,493		$	3,707,057

See accompanying notes.

91

EXCO Resources, Inc.
Consolidated balance sheets

	December 31,
(in thousands, except per share data)	2005		2006
Liabilities and shareholders’ equity
Current liabilities:
Interim bank loan	$	350,000	$	—
Accounts payable and accrued liabilities	25,182		54,402
Accrued interest payable	23,779		36,000
Revenues and royalties payable	11,266		53,994
Income taxes payable	901		89
Deferred income taxes payable	—		32,639
Current portion of asset retirement obligations	1,408		1,579
Current portion of long-term debt	—		6,500
Oil and natural gas derivatives	53,189		5,721
Total current liabilities	465,725		190,924
Long-term debt, net of current portion	461,802		2,081,653
Asset retirement obligations and other long-term liabilities	15,766		57,570
Deferred income taxes	134,912		166,136
Oil and natural gas derivatives	81,406		30,924
Commitments and contingencies	—		—
Shareholders’ equity:
Preferred stock, $.001 par value; Authorized shares—10,000; none issued	—		—
Common stock, $.001 par value; Authorized shares—250,000;
Issued and outstanding shares—50,000 at December 31, 2005 and 104,162 at December 31, 2006	50		104
Additional paid-in capital	354,482		1,024,442
Retained earnings	16,350		155,304
Total shareholders’ equity	370,882		1,179,850
Total liabilities and shareholders’ equity	$	1,530,493	$	3,707,057

See accompanying notes.

92

EXCO Resources, Inc.
Consolidated statements of operations

	Predecessor								Successor
					For the 275 day				For the 90 day
					period from				period from
					January 1, 2005				October 3, 2005
	Year ended				to				to				Year ended
(in thousands, except per share data)	December 31, 2004				October 2, 2005				December 31, 2005				December 31, 2006
Revenues and other income:
Oil and natural gas		$	141,993			$	132,821			$	70,061			$	355,780
Gains (losses) on derivative financial instruments		(50,343		)		(177,253		)		(256		)		198,664
Other income		1,184				7,096				2,374				5,005
Total revenues and other income		92,834				(37,336		)		72,179				559,449
Cost and expenses:
Oil and natural gas production		28,256				22,157				8,949				68,874
Depreciation, depletion and amortization		28,519				24,687				14,071				135,722
Accretion of discount on asset retirement obligations		800				617				226				2,014
General and administrative (includes $44.1 million, $2.2 million, and $6.5 million of non-cash compensation expense for the period from January 1, 2005 to October 2, 2005, the period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006, respectively)		15,466				89,442				6,375				41,206
Interest		34,570				26,675				19,414				84,871
Total cost and expenses		107,611				163,578				49,035				332,687
Equity in net income of TXOK Acquisition, Inc.		—				—				837				1,593
Income (loss) before income taxes		(14,777		)		(200,914		)		23,981				228,355
Income tax expense (benefit)		5,126				(63,698		)		7,631				89,401
Income (loss) before discontinued operations		(19,903		)		(137,216		)		16,350				138,954
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 from discontinued operations		25,916				122,032				—				—
Net income (loss)		$	6,013			$	(15,184	)		$	16,350			$	138,954
Earnings per share:
Basic
Net income (loss) from continuing operations		$	(0.17	)		$	(1.18	)		$	0.35			$	1.44
Net income (loss)		$	0.05			$	(0.13	)		$	0.35			$	1.44
Weighted average common shares outstanding		115,947				116,504				47,222				96,727
Diluted
Net income (loss) from continuing operations		$	(0.17	)		$	(1.18	)		$	0.35			$	1.41
Net income (loss)		$	0.05			$	(0.13	)		$	0.35			$	1.41
Weighted average common and common equivalent shares outstanding		115,947				116,504				47,222				98,453

93

EXCO Resources, Inc.
Consolidated statements of cash flows

	Predecessor								Successor
					For the 275 day				For the 90 day
					period from				period from
					January 1, 2005				October 3, 2005
	Year ended				to				to				Year ended
(in thousands)	December 31, 2004				October 2, 2005				December 31, 2005				December 31, 2006
Operating Activities:
Net income (loss)		$	6,013			$	(15,184	)		$	16,350			$	138,954
Income from discontinued operations		(25,916		)		(122,032		)		—				—
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Equity in net income of TXOK Acquisition, Inc.		—				—				(837		)		(1,593		)
Gain on sale of other assets		—				(373		)		—				(89		)
Depreciation, depletion and amortization		28,519				24,687				14,071				135,722
Stock option compensation expense		—				44,092				2,207				6,532
Accretion of discount on asset retirement obligations		800				617				226				2,014
Non-cash change in fair value of derivatives		24,260				114,410				(21,954		)		(169,241		)
Deferred income taxes		3,681				(59,467		)		15,964				89,401
Amortization of deferred financing costs, premium on 71¤4% senior notes due 2011 and discount on long-term debt		3,859				1,320				2,381				4,733
Proceeds from sale of Enron claim		4,750				—				—				—
(Gains) losses from sales of marketable securities		(14		)		3				—				—
Changes in working capital, net of acquisition effects:
Accounts receivable		(2,487		)		(24,512		)		(2,533		)		24,038
Other current assets		(1,307		)		(369		)		1,094				(3,727		)
Accounts payable and other current liabilities		21,599				25,458				(18,792		)		915
Net cash provided by (used in) operating activities of discontinued operations		54,771				(69,772		)		—				—
Net cash provided by (used in) operating activities		118,528				(81,122		)		8,177				227,659
Investing Activities:
Investment in TXOK Acquisition, Inc.		—				—				(20,000		)		—
Acquisition of North Coast Energy, Inc., less cash acquired		(215,133		)		—				—				—
Additions to oil and natural gas properties, gathering systems and equipment		(139,521		)		(151,144		)		(13,207		)		(434,166		)
Proceeds from disposition of property and equipment		51,865				46,010				(393		)		5,824
Payment to TXOK Acquisition, Inc. for preferred stock redemptions		—				—				—				(158,750		)
Cash acquired in acquisition of TXOK Acquisition, Inc.		—				—				—				32,261
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired		—				—				—				(61,776		)
Acquisition of Winchester Energy Company, Ltd., net of cash acquired		—				—				—				(1,094,910		)
Advance payment on Vernon Assets		—				—				—				(80,000		)
Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415		—				443,397				—				—
Advances/investments with affiliates		—				—				20,000				—
Proceeds from sales of marketable securities		1,296				59				—				—
Net cash used in investing activities of discontinued operations		(79,983		)		(442		)		—				—
Other investing activities		—				—				263				—
Net cash provided by (used in) investing activities		(381,476		)		337,880				(13,337		)		(1,791,517		)
Financing Activities:
Proceeds from long-term debt		546,350				41,300				9,999				1,884,250
Payments on interim bank loan		—				—				—				(350,000		)
Payments on long-term debt		(158,070		)		(148,247		)		(15,279		)		(776,849		)
Proceeds from issuance of common stock, net of underwriters’ commissions and initial public offering costs		—				—				—				657,381
Principal and interest on notes receivable-employees		256				311				1,262				—
Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition		—				—				—				(38,098		)
Deferred financing costs and other		(13,431		)		—				—				(16,957		)
Net cash provided by (used in) financing activities of discontinued operations		(91,397		)		59,601				—				—
Net cash provided by (used in) financing activities		283,708				(47,035		)		(4,018		)		1,359,727
Net increase (decrease) in cash		20,760				209,723				(9,178		)		(204,131		)
Effect of exchange rates on cash and cash equivalents		(1,685		)		—				—				—
Cash at beginning of period		7,333				26,408				236,131				226,953
Cash at end of period including cash of discontinued operations		26,408				236,131				226,953				22,822
Cash of discontinued operations at end of period		10,401				—				—				—
Cash at end of period		$	16,007			$	236,131			$	226,953			$	22,822
Supplemental Cash Flow Information:
Interest paid		$	17,102			$	33,099			$	124			$	65,378
Income taxes paid		$	—			$	38,213			$	15,500			$	—
Value of shares issued in connection with redemption of TXOK Acquisition, Inc. preferred stock		$	—			$	—			$	—			$	4,667
Long-term debt assumed in TXOK Acquisition, Inc. acquisition		$	—			$	—			$	—			$	508,750
Long-term debt assumed in Power Gas Marketing & Transmission, Inc. acquisition		$	—			$	—			$	—			$	13,096
Supplemental non-cash investing:
Capitalized stock compensation		$	—			$	—			$	1,034			$	1,401

See accompanying notes.

94

EXCO Resources, Inc.
Consolidated statements of changes in shareholders’ equity

							Notes						Accumulated
				Additional			receivable—			Retained			other			Total
	Common Stock			paid-in			officers and			earnings			comprehensive			shareholders’
(in thousands)	Shares	Amount		capital			employees			(deficit)			income (loss)			equity
Predecessor:
Balance, December 31, 2003	127,873		$ 128		$   173,804			$ (1,829	)		$    4,146			$   7,646			$   183,895
Principal and interest payable	—		—		—			256			—			—			256
Foreign currency translation adjustments	—		—		—			—			—			13,704			13,704
Equity investments	—		—		—			—			—			17			17
Net income	—		—		—			—			6,013			—			6,013
Balance, December 31, 2004	127,873		128		173,804			(1,573	)		10,159			21,367			203,885
Foreign currency translation adjustments	—		—		—			—			—			(21,384	)		(21,384	)
Unrealized gain on equity investments	—		—		—			—			—			17			17
Principal and interest payable	—		—		—			311			—			—			311
Net loss	—		—		—			—			(15,184	)		—			(15,184	)
Balance for the 275 day period ended October 2, 2005	127,873		$ 128		$   173,804			$ (1,262	)		$  (5,025	)		$        —			$   167,645
Successor:
Acquisition by Holdings II	50,000		$  50		$   350,965			$      —			$         —			$        —			$   351,015
Stock based compensation	—		—		3,517			—			—			—			3,517
Net income	—		—		—			—			16,350			—			16,350
Balance for the 90 day period ended December 31, 2005	50,000		50		354,482			—			16,350			—			370,882
Issuance of common stock, net of expenses	54,162		54		668,021			—			—			—			668,075
Initial public offering costs	—		—		(6,027	)		—			—			—			(6,027	)
Share-based compensation	—		—		7,966			—			—			—			7,966
Net income	—		—		—			—			138,954			—			138,954
Balance at December 31, 2006	104,162		$ 104		$ 1,024,442			$      —			$ 155,304			$        —			$ 1,179,850

See accompanying notes.

95

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

	Predecessor							Successor
				For the 275 day				For the 90 day
				period from				period from
				January 1, 2005				October 3, 2005
	Year ended			to				to			Year ended
(in thousands)	December 31, 2004			October 2, 2005				December 31, 2005			December 31, 2006
Net income (loss)		$	6,013		$	(15,184	)		$	16,350		$	138,954
Other comprehensive income:
Reclassification adjustment of foreign currency translation adjustment		13,704			—				—			—
Unrealized gain on equity investments, net of taxes of $9		17			—				—			—
Total comprehensive income (loss)		$	19,734		$	(15,184	)		$	16,350		$	138,954

See accompanying notes.

96

EXCO Resources, Inc.
Notes to consolidated financial statements

1.   Organization

Unless the context requires otherwise, references in this annual report to “EXCO,” “EXCO Resources,” “we,” “us,” “our” and the “Company” are to EXCO Resources, Inc., its consolidated subsidiaries and EXCO Holding Inc., or EXCO Holdings, our former parent company, which was acquired by and into which EXCO Holdings II, Inc., or Holdings II, merged on October 3, 2005. References in this annual report to “Resources” refers only to the registrant, EXCO Resources, Inc. On February 14, 2006, EXCO Holdings merged with and into Resources. As such, all periods presented reflect the merger and include EXCO Holdings.

EXCO Resources, Inc., a Texas corporation, was formed in October 1955. 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 and, until February 10, 2005, in Canada. 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 derivative financial instrument 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. On February 14, 2006, we acquired TXOK Acquisition, Inc., or TXOK, for approximately $665.1 million and on October 2, 2006, we completed the acquisition of Winchester Energy Company, Ltd., or Winchester, for approximately $1.1 billion in cash after closing adjustments. The Winchester acquisition was completed within our newly-formed subsidiary, EXCO Partners, LP, or EXCO Partners. Concurrent with the closing of this acquisition we contributed to EXCO Partners all of our East Texas assets, including four of our subsidiaries that own or operate certain of our East Texas assets in exchange for $150.0 million of cash and additional equity interests in EXCO Partners. EXCO Partners borrowed $1.3 billion to fund these transactions. Our 2006 acquisitions, including TXOK and Winchester, totaled in excess of $2.1 billion. In addition, we spent $214.3 million for development drilling, acreage and related oil and natural gas facilities during 2006. For a discussion of these acquisitions as well as other transactions that we completed during 2005 and 2006, see “Item 1. Business—Significant transactions during 2005” and “Item 1. Business—Significant transactions during 2006.”

Due to the merger of our parent, EXCO Holdings (formerly EXCO Holdings II), into Resources on February 14, 2006 concurrent with the closing of our initial public offering, or IPO (See “Note 4. Significant recent transactions”), all financial information in this annual report contains the consolidated financial position and results of EXCO Resources and EXCO Holdings pursuant to presentation requirements contained in Statement of Financial Accounting Standards No. 141, “Business Combinations”, or SFAS No. 141, for transactions between entities under common control. For comparative purposes pursuant to SFAS No. 141, the prior period financial statements of EXCO Resources present the consolidated operations of EXCO Resources and EXCO Holdings for all periods. As described below, our financial statements contain two separate and distinct bases of accounting.

Predecessor—For the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, financial information presented in our consolidated statements of operations, statements of cash flows and consolidated statements of shareholders’ equity reflect the consolidated information of EXCO Resources and EXCO Holdings, our parent company until October 2, 2005.

Successor—For the 90 day  period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, financial information presented in our consolidated financial statements of operations, statements of cash flows and consolidated statements of shareholders’ equity reflect the consolidated information of EXCO Resources and Holdings II, which became our parent company on October 3, 2005

97

effective with the consummation of the Equity Buyout and the acquisition by and merger of Holdings II into EXCO Holdings (See “Note 4. Significant recent transactions”). The Equity Buyout (See “Note 4. Significant recent transactions—Equity Buyout”) was accounted for as a purchase pursuant to SFAS No. 141 and resulted in a new basis of accounting. The consolidated balance sheets as of December 31, 2005 and 2006 reflect this new basis of accounting.

In addition, as a result of the redemption of TXOK preferred stock (See “Note 4. Significant recent transactions—TXOK acquisition”) on February 14, 2006, our investment in TXOK, which was accounted for using the equity method of accounting until our redemption of the preferred stock, became a wholly-owned subsidiary.

The consolidated balance sheet as of December 31, 2005 reflects the consolidated financial position of EXCO and Holdings II (as successor for accounting purposes after its merger with EXCO Holdings) prior to the IPO of our common stock on February 9, 2006, which is more fully described below. The consolidated balance sheet as of December 31, 2006 reflects our consolidated financial position after the IPO and the merger of EXCO Holdings into EXCO Resources.

On February 8, 2006, our registration statement on Form S-1, as amended, was declared effective by the Securities and Exchange Commission, or SEC, pursuant to which we offered 50,000,000 shares of our common stock, par value $.001 per share, at an initial offering price of $13.00 per share, or a net price after underwriting discount of $12.35 per share. Net proceeds from the offering after underwriting discount, but before other expenses, were approximately $617.5 million. Concurrent with the February 14, 2006 closing of the IPO, EXCO Holdings, our parent company, was merged into and with EXCO Resources and EXCO Resources became the surviving company. Shares of stock and stock options of EXCO Holdings were automatically converted into an equal number of like securities of EXCO Resources. Subsequently, the underwriters of our IPO exercised their over-allotment option to purchase an additional 3,615,200 shares of our common stock at $12.35 per share which yielded additional net proceeds of approximately $44.6 million.

The accompanying consolidated balance sheets as of December 31, 2005 and 2006, results of operations, cashflows and changes in shareholders’ equity for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 are for EXCO, its subsidiaries, and prior to the IPO, its parent. All intercompany transactions have been eliminated. Our results of operations reflect the results of our former Canadian subsidiary, Addison Energy Inc., or Addison, as discontinued operations. Certain prior year amounts have been reclassified to conform to the current year presentation.

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.

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GAAP requires the application of “pushdown accounting” in situations where the ownership of an entity has changed. Holdings II was 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 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
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

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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 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. During 2006, a total of 3,615,700 options to purchase shares of our common stock were granted at a weighted average price of $14.02. As of December 31, 2006, a total of 8,267,373 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. During 2006, we recorded non-cash compensation of $6.5 million as general and administrative expenses and capitalized $1.4 million as oil and natural gas properties.

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.

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2.Summary of significant accounting policies

Principles of consolidation

The accompanying consolidated balance sheets as of December 31, 2005 and December 31, 2006 and the results of operations, cash flows and comprehensive income for the 90 day period from October 3, 2005 to December 31, 2005 and the twelve months ended December 31, 2006 are for EXCO and its subsidiaries and represents the stepped up Successor basis of accounting following the Equity Buyout transaction.

The accompanying results of operations, cash flows and comprehensive income 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 Predecessor basis of accounting.

The financial statements prior to January 1, 2005 have been restated to reflect the financial position, operations, cash flow and comprehensive income of 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 and natural gas reserve volumes, future development, dismantlement and abandonment costs, share-based compensation expenses, estimates relating to certain oil and natural gas revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management’s estimates.

Cash equivalents

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

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 or natural gas 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 and natural gas sales are generally uncollateralized. The allowance for doubtful accounts receivable (including current assets of discontinued operations) aggregated $1.6 million and $1.9 million at December 31, 2005 and 2006, respectively. We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings.

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For a discussion of the credit risks associated with our commodity price risk management activities, see “Note 7. Derivative financial instruments.”

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, or exemptions for normal purchases and normal sales as allowed by SFAS No. 133 exist. 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.

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 costs of 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, 2005 and 2006, the $53.1 million and $297.9 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the estimated fair value of undeveloped acreage and unproved 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.

Full cost ceiling test

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.

As of December 31, 2006, pursuant to Rule 4-10(c)(4)(i)(A) of Regulation S-X, the Company was required to compute its ceiling test using the December 31, 2006 spot prices for oil and natural gas. The computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding  the December 31, 2006 present value of future net revenues by approximately $393.7 million, of which approximately $189.1 million is attributable to our Winchester and TXOK

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acquisitions. The December 31, 2006 spot price per equivalent Mcf was less than the Company’s realized prices for 2006 by approximately 27% and approximately 38% including realized derivative settlements. Even though the December 31, 2006 prices for oil and natural gas indicated impairment, the spot price for natural gas and oil increased to $7.05 per Mmbtu and $60.03 per Bbl., respectively, on March 12, 2007, a level sufficient to eliminate the need for a ceiling test write-down.

In advance of the 2007 price recovery that eliminated the need for a ceiling test write-down, the Company requested, and received, an exemption from the SEC to exclude all of its 2006 Acquisitions, or the 2006 Acquisitions, from the full cost pool ceiling test assessments for a period of twelve months following December 31, 2006 (i.e. through the filing of our September 30, 2007 Form 10-Q). Accordingly, we will initially test the 2006 Acquisitions for impairment in conjunction with the preparation of our financial statements for the year ended December 31, 2007, provided that we can demonstrate that the fair value of the 2006 Acquisitions exceeds the carrying costs in the interim periods through September 30, 2007.

The allocated value of proved properties for the 2006 Acquisitions totaled approximately $1.6 billion, which represented an increase of over 250% to the full cost pool from December 31, 2005. The request for exemption was made because the Company believes the fair value of the 2006 Acquisitions’ proved oil and gas properties, in certain cases, can be demonstrated beyond a reasonable doubt to exceed their unamortized costs. The Company’s expectation of future prices is principally based on NYMEX futures contracts, adjusted for basis differentials, for a period of five years. After a five year period we have historically elected to use flat pricing as the NYMEX futures contracts become more thinly traded. Generally, the flat price used for the sixth year through the economic life of the property is management’s internal long-term price estimate, which is, in large part, based on an extension of the NYMEX pricing. EXCO believes the NYMEX futures contract reflects an independent proxy for fair value.

We recognize that, due to the volatility associated with oil and natural gas prices, a downward trend in market prices could occur. If such a trend were to occur and is deemed to be other than a temporary trend, we would assess the 2006 Acquisitions for impairment during the 2007 exemption period.

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 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.

Gas gathering assets

Gas gathering assets are capitalized at cost and depreciated on a straight line basis over their estimated useful lives of 25 to 40 years.

Office and field equipment

Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field 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

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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.

The following table reflects our balances for goodwill as of December 31, 2005 and 2006 (in thousands):

Predecessor:
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
Acquisition of TXOK Acquisition, Inc.	64,887
Acquisition of Power Gas Marketing and Transmission, Inc.	21,249
Acquisition of Winchester Energy Company, Ltd.	163,935
Balance as of December 31, 2006	$	470,077

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

Deferred abandonment and asset retirement obligations

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. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. EXCO adopted the new rules on asset retirement obligations on January 1, 2003.

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

	Predecessor								Successor
					For the 275 day				For the 90 day
	For the				period from				period from				For the
	year ended				January 1, 2005				October 3, 2005				year ended
	December 31,				to				to				December 31,
	2004				October 2, 2005				December 31, 2005				2006
Asset retirement obligation at beginning of period		$	6,687			$	13,247			$	14,275			$	15,823
Activity during the period:
Adjustment to liability due to purchase of EXCO by Holdings in 2003 and Holdings II in 2005		—				—				1,607				—
Adjustment to liability due to 2006 Acquisitions		—				—				—				16,954
Liabilities incurred during period		8,462				1,686				51				21,681
Liabilities settled during period		(2,702		)		(1,275		)		(336		)		(323		)
Accretion of discount		800				617				226				2,014
Asset retirement obligation at end of period:		13,247				14,275				15,823				56,149
Less current portion		2,418				1,713				1,408				1,579
Long-term portion		$	10,829			$	12,562			$	14,415			$	54,570

We have no assets that are legally restricted for purposes of settling asset retirement obligations, however we maintain a letter of credit of $1.5 million for plugging costs. This letter of credit expires on September 28, 2007.

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, 2005 and 2006 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 year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, we have capitalized $1.6 million, $1.2 million, $1.5 million and $3.3 million, respectively. Included in the $1.5 million and $3.3 million are $1.0 million and $1.4 million of share based compensation for the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively, resulting from the adoption of SFAS No. 123(R) on October 3, 2005. See “Note 14. Stock transactions” for further discussion.

Overhead reimbursement fees

We have classified fees from overhead charges billed to working interest owners, including ourselves, of $2.1 million, $1.3 million, $0.5 million and $7.8 million, for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. Our share of these charges was

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$1.5 million, $0.8 million, $0.3 million and $5.5 million for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively, and are classified as oil and natural gas production costs.

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.

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

We account for earnings per share in accordance with Statement of Financial Accounting Standards No. 128, “Earnings Per Share”, or SFAS No. 128. SFAS No. 128 requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings per common share are based on the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed in the same manner as basic earnings per share after assuming issuance of common stock for all potentially dilutive equivalent shares, whether exercisable or not.

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 14. 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.

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.

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.   Recent accounting pronouncements

In July 2006, the Financial Accounting Standards Board, or FASB, issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. FIN 48 is effective as of January 1, 2007. We do not believe the adoption of FIN 48 will have a material impact on our consolidated financial position or results of operations.

In September 2006, the Securities and Exchange Commission Staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” or SAB 108, in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related

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disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We adopted SAB 108 in the fourth quarter of 2006. The adoption did not have a material impact on our financial position, results of operations and cash flows.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements,” or SFAS No. 157 which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will be required to adopt SFAS No. 157 in the first quarter of fiscal year 2008. We are currently evaluating the impact of SFAS No. 157 on our financial statements.

4.   Recent significant transactions

TXOK acquisition

On September 16, 2005, Holdings II formed TXOK for the purpose of acquiring ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C., or collectively, ONEOK Energy. Prior to TXOK’s acquisition of ONEOK Energy, 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 and EXCO Holdings owned all of the issued and outstanding common stock of TXOK. On September 27, 2005, TXOK completed the acquisition of ONEOK Energy for an aggregate purchase price of approximately $633.0 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. EXCO Holdings purchased an additional $20.0 million of Class B 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. Pickens, which was subsequently repaid; (ii) the issuance of $150.0 million of 15% Series A Convertible Preferred Stock of TXOK, or the TXOK preferred stock, to BP EXCO Holdings LP; (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.

Prior to TXOK’s redemption of the preferred stock concurrently with the IPO, we held an 11% economic interest in TXOK and used the equity method of accounting for that investment until the merger.

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

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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.

Initial public offering

On February 14, 2006, we closed our IPO and subsequently issued 53.6 million shares of our common stock, including shares subsequently issued pursuant to an exercise by the underwriters of their over-allotment option, for net proceeds of $662.1 million. Concurrent with the consummation of the IPO, we advanced $158.8 million to TXOK to redeem the TXOK preferred stock and issued an additional 388,889 shares of our common stock as a redemption premium (see—Redemption of preferred stock and consolidation of TXOK). The redemption of this preferred stock caused TXOK to become our wholly-owned subsidiary. In addition to the redemption of the preferred stock of TXOK, we used proceeds from the IPO, together with cash on hand to repay the interim bank loan, repay the TXOK term loan, repay a portion of TXOK’s revolving credit facility and pay fees and expenses incurred in connection with the IPO. Concurrently with the closing of the IPO, EXCO Holdings merged with and into Resources and the shares of stock and stock options of EXCO Holdings were automatically converted into an equal number of like securities of EXCO Resources. As a result, Resources became the surviving company.

Redemption of preferred stock and consolidation of TXOK

On February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights and an 89% economic interest in TXOK. The redemption price for the TXOK preferred stock was cash in the amount of $150.0 million plus $8.8 million of unpaid dividends at a rate of 15% and 388,889 shares of our common stock. The EXCO common stock issued in connection with the preferred redemption represented the value necessary to produce an overall 23% annualized rate of return on the stated value of the TXOK preferred stock as of the date of redemption pursuant to the terms of the preferred stock agreement. For purposes of calculating the rate of return, the common stock of EXCO was valued at $12.00 as required by the terms of the preferred stock. Once the TXOK preferred stock was redeemed, our acquisition of TXOK, or the TXOK acquisition, was complete and it became our wholly-owned subsidiary. We accounted for the acquisition of TXOK as a step acquisition using the purchase method of accounting and began consolidating its operations effective February 14, 2006. As a result, 89% of the fair value of the assets and liabilities of TXOK was recorded at the redemption date and the remaining 11% was recorded as an adjustment to book value as of the date of the initial investment. The total purchase price of TXOK was $665.1 million representing the redemption of the TXOK preferred stock, the initial investment in TXOK common stock and the assumption of liabilities as detailed below. The allocation of the purchase price to the assets and liabilities acquired, which reflect certain second quarter adjustments to the original fair values assigned to certain current assets, current liabilities and deferred income taxes, are also presented (in thousands).

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Purchase price calculations:
Carrying value of initial investment in TXOK Acquisition, Inc.	$	21,531
Acquisition of preferred stock, including accrued and unpaid dividends	158,750
Value of preferred stock redemption premium	4,667
Assumption of debt:
Term loan, plus accrued interest	202,755
Revolving credit facility plus accrued interest	309,701
Less cash acquired	(32,261		)
Total TXOK Acquisition, Inc. purchase price	$	665,143
Allocation of purchase price:
Oil and natural gas properties—proved	$	489,076
Oil and natural gas properties—unproved	60,840
Other fixed assets	20,079
Goodwill	64,887
Current and non-current assets	37,460
Deferred income taxes	26,783
Accounts payable and other accrued expenses	(30,377		)
Asset retirement obligations	(8,203		)
Fair value of oil and natural gas derivatives	4,598
Total purchase price allocation	$	665,143

Acquisition of Power Gas Marketing & Transmission, Inc.

On April 28, 2006, our wholly-owned subsidiary, North Coast Energy, Inc., or North Coast, closed an acquisition of 100% of the common stock of Power Gas Marketing & Transmission, Inc., or PGMT, for a purchase price of $115.0 million before contractual adjustments, and a net purchase price of $113.0 million. The purchase price included the assumption of $13.1 million of debt and $38.1 million of derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under our credit facility, we paid the assumed debt and terminated the assumed derivative financial instruments. The acquisition was accounted for as a purchase in accordance with SFAS No. 141. The allocation of the purchase price to the assets and liabilities of PGMT is presented on the following table (in thousands).

Purchase price calculations:
Cash payments for acquired shares and contractual payments	$	63,615
Assumption of debt, including accrued interest	13,096
Assumption of derivative financial instruments	38,098
Less cash acquired	(1,839		)
Net purchase price	$	112,970
Allocation of purchase price:
Proved properties	$	122,972
Unproved properties	421
Deferred taxes, net	(31,424		)
Current assets	2,024
Land, field equipment and other assets	2,573
Current liabilities	(3,267		)
Asset retirement obligations	(1,527		)
Other liabilities	(51		)
Goodwill	21,249
Total allocation of purchase price	$	112,970

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Winchester Acquisition

On October 2, 2006, our wholly-owned subsidiary, Winchester Acquisition, LLC, or Winchester Acquisition, acquired Winchester Energy Company, Ltd., or Winchester, and its affiliated entities from Progress Fuels Corporation for $1.1 billion in cash, subject to purchase price adjustments, which was funded with indebtedness, as discussed below and in Note 8. The acquisition was accounted for as a purchase in accordance with SFAS No. 141. Goodwill of $163.9 million resulted from the acquisition, primarily due to the Company’s emphasis in concentrating on assets in the East Texas/North Louisiana producing regions.

The allocation of the purchase price to the assets and liabilities of Winchester is presented on the following table (in thousands):

Purchase price:
Cash payments for acquired shares of common stock	$	1,095,028
Less cash acquired	(118		)
Net purchase price	$	1,094,910
Allocation of purchase price:
Oil and natural gas properties—proved	$	583,683
Oil and natural gas properties—unproved	154,291
Gathering and other fixed assets	151,149
Goodwill	163,935
Current and non-current assets	31,872
Deferred income taxes	—
Accounts payable and other accrued expenses	(39,420		)
Asset retirement obligations	(7,793		)
Fair value of oil and natural gas derivatives	57,193
Total purchase price allocation	$	1,094,910

Pro forma results of operations

The following table reflects the unaudited pro forma results of operations as though the acquisitions of TXOK, PGMT and Winchester had occurred at the beginning of each respective period (in thousands except per share data):

	For the 275 day				For the 90 day
	period from				period from			For the
	January 1, 2005				October 3, 2005			year ended
(in thousands except per	to				to			December 31,
share data, unaudited)	October 2, 2005				December 31, 2005			2006
Revenues and other income		$	177,774			$	207,390		$	762,578
Income (loss) from continuing operations		(133,545		)		44,259			146,445
Net income (loss)		(87,333		)		44,259			146,445
Basic earnings per share		$	(0.84	)		$	0.43		$	1.51
Diluted earnings per share		$	(0.84	)		$	0.41		$	1.49

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

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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.

The following table reflects the unaudited pro forma results of operations for the year ended December 31, 2004. 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 payment of our related fees and expenses as if each occurred on January 1, 2004.

During North Coast's 26 day period from January 1, 2004 to January 26, 2004, there was $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:

	For the year ended
(in thousands)	December 31, 2004
Revenues and other income		$	99,544
Net income		$	8,306
Basic and diluted earnings per share		$	0.07

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.

5.   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. As of December 31, 2005, we had a receivable in the amount of Cdn. $21.5 million (U.S. $18.5 million) for the excess of the amount withheld for Canadian income taxes from the sales proceeds over the estimated amount of Canadian income taxes that were actually owed on the gain from the sale which was received in March 2006. 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 remains 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.

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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 made an employment offer to a terminated employee and the employee accepted the offer, Purchaser was obligated to pay EXCO an amount equal to 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 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 was eliminated as these amounts were considered in the determination of the gain on the sale.

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

				For the 275 day period
	Year ended			from January 1, 2005 to
(in thousands)	December 31, 2004			October 2, 2005
Revenues		$	85,219		$	4,490
Costs and expenses		48,945			8,893
Income (loss) from operations		36,274			(4,403		)
Gain on disposition		—			175,717
Income tax expense		10,358			49,282
Income from discontinued operations, net of income tax		$	25,916		$	122,032

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 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.

6.   Acquisitions and dispositions

Transactions other than TXOK, PGMT and Winchester that occurred during 2006

In April and May 2006, we acquired producing properties and undeveloped acreage in West Texas and the Cotton Valley trend in East Texas in two separate acquisitions. The aggregate purchase price of these assets was $135.8 million, after contractual adjustments, which was funded with indebtedness drawn under our credit agreement.

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In August and September 2006, we closed two acquisitions of producing properties and acreage for an aggregate purchase price of $76.9 million, after contractual adjustments, adding properties and acreage in our Appalachia and Rockies areas. We paid $27.5 million for properties located in Wyoming.

For the year ended December 31, 2006, property and other asset sales totaled $5.8 million.

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. 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 $45.4 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.

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. The total purchase price, after contractual adjustments, for the acquisitions was approximately $88.4 million funded with borrowings under our U.S. credit agreement and from surplus cash.

During the year ended December 31, 2004, we completed 21 sales of oil and natural gas properties in the United States. The total sales proceeds we received were approximately $51.9 million.

Pro forma financial information has not been provided because the acquisitions and dispositions were not material.

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7.   Derivative financial instruments

The following table sets forth our oil and natural gas derivatives as of December 31, 2006. The fair values at December 31, 2006 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, 2006. We 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.

			Weighted Average			Fair Value at
	Volume		Strike Price per			December 31,
	Mmbtus/Bbls		Mmbtu/Bbl			2006
	(In thousands, except prices and differentials)
Natural Gas:
Swaps:
2007		47,790		$	8.73		$	82,659
2008		43,140		8.63			23,237
2009		25,705		8.02			3,943
2010		6,985		6.63			(4,664		)
2011		1,825		4.51			(3,673		)
2012		1,830		4.51			(2,929		)
2013		1,825		4.51			(2,639		)
Total Natural Gas		129,100					95,934
Oil:
Swaps:
2007		734		69.52			3,234
2008		327		62.67			(1,455		)
2009		120		60.80			(670		)
2010		108		59.85			(605		)
Total Oil		1,289					504
Total Oil and Natural Gas							$	96,438

At December 31, 2006, the average forward NYMEX oil prices per Bbl for calendar 2007 and 2008 were $65.02 and $67.50, respectively, and the average forward NYMEX natural gas prices per Mmbtu for calendar 2007 and 2008 were $6.97 and $8.06, 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.

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8.   Long-term debt and interim bank loan

	December 31,
(in thousands)	2005			2006
Short-term debt:
Interim bank loan		$	350,000	$	—
Current portion of long-term debt		—		6,500
		$	350,000	$	6,500
Long term debt:
EXCO credit agreements		$	1	$	339,000
EPOP Revolving Credit Facility		—		643,500
EPOP Senior Term Credit Agreement		—		643,500
Unamortized discount on EPOP Senior Term Credit Agreement		—		(3,180		)
7¼% senior notes due 2011		444,720		444,720
Unamortized premium on 7¼% senior notes due 2011		17,081		14,113
Total		$	461,802	$	2,081,653

Credit agreements

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 Holdings II common stock. The maturity date of the loan was July 3, 2006, with an interest rate of 10%. The loan agreement contained representations and warranties, covenants and conditions usual for a transaction of this type. Covenants contained in the 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.

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

EXCO Credit Agreement

On March 17, 2006, EXCO Resources, Inc. and certain of its subsidiaries entered into an amended and restated credit agreement, or our credit agreement, with certain lenders, JPMorgan Chase Bank, N.A., as administrative agent, and J.P. Morgan Securities Inc., as sole bookrunner and lead arranger. This amendment established a new borrowing base of $750.0 million under our credit agreement reflecting the addition of the assets of TXOK. TXOK and its subsidiaries became guarantors of our credit agreement. The amendment also provided for an extension of our credit agreement maturity date to December 31, 2010. The borrowing base is 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

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·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 credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our oil and natural gas properties including TXOK’s Oklahoma properties and North Coast Energy, Inc. and their respective subsidiaries. Our borrowings are 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 was $300.0 million. This aggregate commitment increased to $500.0 million on May 11, 2006, was reduced to $400.0 million on October 2, 2006, and was increased back to $500.0 million on February 2, 2007.

At our option, borrowings under our 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.

We typically elect to borrow funds using the LIBOR interest rate option described above. At December 31, 2005 and 2006, the six month LIBOR rates were 4.70% and 5.37% which would result in interest rates of approximately 5.95% and 6.62%, respectively, on any new indebtedness we may incur under the credit agreement. At December 31, 2005 and 2006, we had $1,000 and $339.0 million respectively, of outstanding indebtedness under our credit agreement.

Additionally, the credit agreement contains 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, 2006, we were in compliance with the covenants contained in our credit agreement.

In connection with the contribution by EXCO Resources to EXCO Partners of EXCO Resources’ East Texas assets, EXCO Resources entered into an amendment to its credit agreement (“First Amendment”). The First Amendment generally consents to and facilitates the contribution of the East Texas assets to EXCO Partners and provides that EXCO Partners, its subsidiaries and its general partners, all of which are subsidiaries of EXCO are unrestricted subsidiaries under our credit agreement, are not subject to the terms thereof and are no longer guarantors thereof. In addition, the assets contributed by EXCO Resources were released from the mortgages securing the credit agreement. Moreover, the assets of EXCO Partners and its subsidiaries have not been pledged under our credit agreement and none of EXCO Partners or the other unrestricted subsidiaries have guaranteed our credit agreement. The First Amendment also provides that the borrowing base under the credit agreement shall be reduced to $600.0 million, with an aggregate commitment of $400.0 million (increased back to $500.0 million on February 2, 2007). The First Amendment also revises the covenants regarding the format of the financial statements to be delivered by EXCO Resources and consents to the contingent equity contribution obligation described below under “EXCO Resources Equity Contribution Agreement” subject to certain conditions. The First Amendment also amends certain covenants to address the relationship with EXCO Partners. Prior to any public offering by EXCO Partners, EXCO Resources may not permit the subsidiaries through which EXCO Resources owns the equity of EXCO Partners to incur any indebtedness or incur any lien. Prior to any public offering by EXCO Partners, EXCO Resources is required to own 100% of the equity of EXCO Partners. As of February 28, 2007, $407.0 million of indebtedness was outstanding under our credit agreement and we had $91.5 million of availability under our credit agreement. Our consolidated debt as of February 28, 2007, which includes EPOP’s debt, our credit facility

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and 71¤4% senior notes totals $2.2 billion. The debt incurred in the Winchester acquisition is more fully described below. We are in compliance with the financial covenants of the EXCO Credit Agreement as of December 31, 2006.

EPOP Revolving Credit Facility

To finance the Winchester acquisition and the $150.0 million payment to EXCO Resources for its East Texas assets, EXCO Partners’ wholly-owned subsidiary, EPOP, entered into a Senior Revolving Credit Agreement, or EPOP Revolving Credit Facility dated October 2, 2006, with a group of lenders led by JPMorgan Chase Bank, N.A. The EPOP Revolving Credit Facility has a face amount of $750.0 million with an initial borrowing base of $750.0 million and an initial conforming borrowing base of $650.0 million. The conforming borrowing base is the amount of borrowings upon which interest is computed on a lower premium to LIBOR than borrowings which exceed the conforming borrowing base. The borrowing base must be conforming by April 1, 2007. The EPOP Revolving Credit Facility is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries. We executed an amendment dated effective as of December 31, 2006, the EPOP Revolver First Amendment, which amends certain financial covenants contained in the EPOP Revolving Credit Facility. The EPOP Revolver Amendment was sought due to our inability to comply with the leverage ratio and interest coverage ratio tests, as defined below, as of December 31, 2006. The original financial covenant ratios were negotiated assuming a more accelerated drilling program, which would have resulted in higher forecasted production. In addition, interest expense attributable to the EPOP Senior Term Credit Agreement was higher than originally forecast as the final negotiated interest rate exceeded our initial estimates when the covenants were being negotiated. Management and the lenders believe these revised covenants are more consistent with the actual operational activities contemplated at EPOP during 2007. As amended, the EPOP Revolving Credit Facility contains the following financial covenants:

·EPOP’s Consolidated Current Ratio (as defined) as of the end of any fiscal quarter ending after September 30, 2006 is not permitted to be less than 1.00 to 1.00. The EPOP Revolver Amendment did not revise this covenant.

·EPOP’s ratio of (A) Consolidated Funded Indebtedness (as defined) as of the end of a fiscal quarter to (B) Consolidated EBITDAX (as defined) shall not be greater than:

·6.00 to 1.00 (increased from 5.00 to 1.00) for the quarter ending December 31, 2006. For purposes of the December 31, 2006 Consolidated EBITDAX, the December 31, 2006 quarter shall be multiplied by four (4);

·5.50 to 1.00 (increased from 4.00 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX calculated using a defined trailing period multiplied by a fraction);

·5.50 to 1.00 (increased from 4.00 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);

·5.25 to 1.00 (increased from 4.00 to 1.00) for the quarter ended December 31, 2007, and

·4.00 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.

·EPOP will not permit its ratio of Consolidated EBITDAX to Consolidated Interest Expenses (as defined) to be less than:

·1.50 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2006 (Consolidated EBITDAX and Consolidated Interest Expenses for such quarter to be multiplied by four);

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·1.75 to 1.00 (lowered from 2.50 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX and Consolidated Interest Expenses calculated using a defined trailing period multiplied by a fraction);

·1.75 to 1.00 (lowered from 2.50 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX and Consolidated Interest Expenses calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);

·2.00 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2007, and

·2.50 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.

·Finally, EPOP will not permit its ratio of net present value (calculated pursuant to the terms of the EPOP Revolving Credit Facility) to Consolidated Funding Indebtedness (as defined) to be less than (i) 1.15 to 1.00 (unchanged) determined as of December 31, 2006 or (ii)1.25 to 1.00 (unchanged) determined as of each succeeding June 30 and December 31.

The EPOP Revolving Credit Facility, as amended, contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Revolving Credit Facility matures four years from the closing date and has an initial drawn interest rate of LIBOR + 175 basis points (“bps”) and an undrawn commitment fee of 37.5 bps on the first $650.0 million of the EPOP Revolving Credit Facility. To the extent usage exceeds the initial conforming borrowing base, the EPOP Revolving Credit Facility will have an initial drawn interest rate of LIBOR + 250 bps and an undrawn commitment fee of 50 bps on the portion of the borrowings that exceed the initial conforming borrowing base. Finally, as a condition precedent to the funding of the EPOP Revolving Credit Facility, EPOP is required to hedge 75% of proved developed producing production through 2010. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP. The initial amount borrowed under this facility was $651.0 million at closing of the Winchester merger and the weighted average interest rate as of December 31, 2006, is 7.19%. As of February 28, 2007, $643.5 million was outstanding under this facility.  We are in compliance with the financial covenants, as amended, pursuant to the EPOP Revolver First Amendment as of December 31, 2006.

EPOP Senior Term Credit Agreement

In connection with the Winchester acquisition and the EXCO Resources asset contribution, EPOP entered into the EPOP Senior Term Credit Agreement, dated October 2, 2006 (as amended and restated as of October 13, 2006), with JPMorgan Chase Bank, N.A., as administrative agent. The aggregate principal amount is $650.0 million. The EPOP Senior Term Credit Agreement is secured by a second priority lien on all of the properties securing the EPOP Revolving Credit Facility, including 100% of the stock of subsidiaries, and is guaranteed by all existing and future subsidiaries. Financial covenants governing the EPOP Senior Term Credit Agreement include the same net present value ratio contained in the EPOP Revolving Credit Facility, a Leverage Ratio computed similarly to the covenant contained in the EPOP Revolving Credit Facility that cannot exceed 5.50 to 1.00 for applicable periods, and an Interest Coverage Ratio that cannot be less than 2.00 to 1.00 for any applicable period. The debt covenant tests for the EPOP Senior Term Credit Agreement begin with the quarter ended March 31, 2007. In addition, EPOP cannot make Capital Expenditures (as defined) exceeding $125.0 million in any fiscal year. The EPOP Senior Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The EPOP Senior Term Credit Agreement has an interest rate of LIBOR + 600 bps, with 25 bps step-ups on October 2, 2007 and January 2, 2008, and a total cap of LIBOR + 650 bps. Additionally, the EPOP Senior Term Credit Agreement matures five years from

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the closing date, requires payments of principle at 1% per year, with the balance of unpaid principle due at maturity. Upon an initial public offering by EXCO Partners, EPOP shall prepay the principal outstanding (plus accrued interest) under the EPOP Senior Term Credit Agreement at par plus an applicable premium. Commencing with the fiscal year ended December 31, 2007, and each year thereafter, EPOP must apply 100% of its Excess Cash Flow (as defined in the EPOP Senior Term Credit Agreement) toward prepayment at par of the EPOP Senior Term Credit Agreement. Such payments shall be made no later than the later of April 15 or five business days following delivery of the annual financial statements required under the EPOP Senior Term Credit Agreement. Any principal payment prior to the first anniversary, other than the mandatory cash flow and amortization prepayments described above, must be paid at 102% of the principal amount and after the first anniversary date to and including the second anniversary at 101% of par. Thereafter, any prepayments are at par. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP.

EXCO Resources Equity Contribution Agreement

In connection with the arrangement of the EPOP Senior Term Credit Agreement, the lenders required EXCO Resources to enter into an Equity Contribution Agreement, dated October 2, 2006, and amended and restated on October 4, 2006 and October 13, 2006 (as amended and restated, the “ECA”). The ECA generally provides that on the date 18 months from October 2, 2006 (Equity Contribution Date), EXCO Resources will make a cash common equity contribution to EPOP in an amount equal to the lesser of (i) $150.0 million or (ii) the aggregate amount then outstanding under the EPOP Senior Term Credit Agreement; provided, that in no event can this obligation exceed during the term of the ECA the maximum amount that EXCO Resources could contribute under the terms of the Indenture governing its senior notes. Alternatively, EXCO Resources can cause EXCO Partners to make the equity contribution to EPOP in the amount of $150.0 million to satisfy this obligation. In lieu of requiring the equity contribution, the holders of at least 662¤3% of the aggregate principal amount of the loans outstanding under the EPOP Senior Term Credit Agreement can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become “Restricted Subsidiaries” under the credit agreement and require EXCO Resources to provide, and cause all then restricted subsidiaries as defined and constituted under the credit agreement to provide, guarantees and collateral in respect of the EPOP Senior Term Credit Agreement on terms substantially consistent with the guarantees and collateral provided under its credit agreement. This requirement is subject to compliance with the credit agreement. Any cash so contributed shall be used by EPOP to prepay loans under the EPOP Senior Term Credit Agreement. EXCO Resources is prohibited from making restricted payments (as defined in the Indenture) that would constitute a utilization of the Indenture restricted payment baskets, other than restricted payments not to exceed $5.0 million In addition, EXCO Resources has covenanted to redeem or defease its senior notes if the Indenture would not permit the equity contribution or the lenders’ election to cause EXCO Resources to designate EPOP and its subsidiaries as restricted subsidiaries under the credit agreement (subject to certain restrictions on the indebtedness that may be incurred for any such redemption or defeasance if the election to cause the designation of EPOP as a restricted subsidiary is chosen). The ECA will terminate upon payment in full of the EPOP Senior Term Credit Agreement.

7¼% senior notes due January 15, 2011

On January 20, 2004, EXCO completed the private placement of $350.0 million aggregate principal amount of 7¼% 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

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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.

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 is being amortized over the remaining life of the senior notes. The unamortized premium was $14.1 million at December 31, 2006. The purchase of the $5.3 million in aggregate principal amount of senior notes tendered to us as discussed above 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, 2006 was $453.6 million as compared to the carrying amount of $458.8 million (including $14.1 million of unamortized premium). The fair value of the senior notes is estimated based on quoted market prices for the senior notes.

Following is the principal maturity schedule for the debt outstanding as of December 31, 2006 (in thousands):

	Amount
2007	$	6,500
2008	6,435
2009	6,371
2010	988,807
2011	1,069,107
Thereafter	—
Total	$	2,077,220

9.   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.

10.   Commitments and contingencies

We lease our offices and certain equipment. Our rental expenses were approximately $0.6 million, $0.6 million, $0.2 million and $1.7 million for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively. Our future minimum rental payments under

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operating leases with remaining noncancellable lease terms at December 31, 2006, are as follows (in thousands):

	Amount
2007	$	5,834
2008	5,198
2009	4,679
2010	4,618
2011	1,620
Thereafter	2,235
Total	$	24,184

We regularly enter into agreements with contract drilling companies which commit us to utilize, or to pay for if not utilized, the use of drilling rigs in east Texas. As of December 31, 2006, the minimum amount that we are obligated to pay under these contracts is $78.6 million.

On October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styled PRC Holdings, LLC, et al. v. North Coast Energy, Inc. and was filed in the Circuit Court of Roane County, West Virginia. This action has been removed to the United States District Court for the Southern District of West Virginia. The action has been brought by certain landowners and lessors in West Virginia for themselves and on behalf of other similarly situated landowners and lessors in West Virginia. The lawsuit alleges that North Coast Energy, Inc. has not been paying royalties to the plaintiffs in the manner required under the applicable leases, has provided misleading documentation to the plaintiffs regarding the royalties due, and has breached various other contractual, statutory and fiduciary duties to the plaintiffs with regard to the payment of royalties. In a case styled The Estate of Garrison Tawney v. Columbia Natural Resources, LLC announced in June 2006, the West Virginia Supreme Court held that language such as “at the wellhead” and similar language contained in leases when used in describing how to calculate royalties due lessors was ambiguous and, therefore, should be construed strictly against the lessee. Accordingly, in the absence of express language in a lease that is intended to allocate between a lessor and lessee post-production costs such as the costs of marketing the product and transporting it to the point of sale, no post-production costs may be deducted from the lessor’s royalty payment due from the lessee. The claims alleged by the plaintiffs in the lawsuit filed against us are similar to the claims alleged in the Tawney case. Plaintiffs are seeking common law and statutory compensatory and punitive damages, interest and costs and other remedies. We are vigorously defending the existing lawsuit. The action is in a very preliminary stage. The preliminary status of the lawsuit leaves the ultimate outcome of this litigation uncertain. We believe that we have substantial defenses to this lawsuit and that the adverse affects from this litigation, if any, are reflected in our financial statements and we do not expect the ultimate outcome of the lawsuit to have a material effect on our financial position, results of operations or cash flows.

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.

11.   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 $0.4 million, $0.4 million, $95,000 and $1.1 million 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 and for the year ended December 31, 2006, respectively, have been included as general and administrative expense.

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12.   Bonus retention program

Prior to entering into the Equity Buyout, Holdings established a bonus retention program in 2003 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. For the year ended December 31, 2004, we included approximately $1.4 million in general and administrative expense and $0.4 million 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.

13.   Earnings per share

The following table presents basic and diluted earnings (loss) per share for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 (in thousands, except per share amounts):

	Predecessor								Successor
					For the 275 day				For the 90 day
					period from				period from
					January 1, 2005				October 3, 2005
	Year ended				to				to			Year ended
	December 31, 2004				October 2, 2005				December 31, 2005			December 31, 2006
Basic earnings per share:
Income (loss) from continuing operations		$	(19,903	)		$	(137,216	)		$	16,350		$	138,954
Income from discontinued operations		25,916				122,032				—			—
Net income		$	6,013			$	(15,184	)		$	16,350		$	138,954
Shares:
Weighted average number of common shares outstanding		115,947				116,504				47,222			96,727
Basic earnings (loss) per share:
Continuing operations		$	(0.17	)		$	(1.18	)		$	0.35		$	1.44
Discontinued operations		0.22				1.05				—			—
Total basic earnings per share		$	0.05			$	(0.13	)		$	0.35		$	1.44
Diluted earnings per share:
Income (loss) from continuing operations		$	(19,903	)		$	(137,216	)		$	16,350		$	138,954
Income from discontinued operations		25,916				122,032				—			—
Net income		$	6,013			$	(15,184	)		$	16,350		$	138,954
Shares:
Weighted average number of common shares outstanding		115,947				116,504				47,222			96,727
Dilutive effect of stock options		—				—				—			1,726
Weighted average common shares and common stock equivalents		115,947				116,504				47,222			98,453
Diluted earnings (loss) per share:
Continuing operations		$	(0.17	)		$	(1.18	)		$	0.35		$	1.41
Discontinued operations		0.22				1.05				—			—
Total diluted earnings per share		$	0.05			$	(0.13	)		$	0.35		$	1.41

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As a result of the loss from continuing operations for the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, the potential common stock equivalents from the assumed conversion of stock options of 5,097,369 and 8,801,351, respectively, have been excluded from the diluted EPS calculation. For financial accounting purposes, the Class B shares of Holdings for the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, were considered to be a “variable” plan since a holder of the shares had to be employed at the date of a change in control to receive fair value for the Class B shares. As a result, the Class B shares have been excluded from per share calculations as required under SFAS No. 128.

14.   Stock transactions

Stock options

As discussed in “Note 2. Summary of significant accounting policies”, certain of our employees were granted Holdings stock options under the Holdings Plan. The following table summarizes Holdings stock option activity under the Holdings Plan, which were canceled upon consummation of the Equity Buyout:

		Weighted Average
	Stock	Exercise Price
	Options	Per Share
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 exerciseable 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 EXCO’s common stock. The options expire ten years following the date of grant and have a weighted average remaining life of 9.19 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, 2006, there were 1,574,475 shares available to be granted under the Plan.

The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan:

		Weighted average			Weighted average		Aggregate
	Stock	exercise price			remaining terms		intrinsic
	options	per share			(in years)		value
Options outstanding at October 3, 2005	—		$	—
Granted	4,992,650		$	7.50
Forfeitures	19,575		$	7.50
Exercised	—		$	—
Options outstanding at December 31, 2005	4,973,075		$	7.50
Granted	3,615,700		$	14.02
Forfeitures	163,250		$	8.83
Exercised	158,152		$	7.97
Options outstanding at December 31, 2006	8,267,373		$	10.32		9.19		$	54,505
Options exercisable at December 31, 2006	3,179,474		$	9.33		9.04		$	24,116

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The weighted average grant date fair value of stock options granted during the years 2005 and 2006 were $2.29 and $4.75, respectively. The total intrinsic value of stock options exercised for the 90 day period from October 3, 2006 and the year ended December 31, 2006 was $0 and $0.9 million, respectively.

The following summarizes the status of the non-vested stock options as of December 31, 2006 and changes for the year ended December 31, 2006:

				Weighted average
	Number of shares			grant date fair value
Nonvested January 1, 2006		3,728,962			$	2.29
Granted		3,615,700			4.75
Forfeitures		(163,250	)		2.79
Vested		(2,093,513	)		3.35
Nonvested at December 31, 2006		5,087,899			$	3.59

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. Options are granted at the fair market value of the common stock on the date of grant. The following assumptions were used for the options included in the above table:

	2005		2006
Expected life	4 years		4 years
Risk-free rate of return	4.22	%	4.22% - 5.13	%
Volatility	30.40	%	30.40 % - 35.58	%
Dividend yield	0	%	0	%

As required by SFAS 123(R), the granting of options under the 2005 Incentive Plan 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 Predecessor for .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 and the year ended December 31, 2006 was $3.2 million and $7.9 million, of which $2.2 million and $6.5 million is included in general and administrative expense and $1.0 million and $1.4 million was capitalized as part of proved developed and undeveloped oil and natural gas properties, respectively, as discussed in “Note 2. Summary of significant accounting policies.” Total share-based compensation to be recognized on unvested awards is $15.5 million over a weighted average period of 2.40 years as of December 31, 2006.

As discussed in “Note 1. Organization,” the Class B common stock issued in July 2003 was considered to be a “variable” plan for financial reporting 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.

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15.   Income taxes

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

	Predecessor								Successor
					For the				For the
					275 day				90 day
					period from				period from
	Year				January 1,				October 3,				Year
	ended				2005 to				2005 to				ended
	December 31,				October 2,				December 31,				December 31,
(in thousands)	2004				2005				2005				2006
Current:
U.S.
Federal		$	—			$	(3,563	)		$	(7,020	)		$	—
State		1,445				(668		)		(1,315		)		—
Total current income tax (benefit)		1,445				(4,231		)		(8,335		)		—
Deferred:
U.S.
Federal		4,681				(49,881		)		12,949				80,697
State		(91		)		(9,586		)		3,017				8,704
Canadian		(909		)		—				—				—
Total deferred income tax (benefit)		3,681				(59,467		)		15,966				89,401
Total income tax (benefit)		$	5,126			$	(63,698	)		$	7,631			$	89,401

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 $7.9 million of the NOLs limited by Section 382 will expire prior to their utilization. Expiration is expected to occur from 2007 through 2016. Our NOL available for utilization at December 31, 2006 is approximately $129.3 million.

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

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rise to the effect is a component of discontinued operations. On May 18, 2006, the Texas governor signed into law a Texas Margin tax that replaces the current franchise tax effective January 1, 2007. We had recorded the effect of the change in tax rate on our existing deferred balances in the second quarter of 2006. Our deferred income tax related to the Texas Margin tax is $0.9 million at December 31, 2006.

For the year ended December 31, 2004, we recognized a deferred income tax benefit of approximately $0.9 million related to Canadian legislation which became effective in May 2004 to phase in reduced income tax rates and allow for deductibility of crown royalties. This amount has been reflected as an income tax benefit in continuing operations pursuant to the provisions of SFAS No. 109 and EITF 93-13 as discussed above.

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,
(in thousands)	2005			2006
Current deferred tax assets (liabilities):
Basis difference in fair value of derivative financial instruments	$	26,605		$	(32,639	)
Other	3,363			—
Total current deferred tax assets (liabilities)	$	29,968		$	(32,639	)
Long-term deferred tax assets:
Net operating loss carryforwards—U.S.	$	1,879		$	48,654
Basis difference in fair value of derivative financial instruments	34,300			32,684
Purchase accounting adjustment to bond premium	5,456			9,511
Share-based compensation	437			1,234
Other	3			118
Total long-term deferred tax assets	42,075			92,201
Deferred tax liabilities:
Book basis of oil and natural gas properties in excess of tax basis—U.S.	(176,677		)	(258,337		)
Taxes on undistributed earnings of foreign subsidiary—U.S.	(310		)	—
Total deferred liabilities	(176,987		)	(258,337		)
Net noncurrent deferred tax liabilities	$	(134,912	)	$	(166,136	)

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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 year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 is presented in the following table:

	Predecessor								Successor
					For the 275 day				For the 90 day
					period from				period from
	Year ended				January 1, 2005				October 3, 2005				Year ended
	December 31,				to				to				December 31,
(in thousands)	2004				October 2, 2005				December 31, 2005				2006
United States federal income taxes (benefit) at statutory rate of 35%		$	(5,120	)		$	(70,293	)		$	8,393			$	79,925
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				1,420
Non-deductible intercompany foreign interest expense		1,840				—				—				—
State taxes net of federal benefit		880				(6,665		)		1,095				8,704
Other		198				(741		)		535				(648		)
Total income tax provision		$	5,126			$	(63,698	)		$	7,631			$89,401

16.Related party transactions

TXOK acquisition

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 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 $633.0 million, net of contractual adjustments. 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 were an obligor or guarantor with respect to these financings; however, Holdings (formerly Holdings II) pledged its stock in TXOK as collateral security for payment of the TXOK credit facility and the TXOK term loan.

On October 7, 2005 Holdings made an additional $20.0 million investment in TXOK. Holdings’ additional investment was partially funded by an advance of $4.0 million from EXCO Resources. TXOK

129

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 EXCO 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.

On February 14, 2006, in connection with our IPO, EXCO advanced TXOK $158.8 million to redeem its preferred stock and TXOK became our wholly-owned subsidiary. 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. 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. We used the equity method of accounting for our investment in TXOK until February 14, 2006, when TXOK became a wholly-owned subsidiary.

Effective October 15, 2005, we entered into an agreement with TXOK to manage TXOK’s business affairs. Mr. Pickens controlled TXOK through BP EXCO Holdings LP’s ownership of the TXOK preferred stock. The agreement provided that we would provide TXOK with general management, treasury, finance, legal, audit, tax, information technology, and payroll and benefit administration services. TXOK 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 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 ONEOK and historically worked on these assets. TXOK reimbursed 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. On February 14, 2006, TXOK became our wholly-owned subsidiary and the accounts under the related party arrangements were settled.

Corporate use of personal aircraft

We periodically charter, for company business, a jet aircraft from DHM Aviation, LLC, a company owned by Douglas H. Miller, our chairman and chief executive officer. The Board of Directors has adopted a written policy covering the use of this aircraft. The Company believes that prudent use of a chartered private airplane by our senior management while on company business can promote efficient use of management time. Such usage can allow for unfettered, confidential communications among management during the course of the flight and minimize airport commuting and waiting time, thereby promoting maximum use of management time for company business. However, we restrict the use of the aircraft to priority company business being conducted by senior management in a manner that is cost effective for us and our shareholders. As a result, EXCO reimbursed use of the aircraft is restricted to company business. Such use must be approved in advance by Resources’ President and Chief Financial Officer. We maintain a detailed written log of such usage specifying the company personnel (and others, if any) that fly on the aircraft, the travel dates and destination(s), and the company business being conducted. In addition, the log contains a detail of all charges paid or reimbursed by us with supporting written documentation.

In the event the aircraft is chartered for a mixture of company business and personal use, all charges will be reasonably allocated between company reimbursed charges and charges to the person using the aircraft for personal use.

At least annually, and more frequently if requested by the Audit Committee, our Director of Internal Audit surveys fixed base operators and other charter operators located at Dallas Love Field, Dallas, Texas

130

to ascertain hourly flight rates for aircraft of comparable size and equipment in relation to the aircraft. This survey also ascertains other charges (including fuel surcharges) invoiced by such charter operators as well as out-of-pocket reimbursement policies. Such survey is supplied to the Audit Committee in order for the Audit Committee to establish an hourly rate and other charges EXCO shall pay for the upcoming calendar year for the use of the aircraft. The present hourly rate paid by EXCO to DHM Aviation, LLC is less than market rate for similar aircraft.

We reimburse DHM Aviation, LLC at a rate of $3,600 per hour, including fuel surcharges, for use of the aircraft. During the year ended December 31, 2004, we paid DHM Aviation, LLC $0.5 million for use of the aircraft. 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, we paid DHM Aviation, LLC $0.3 million and $0.1 million, respectively. Payments to DHM Aviation, LLC for the year ended December 31, 2006 were $0.4 million for use of the aircraft. During 2004, we were reimbursed a total of $93,000 of the aircraft fees by the underwriters of our senior notes offering.

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. 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), and Mr. Harold L. Hickey, who purchased 166,670 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.

Suite

The Company maintains a suite at the American Airlines Center in Dallas, Texas. The Company shares the suite with and is reimbursed for 50% of its expenses relative to the suite by an entity affiliated with Boone Pickens, one of our directors, pursuant to an arrangement entered into in 2006 between the Company and such entity. During the year ended December 31, 2006, the Company paid a total of $350,000 to maintain the suite, of which $175,000 was reimbursed by the entity affiliated with Mr. Pickens.

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.

17.    Concentration of credit risk

During 2005 and 2006, sales of natural gas to an industrial customer and an interstate pipeline accounted for 10.1% and 11.6%, respectively, of our total oil and natural gas revenues. During 2004, sales of natural gas to an industrial customer accounted for 10.6% 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.

131

18.   Geographic operating segment information and oil and natural gas disclosures

We follow Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS No. 131). We have operations in only one industry segment, that being the oil and natural gas exploration and production industry.  In prior periods, the Company provided geographic segment information for the following regions within the United States: EXCO, excluding Appalachia, and Appalachia. Effective in the fourth quarter of 2006, we no longer present separate financial information for geographic regions within the United States as we have aggregated these regions into one reportable segment. As a result, the prior period segment information has been deleted.

19.   Subsequent events

On December 29, 2006, we announced an agreement with Anadarko Petroleum Corporation and Anadarko Gathering Company, or collectively Anadarko, to acquire substantially all of the oil and gas properties and related assets, or collectively the Vernon Assets, of Anadarko in the Vernon and Ansley Fields located in Jackson Parish, Louisiana through our wholly-owned subsidiary, Vernon Holdings, LLC, or Vernon, for $1.6 billion in cash. In December 2006, we deposited $80.0 million in an escrow account to be applied to the purchase price upon closing. We anticipate closing on these properties in the  first quarter of 2007.

On February 2, 2007, we announced we had signed a Purchase and Sale Agreement, or the Southern Gas Purchase Agreement, with Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, or collectively Anadarko, to acquire substantially all of the oil and natural gas properties and related assets, of Anadarko in multiple fields located in the Mid-Continent, South Texas and Gulf Coast areas of Oklahoma and Texas. The purchase price is $860.0 million, of which, we have paid $43.0 million. We anticipate closing in the second quarter of 2007.

In conjunction with these acquisitions, we have received a revised commitment letter dated as of February 1, 2007, from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A. The new commitment letter provides for a senior secured revolving credit facility in the amount of $1.8 billion and a bridge loan facility in the amount of $1.1 billion, or collectively the new credit facilities. In addition, we are considering other financing alternatives, including a private placement of preferred stock.

In January 2007, we completed the sale of our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. The transaction included substantially all of our assets in the area. The adjusted purchase price paid at closing was $131.9 million.

132

20.   Quarterly financial data (unaudited)

The following are summarized quarterly financial data for the years ended December 31, 2005 and 2006:

	Quarter
	Predecessor												Successor
									2 day period from				90 day period from
									October 1, 2005				October 3, 2005
									to				to
									October 2, 2005				December 31, 2005
(in thousands)	1st			2nd		3rd			4th
2005
Revenues	$	(18,072	)	$	31,662	$	(52,327	)		$	1,401			$	72,179
Operating income	(46,875		)	1,387		(82,501		)		(72,925		)		23,981
Net income (loss) from continuing operations	$	(28,668	)	$	4,412	$	(49,723	)		$	(63,237	)		$	16,350
Income (loss) from discontinued operations	120,884			1,149		—				(1		)		—
Net income (loss)	$	92,216		$	5,561	$	(49,723	)		$	(63,238	)		$	16,350
Basic earnings per share:
Net income (loss) from continuing operations	$	(0.25	)	$	0.04	$	(0.43	)		$	(0.53	)		$	0.35
Income from discontinued operations	1.04			0.01		—				—				—
Net income (loss)	$	0.79		$	0.05	$	(0.43	)		$	(0.53	)		$	0.35
Diluted earnings per share:
Net income (loss) from continuing operations	$	(0.25	)	$	0.04	$	(0.43	)		$	(0.53	)		$	0.35
Income from discontinued operations	1.04			0.01		—				—				—
Net income (loss)	$	0.79		$	0.05	$	(0.43	)		$	(0.53	)		$	0.35

	1st		2nd		3rd		4th
2006
Revenues	$	113,146	$	117,112	$	185,329	$	143,862
Operating income	54,718		52,855		116,229		4,553
Net income (loss) from continuing operations	$	37,152	$	31,023	$	71,745	$	(966	)
Income from discontinued operations	—		—		—		—
Net income (loss)	$	37,152	$	31,023	$	71,745	$	(966	)
Basic earnings per share:
Net income (loss) from continuing operations	$	0.46	$	0.30	$	0.69	$	(0.01	)
Income from discontinued operations	—		—		—		—
Net income (loss)	$	0.46	$	0.30	$	0.69	$	(0.01	)
Diluted earnings per share:
Net income (loss) from continuing operations	$	0.45	$	0.29	$	0.68	$	(0.01	)
Income from discontinued operations	—		—		—		—
Net income (loss)	$	0.45	$	0.29	$	0.68	$	(0.01	)

133

21.   Consolidating financial statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The senior notes are jointly and severally guaranteed by 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 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. On May 4, 2006, PGMT became a guarantor of the senior notes. In conjunction with the formation of EXCO Partners and the Winchester acquisition on October 2, 2006, certain of our existing subsidiaries, specifically ROJO Pipeline, Inc. and those TXOK subsidiaries that hold direct or indirect interests in certain of our East Texas assets were released from their guaranties under the senior notes and are now deemed unrestricted subsidiaries thereunder. EXCO Resources itself also contributed all of its directly held East Texas assets to EXCO Partners. EXCO Partners, its direct and indirect partners, which are also subsidiaries of EXCO Resources, and all of EXCO Partners’ subsidiaries are deemed unrestricted subsidiaries under the Indenture governing the senior notes and are not guarantors of the senior notes.

In connection with the formation of EXCO Partners on October 2, 2006 and the resulting contribution of EXCO’s assets in East Texas, its ROJO subsidiary and the East Texas subsidiaries of TXOK (collectively, the non-guarantor subsidiaries), the consolidating balance sheet as of December 31, 2005 and the consolidating statements of operations and consolidating statements of cash flows for 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 have been restated to reflect the non-guarantor subsidiaries as if they had been non-guarantor subsidiaries for all periods presented. We have also presented the 2006 consolidating financial statements to reflect the non-guarantor status as if it was in place at the beginning of the year.

The following financial information presents consolidating financial statements, which include:

·Resources;

·the guarantor subsidiaries on a combined basis;

·the non-guarantor subsidiaries;

·elimination entries necessary to consolidate Resources, the guarantor subsidiaries and the non-guarantor subsidiaries; and

·EXCO on a consolidated basis.

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.

134

EXCO Resources, Inc.
Consolidating balance sheet
December 31, 2005

				Guarantor				Non-guarantor
(in thousands)	Resources			subsidiaries				subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	191,499			$	35,454			$	—			$	—			$	226,953
Other current assets	67,650				43,589				4,333				—				115,572
Total current assets	259,149				79,043				4,333				—				342,525
Investment in TXOK Acquisition, Inc.	20,837				—				—				—				20,837
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	49				46,385				6,687				—				53,121
Proved developed and undeveloped oil and natural gas properties	94,872				691,716				87,007				—				873,595
Allowance for depreciation, depletion and amortization	(1,650		)		(9,060		)		(2,571		)		—				(13,281		)
Oil and natural gas properties, net	93,271				729,041				91,123				—				913,435
Gas gathering assets, office and field equipment, net	1,745				30,846				680				—				33,271
Goodwill	76,786				143,220				—				—				220,006
Investments in and advances to affiliates	1,241,231				(288,867		)		(83,073		)		(869,291		)		—
Other assets, net	—				419				—				—				419
Total assets	$	1,693,019			$	693,702			$	13,063			$	(869,291	)		$	1,530,493
Liabilities and stockholders’ equity
Current liabilities	$	769,210			$	50,482			$	2,087			$	(356,054	)		$	465,725
Long-term debt	461,802				—				—				—				461,802
Deferred income taxes	34,151				100,761				—				—				134,912
Other liabilities	56,974				39,634				564				—				97,172
Stockholders’ equity	370,882				502,825				10,412				(513,237		)		370,882
Total liabilities and stockholders’ equity	$	1,693,019			$	693,702			$	13,063			$	(869,291	)		$	1,530,493

135

EXCO Resources, Inc.
Consolidating balance sheet
December 31, 2006

(in thousands)	Resources			Guarantor subsidiaries				Non-guarantor subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	(3,031	)		$	15,786			$	10,067			$	—			$	22,822
Other current assets	21,040				59,494				133,354				—				213,888
Total current assets	18,009				75,280				143,421				—				236,710
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	53,617				54,603				189,699				—				297,919
Proved developed and undeveloped oil and natural gas properties.	341,694				1,085,737				1,065,432				—				2,492,863
Allowance for depreciation, depletion and amortization	(20,701		)		(66,507		)		(55,383		)		—				(142,591		)
Oil and natural gas properties, net	374,610				1,073,833				1,199,748				—				2,648,191
Gas gathering assets, office and field equipment, net	5,193				34,085				174,883				—				214,161
Deferred financing costs	946				—				14,983								15,929
Advance on probable acquisition	80,000				—				—				—				80,000
Oil and natural gas derivatives	1,868				9,522				30,079				—				41,469
Goodwill	62,776				196,952				210,349				—				470,077
Investments in and advances to affiliates	1,515,673				(336,199		)		373,805				(1,553,279		)		—
Other assets, net	—				488				32				—				520
Total assets	$	2,059,075			$	1,053,961			$	2,147,300			$	(1,553,279	)		$	3,707,057
Liabilities and stockholders’ equity
Current liabilities	$	56,691			$	35,266			$	98,967			$	—			$	190,924
Long-term debt	797,832				—				1,283,821				—				2,081,653
Deferred income taxes	14,395				151,741				—				—				166,136
Other liabilities	10,307				67,491				10,696				—				88,494
Stockholders’ equity	1,179,850				799,463				753,816				(1,553,279		)		1,179,850
Total liabilities and stockholders’ equity	$	2,059,075			$	1,053,961			$	2,147,300			$	(1,553,279	)		$	3,707,057

136

EXCO Resources, Inc.
Consolidating statement of operations
For the year ended December 31, 2004

(in thousands)	Resources				Guarantor subsidiaries				Non-guarantor subsidiaries			Eliminations				Consolidated
Revenues:
Oil and natural gas sales		$	39,993			$98,360				$	3,640		$	—			$	141,993
Derivative financial instruments		(18,055		)		(32,288		)		—			—				(50,343		)
Other income		4,305				877				—			(3,998		)		1,184
Equity in earnings of subsidiaries		41,164				—				—			(41,164		)		—
Total revenues		67,407				66,949				3,640			(45,162		)		92,834
Costs and expenses:
Oil and natural gas production		11,563				15,759				934			—				28,256
Depreciation, depletion and amortization		7,148				20,271				1,100			—				28,519
Accretion of discount on asset retirement obligations		348				446				6			—				800
General and administrative		11,603				3,288				575			—				15,466
Interest		34,432				4,136				—			(3,998		)		34,570
Total costs and expenses		65,094				43,900				2,615			(3,998		)		107,611
Income (loss) before income taxes		2,313				23,049				1,025			(41,164		)		(14,777		)
Income tax expense		504				4,622				—			—				5,126
Income before discontinued operations		1,809				18,427				1,025			(41,164		)		(19,903		)
Discontinued operations:
Income from operations		5,114				—				31,160			—				36,274
Income tax expense		910				—				9,448			—				10,358
Income from discontinued operations		4,204				—				21,712			—				25,916
Net income		$	6,013			$	18,427			$	22,737		$	(41,164	)		$	6,013

137

EXCO Resources, Inc.
Consolidating statement of operations
For the 275 day period ended October 2, 2005

(in thousands)	Resources			Guarantor subsidiaries				Non-guarantor subsidiaries				Eliminations				Consolidated
Revenues:
Oil and natural gas sales	$	22,861			$	96,005			$	13,955			$	—			$	132,821
Derivative financial instruments	(56,705		)		(120,548		)		—				—				(177,253		)
Other income	32,073				1,208				141				(26,326		)		7,096
Equity in earnings of subsidiaries	(43,080		)		—				—				43,080				—
Total revenues	(44,851		)		(23,335		)		14,096				16,754				(37,336		)
Costs and expenses:
Oil and natural gas production	6,772				12,988				2,397				—				22,157
Depreciation, depletion and amortization	3,978				15,242				5,467				—				24,687
Accretion of discount on asset retirement obligations	235				368				14				—				617
General and administrative	79,317				7,487				2,638				—				89,442
Interest	26,673				26,328				—				(26,326		)		26,675
Total costs and expenses	116,975				62,413				10,516				(26,326		)		163,578
Income (loss) before income taxes	(161,826		)		(85,748		)		3,580				43,080				(200,914		)
Income tax benefit	(21,538		)		(42,160		)		—				—				(63,698		)
Income (loss) before discontinued operations	(140,288		)		(43,588		)		3,580				43,080				(137,216		)
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
	125,104				—				(3,072		)		—				122,032
Net income (loss)	$	(15,184	)		$	(43,588	)		$	508			$	43,080			$	(15,184	)

138

EXCO Resources, Inc.
Consolidating statement of operations
For the 90 day period ended December 31, 2005

(in thousands)	Resources				Guarantor subsidiaries				Non-guarantor subsidiaries			Eliminations				Consolidated
Revenues:
Oil and natural gas sales		$	8,463			$	53,212			$	8,386		$	—			$	70,061
Derivative financial instruments		2,856				(3,112		)		—			—				(256		)
Other income (loss)		7,929				408				112			(6,075		)		2,374
Equity earnings of subsidiaries		22,054				—				—			(21,217		)		837
Total revenues		41,302				50,508				8,498			(27,292		)		73,016
Costs and expenses:
Oil and natural gas production		1,784				5,908				1,257			—				8,949
Depreciation, depletion and amortization		1,869				9,623				2,579			—				14,071
Accretion of discount on asset retirement obligations		70				147				9			—				226
General and administrative		4,948				381				1,046			—				6,375
Interest		19,413				6,076				—			(6,075		)		19,414
Total costs and expenses.		28,084				22,135				4,891			(6,075		)		49,035
Income (loss) before income taxes		13,218				28,373				3,607			(21,217		)		23,981
Income tax expense (benefit)		(3,132		)		10,763				—			—				7,631
Net income (loss)		$	16,350			$	17,610			$	3,607		$	(21,217	)		$	16,350

139

EXCO Resources, Inc.
Consolidating statement of operations
For the year ended December 31, 2006

(in thousands)	Resources		Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations				Consolidated
Revenues:
Oil and natural gas sales	$	29,450		$	207,761		$	118,569		$	—			$	355,780
Derivative financial instruments	40,994			132,122			25,548			—				198,664
Other income (loss)	29,862			7,007			2,004			(33,868		)		5,005
Equity in earnings of subsidiaries	147,498			—			—			(145,905		)		1,593
Total revenues	247,804			346,890			146,121			(179,773		)		561,042
Costs and expenses:
Oil and natural gas production	8,279			32,338			28,257			—				68,874
Depreciation, depletion and amortization	9,393			71,086			55,243			—				135,722
Accretion of discount on asset retirement obligations	252			1,414			348			—				2,014
General and administrative	21,339			11,312			8,555			—				41,206
Interest	52,576			19,716			46,447			(33,868		)		84,871
Total costs and expenses	91,839			135,866			138,850			(33,868		)		332,687
Income before income taxes	155,965			211,024			7,271			(145,905		)		228,355
Income tax expense	17,011			72,390			—			—				89,401
Income from operations	$	138,954		$	138,634		$	7,271		$	(145,905	)		$	138,954

140

EXCO Resources, Inc.
Consolidating statement of cash flow
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	$	114			$	62,989			$	55,425			$	—		$	118,528
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(15,547		)		(77,100		)		(46,874		)		—			(139,521		)
Proceeds from dispositions of property and equipment.	47,364				4,501				—				—			51,865
Acquisition of North Coast Energy, Inc., net of cash acquired.	(225,562		)		10,429				—				—			(215,133		)
Advances/investments with affiliates.	(177,607		)		6,653				170,954				—
Proceeds from sale of marketable securities	1,296				—				—				—			1,296
Net cash used in investing activities of discontinued operations.	—				—				(79,983		)		—			(79,983		)
Net cash provided by (used in) investing activities	(370,056		)		(55,517		)		44,097				—			(381,476		)
Financing Activities:
Proceeds from long-term debt	546,350				—				—				—			546,350
Payments on long-term debt	(158,070		)		—				—				—			(158,070		)
Principal and interest on notes receivable-employees	256				—				—							256
Deferred financing costs and other	(13,431		)		—				—				—			(13,431		)
Net cash used in financing activities of discontinued operations	—				—				(91,397		)		—			(91,397		)
Net cash provided by (used in) financing activities	375,105				—				(91,397		)		—			283,708
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 the beginning of the period	3,372				—				3,961				—			7,333
Cash at end of period, including cash of discontinued operations	$	8,535			$	7,472			$	10,401			$	—		$	26,408

141

EXCO Resources, Inc.
Consolidating statement of cash flow
For the 275 day period ended October 2, 2005

(in thousands)	Resources			Guarantor subsidiaries				Non- guarantor subsidiaries				Eliminations			Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(76,249	)		$	7,014			$	(11,887	)		$	—		$	(81,122	)
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	3,987				(112,423		)		(42,708		)		—			(151,144		)
Proceeds from dispositions of oil and natural gas properties.	(160		)		46,170				—				—			46,010
Proceeds from sale of Addison	444,812				—				(1,415		)					443,397
Advances/investments with affiliates	(58,732		)		72,282				(13,550		)		—			—
Proceeds from sales of marketable securities	59				—				—				—			59
Net cash used in investing activities of discontinued operations.	—				—				(442		)		—			(442		)
Net cash provided by (used in) investing activities	389,966				6,029				(58,115		)		—			337,880
Financing Activities:
Proceeds from long-term debt	41,300				—				—				—			41,300
Payments on long-term debt	(148,247		)		—				—				—			(148,247		)
Principal and interest on notes receivable-employees.	311				—								—			311
Net cash used in financing of discontinued operations.	—				—				59,601				—			59,601
Net cash provided by (used in) financing activities	(106,636		)		—				59,601				—			(47,035		)
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

142

EXCO Resources, Inc.
Consolidating statement of cash flow
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	$	(19,063	)		$	21,021			$	6,219			$	—		$	8,177
Investing Activities:
Investment in TXOK Acquisition, Inc.	(20,000		)		—				—				—			(20,000		)
Additions to oil and natural gas properties, gathering systems and equipment	(1,153		)		(5,601		)		(6,453		)		—			(13,207		)
Proceeds from dispositions of oil and natural gas properties	(145		)		(248		)		—				—			(393		)
Advances from related parties	20,000				—				—				—			20,000
Other investing activities	263				(234		)		234				—			263
Net cash used in investing activities	(1,035		)		(6,083		)		(6,219		)		—			(13,337		)
Financing Activities:
Proceeds from long-term debt	9,999				—				—				—			9,999
Payments on long-term debt	(15,279		)		—				—				—			(15,279		)
Principal and interest on notes receivable - employees	1,262				—				—				—			1,262
Net cash used in financing activities	(4,018		)		—				—				—			(4,018		)
Net increase (decrease) in cash	(24,116		)		14,938				—				—			(9,178		)
Cash at the beginning of the period	215,616				20,515				—				—			236,131
Cash at end of period	$	191,500			$	35,453			$	—			$	—		$	226,953

143

EXCO Resources, Inc.
Consolidating statement of cash flow
For the year ended December 31, 2006

								Non-
				Guarantor				guarantor
(in thousands)	Resources			subsidiaries				subsidiaries			Eliminations			Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(14,371	)		$	183,679		$	58,351			$	—	$	227,659
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(59,507		)		(197,940		)	(176,719		)		—		(434,166		)
Proceeds from dispositions of oil and natural gas properties	140				4,566			1,118				—		5,824
Cash acquired in acquisition of TXOK Acquisition, Inc.	—				32,261			—				—		32,261
Advance to TXOK Acquisition, Inc. for preferred stock redemption	—				(158,750		)	—				—		(158,750		)
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired	—				(61,776		)	—				—		(61,776		)
Acquisition of Winchester Energy Company, Ltd., net of cash acquired	—				—			(1,094,910		)		—		(1,094,910		)
Advances/investments with affiliates	(177,305		)		252,867			(75,562		)		—		—
Advance payment on Vernon Assets	(80,000		)		—			—				—		(80,000		)
Net cash used in investing activities	(316,672		)		(128,772		)	(1,346,073		)		—		(1,791,517		)
Financing Activities:
Proceeds from long—term debt	583,000				—			1,301,250				—		1,884,250
Payments on long—term debt	(1,102,751		)		(13,098		)	(11,000		)		—		(1,126,849		)
Payments of hedges in conjunction with Power Gas Marketing & Transmission, Inc. acquisition	—				(38,098		)	—				—		(38,098		)
Proceeds from issuance of common stock, net	657,381				—			—				—		657,381
Deferred financing costs and other	(1,117		)		—			(15,840		)		—		(16,957		)
Net cash provided by (used in) financing activities	136,513				(51,196		)	1,274,410				—		1,359,727
Net increase (decrease) in cash	(194,530		)		3,711			(13,312		)		—		(204,131		)
Cash at the beginning of the period	191,499				12,075			23,379				—		226,953
Cash at end of period	$	(3,031	)		$	15,786		$	10,067			$	—	$	22,822

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22.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)	Amount
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
2006:
Proved property acquisition costs(3)	$	1,416,834
Unproved property acquisition costs(4)	215,552
Total property acquisition costs	1,632,386
Development and exploration costs(2)	214,283
Capitalized asset retirement costs	21,681
Depreciation, depletion and amortization per Boe	$	16.44
Depreciation, depletion and amortization per Mcfe	$	2.74

(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.

(3)   Includes $489.1 million, $123.0 million and $583.7 million allocated to proved oil and natural gas properties in connection with the TXOK, PGMT and Winchester acquisitions, respectively.

(4)   Includes $60.8 million, $0.4 million and $154.3 million allocated to unproved oil and natural gas properties in connection with the TXOK, PGMT and Winchester acquisitions, respectively.

We retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil and natural gas 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

145

undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of our reserves are located onshore in the continental United States of America.

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 unproved 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

			Natural
	Oil		Gas		NGLs
(in thousands)	(Bbls)		(Mcf)		(Bbls)(1)			Mcfe(2)
December 31, 2003	10,473		155,630			822		223,400
Purchase of reserves in place	1,651		229,837			—		239,743
New discoveries and extensions	545		20,807			18		24,185
Revisions of previous estimates	(369	)	1,447			43		(509	)
Production	(638	)	(18,860	)		(60	)	(23,048	)
Sales of reserves in place	(4,426	)	(27,469	)		(613	)	(57,703	)
December 31, 2004	7,236		361,392			210		406,068
Purchase of reserves in place	60		59,780			—		60,140
New discoveries and extensions	349		30,834			—		32,928
Revisions of previous estimates	11		(12,608	)		(190	)	(13,682	)
Production	(491	)	(20,482	)		(20	)	(23,548	)
Sales of reserves in place	(343	)	(17,886	)		—		(19,944	)
December 31, 2005	6,822		401,030			—		441,962
Purchase of reserves in place	8,775		723,427			—		776,077
New discoveries and extensions	2,018		80,832			—		92,940
Revisions of previous estimates	(487	)	(33,467	)		—		(36,389	)
Production	(916	)	(44,123	)		—		(49,619	)
Sales of reserves in place.	(57	)	(1,097	)		—		(1,439	)
December 31, 2006	16,155		1,126,602			—		1,223,532

Estimated Quantities of Proved Developed Reserves

		Natural
	Oil	Gas	NGLs
(in thousands)	(Bbls)	(Mcf)	(Bbls) (1)		Mcfe (2)
December 31, 2004	6,021	318,292		210	355,678
December 31, 2005	5,527	321,716		—	354,878
December 31, 2006	11,290	665,263		—	733,003

(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.

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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 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.

Standardized Measure of Discounted Future Net Cash Flows

(in thousands)	Amount
Year ended December 31, 2004:
Future cash inflows	$	2,589,656
Future production, development and abandonment costs	795,140
Future income taxes	588,897
Future net cash flows	1,205,619
Discount of future net cash flows at 10% per annum	731,882
Standardized measure of discounted future net cash flows	$	473,737
Year ended December 31, 2005:
Future cash inflows	$	4,334,629
Future production, development and abandonment costs	1,148,283
Future income taxes	1,097,606
Future net cash flows	2,088,740
Discount of future net cash flows at 10% per annum.	1,265,441
Standardized measure of discounted future net cash flows(1)	$	823,299
Year ended December 31, 2006:
Future cash inflows	$	7,173,640
Future production, development and abandonment costs	3,397,690
Future income taxes	721,154
Future net cash flows	3,054,796
Discount of future net cash flows at 10% per annum	1,743,021
Standardized measure of discounted future net cash flows	$	1,311,775

During recent years, prices paid for oil and natural gas have fluctuated significantly. The spot prices at December 31, 2004, 2005 and 2006 used in the above table, were $43.33, $61.03 and $60.82 per Bbl of oil, respectively, and $6.18, $10.08 and $5.64 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials.

147

The following are the principal sources of change in the Standardized Measure:

(in thousands)
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	84,388
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	11,624
Revisions of previous quantity estimates	(22,714		)
Sales of reserves in place	(81,485		)
Purchase of reserves in place	320,788
Accretion of discount before income taxes	62,096
Changes in timing, foreign currency translation and other	(48,243		)
Net change in income taxes	(35,833		)
Net change	$	247,731
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	511,666
Extensions and discoveries, net of future development and production costs	87,239
Development costs during the period	53,094
Changes in estimated future development costs	(58,997		)
Revisions of previous quantity estimates	(21,895		)
Sales of reserves in place	(29,363		)
Purchase of reserves in place	117,572
Accretion of discount before income taxes	69,849
Changes in timing, foreign currency translation and other	(7,344		)
Net change in income taxes	(200,484		)
Net change	$	349,562
Year ended December 31, 2006:
Sales and transfers of oil and natural gas produced, net of production costs	(286,906		)
Net changes in prices and production costs	(541,139		)
Extensions and discoveries, net of future development and production costs	96,494
Development costs during the period	194,312
Changes in estimated future development costs	(140,061		)
Revisions of previous quantity estimates	(108,658		)
Sales of reserves in place	(4,298		)
Purchase of reserves in place	991,548
Accretion of discount before income taxes	124,395
Changes in timing, foreign currency translation and other	23,900
Net change in income taxes	138,889
Net change	$	488,476

148

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)
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 costs	272
Capitalized asset retirement costs	—
Depreciation, depletion and amortization per Boe	$	7.49
Depreciation, depletion and amortization per Mcfe	$	1.16

We 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.

149

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 unproved 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.

Estimated Quantities of Proved Reserves

			Natural
	Oil		Gas		NGLs
(in thousands)	(Bbls)		(Mcf)		(Bbls)		Mcfe(1)
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

		Natural
	Oil	Gas	NGLs
(in thousands)	(Bbls)	(Mcf)	(Bbls)	Mcfe(1)
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 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.

150

Standardized Measure of Discounted Future Net Cash Flows

(in thousands)
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	$	—

Near month NYMEX futures prices at December 31, 2004 used in the above table was $43.45 per Bbl or oil and $6.15 per Mmbtu of natural gas, adjusted for historical differentials.

Changes in standardized measure—discontinued operations

The following are the principal sources of change in the Standardized Measure:

(in thousands)
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	)

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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), Chief Financial Officer (CFO) and Chief Accounting Officer (CAO), 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, CFO and CAO, the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2006 and concluded our controls were effective.

Prior to September 30, 2006, our management had concluded that our disclosure controls and procedures were not effective due to a material weakness relating to accounting for income taxes. We believe we have taken the necessary steps to remediate the material weakness described below. Before concluding that the material weakness was remediated, management implemented and evaluated its new controls and procedures for income tax provisions and determined that these procedures were operating effectively for two consecutive quarters, an amount of time deemed sufficient to conclude that the material weakness no longer existed.

Material weakness in internal control over financial reporting

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.

Prior to September 30, 2006, our management had concluded that 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. We undertook numerous remedial actions, as described below, to enhance controls.

152

Remediation of material weakness

During 2005 and 2006, the following remedial activities were undertaken to strengthen internal controls to address the material weakness described above:

·we added additional staff to our tax department, as well as a new tax director.

·we changed the process in calculating our quarterly and annual tax provisions and related deferred taxes that streamline and simplify the process, thereby increasing the effectiveness of our tax calculation process.

·we added staff to our financial reporting function with technical expertise to strengthen our deferred tax calculation and reviews.

·we implemented more stringent reviews of the quarterly tax provision.

We believe the aforementioned steps have resolved the open matters related to the material weakness described above for a period of time sufficient to conclude that our controls are now effective.

Changes in internal control over financial reporting

There have been no changes during the quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The acquisition of Winchester on October 2, 2006 has significantly increased the breadth of our operating and control environment. Our pending acquisitions from Anadarko will significantly increase the number of properties we operate and assets that we manage. Management believes its controls are adequate to effectively integrate the Winchester operations into its existing control environment.

At the end of 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.

PART III

ITEM 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.

ITEM 11.EXECUTIVE COMPENSATION

The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to

153

Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLER MATTERS

The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.

154

ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.

PART IV

ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

EXHIBIT NUMBER	Description Of Exhibit
2.1	Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
2.2	First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
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, dated February 8, 2006 and 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, dated February 8, 2006 and 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.

155

EXHIBIT NUMBER	Description Of Exhibit
4.5	Form of 71¤4% Global Note Due 2011.**
4.6	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
4.7	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 Current Report on Form 8-K/A Amendment No. 1, dated February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.
4.8	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.
4.9	Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
4.10	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 its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1	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 Current Report on Form 8-K, dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.
10.2	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.3	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

156

EXHIBIT NUMBER	Description Of Exhibit
10.4	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.5	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.
10.6	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.*
10.7	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.
10.8	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/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.9	Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
10.10	Form of 71¤4% Global Note Due 2011.**
10.11	EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.12	Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.13	Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.14	Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***

157

EXHIBIT NUMBER	Description Of Exhibit
10.15	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 Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.16	Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.17	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 its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.18	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, dated February 8, 2006 and filed February 14, 2006 and incorporated by reference herein.
10.19	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 Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.20	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 Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.21	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 Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.

158

EXHIBIT NUMBER	Description Of Exhibit
10.22	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/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.23	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, dated March 17, 2006 and filed on March 23, 2006 and incorporated by reference herein.
10.24	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.***
10.25	Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.26	Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.27	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.***
10.28	Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
10.29	First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.30	Payment Performance Guaranty, dated July 22, 2006, by and between Progress Fuels Corporation and EXCO Resources, Inc., filed as an exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 24, 2006 and incorporated by reference herein.

159

EXHIBIT NUMBER	Description Of Exhibit
10.31	Senior Revolving Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.32	Senior Term Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.33	First Amendment to Credit Agreement, dated October 2, 2006, among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.34	Amended and Restated Equity Contribution Agreement, dated October 4, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.35	Senior Term Credit Agreement, dated October 2, 2006, as amended and restated as of October 13, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.36	Second Amended and Restated Equity Contribution Agreement, dated October 13, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.37	Second Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
10.38	Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 15, 2007 and filed on January 16, 2007 and incorporated by reference herein.

160

EXHIBIT NUMBER	Description Of Exhibit
10.39	Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.40	Guaranty dated December 22, 2006 by EXCO Resources, Inc. in favor of Anadarko Petroleum Corporation and Anadarko Gathering Company, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.41	Purchase and Sale Agreement by and among EXCO Resources, Inc., Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated February 1, 2007, filed herewith.
10.42	First Amendment to Senior Revolving Credit Agreement effective as of December 31, 2006 among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated March 8, 2007 and filed march 13, 2007 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 its Registration Statement on 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 its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.3	Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
21.1	Subsidiaries of the registrant, filed herewith.
23.1	Consent of KPMG LLP, filed herewith.
23.2	Consent of PricewaterhouseCoopers LLP, filed herewith.
23.3	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.

161

EXHIBIT NUMBER	Description Of Exhibit
31.3	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting 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, Chief Financial Officer and Chief Accounting 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.

162

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 19, 2007	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 19, 2007	/s/ DOUGLAS H. MILLER
	Douglas H. Miller
	Director, Chairman and Chief Executive Officer
	/s/ STEPHEN F. SMITH
	Stephen F. Smith
	Director, Vice Chairman and President
	/s/ J. DOUGLAS RAMSEY
	J. Douglas Ramsey
	Vice President, Chief Financial Officer and Treasurer
	/s/ MARK E. WILSON
	Mark E. Wilson
	Vice President, Chief Accounting Officer and Controller
	/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

163

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.

164

Index to Exhibits

	EXHIBIT NUMBER	Description Of Exhibit
2.1		Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
2.2		First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
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, dated February 8, 2006 and 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, dated February 8, 2006 and 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		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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
4.7		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 Current Report on Form 8-K/A Amendment No. 1, dated February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.

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4.8	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.
4.9	Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
4.10	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 its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1	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 Current Report on Form 8-K, dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.
10.2	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.3	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.4	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 Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.5	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.
10.6	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.*
10.7	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.

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10.8	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/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.9	Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
10.10	Form of 71¤4% Global Note Due 2011.**
10.11	EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.12	Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.13	Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.14	Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.15	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 Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.16	Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.17	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 its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.18	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, dated February 8, 2006 and filed February 14, 2006 and incorporated by reference herein.

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10.19	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 Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.20	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 Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.21	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 Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.22	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/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.23	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, dated March 17, 2006 and filed on March 23, 2006 and incorporated by reference herein.
10.24	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.***
10.25	Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.26	Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.27	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.***

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10.28	Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
10.29	First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.30	Payment Performance Guaranty, dated July 22, 2006, by and between Progress Fuels Corporation and EXCO Resources, Inc., filed as an exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 24, 2006 and incorporated by reference herein.
10.31	Senior Revolving Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.32	Senior Term Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.33	First Amendment to Credit Agreement, dated October 2, 2006, among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.34	Amended and Restated Equity Contribution Agreement, dated October 4, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.35	Senior Term Credit Agreement, dated October 2, 2006, as amended and restated as of October 13, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.36	Second Amended and Restated Equity Contribution Agreement, dated October 13, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.

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10.37	Second Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
10.38	Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 15, 2007 and filed on January 16, 2007 and incorporated by reference herein.
10.39	Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.40	Guaranty dated December 22, 2006 by EXCO Resources, Inc. in favor of Anadarko Petroleum Corporation and Anadarko Gathering Company, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.41	Purchase and Sale Agreement by and among EXCO Resources, Inc., Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated February 1, 2007, filed herewith.
10.42	First Amendment to Credit Agreement effective as of December 31, 2006 among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated March 8, 2007 and filed March 13, 2007 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 its Registration Statement on 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 its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.3	Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
21.1	Subsidiaries of the registrant, filed herewith.
23.1	Consent of KPMG LLP, filed herewith.
23.2	Consent of PricewaterhouseCoopers LLP, filed herewith.
23.3	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.

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31.3	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting 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, Chief Financial Officer and Chief Accounting 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.

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EX-10.25

Exhibit 10.25

INCENTIVE STOCK OPTION AGREEMENT

THE EXCO RESOURCES, INC.
2005 LONG-TERM INCENTIVE PLAN

1.             Grant of Option.  Pursuant to the EXCO Resources, Inc. 2005 Long-Term Incentive Plan (the “Plan”) for key employees of EXCO Resources, Inc., a Texas corporation (the “Company”), the Company grants to

_________________________
(the “Participant”),

who is an employee of the Company, an option to purchase shares of Common Stock, par value $.001 per share (“Common Stock”), of the Company as follows:

On the date hereof, the Company grants to the Participant an option (the “Option” or “Stock Option”) to purchase                                     (                        ) full shares (the “Optioned Shares”) of Common Stock at an Option Price equal to $                   per share (being the Fair Market Value per share of the Common Stock on this Date of Grant or 110% of such Fair Market Value, in the case of a ten percent (10%) or more stockholder as provided in Code Section 422).  The Date of Grant of this Stock Option is                            , 20     .

The “Option Period” shall commence on the Date of Grant and shall expire on the date immediately preceding the tenth (10th) anniversary of the Date of Grant (or the date immediately preceding the fifth (5th) anniversary of the Date of Grant, in the case of a ten percent (10%) or more stockholder as provided in Code Section 422).  The Stock Option is intended to be an Incentive Stock Option.

2.             Subject to Plan.  The Stock Option and its exercise are subject to the terms and conditions of the Plan, and the terms of the Plan shall control to the extent not otherwise inconsistent with the provisions of this Agreement. The capitalized terms used herein that are defined in the Plan shall have the same meanings assigned to them in the Plan.  The Stock Option is subject to any rules promulgated pursuant to the Plan by the Board or the Committee and communicated to the Participant in writing.  In addition, if the Plan previously has not been approved by the Company’s stockholders, the Stock Option is granted subject to such stockholder approval.

3.             Vesting; Time of Exercise.  Except as specifically provided in this Agreement and subject to certain restrictions and conditions set forth in the Plan, the Optioned Shares shall be vested  and exercisable as follows:

a.             Twenty-five percent (25%) of the total Optioned Shares shall be fully vested on the Date of Grant, provided the Participant is employed by the Company or a Subsidiary on that date.

b.             Twenty-five percent (25%) of the total Optioned Shares shall be fully vested on the first anniversary of the Date of Grant, provided the Participant is employed by the Company or a Subsidiary on that date.

c.             An additional twenty-five percent (25%)  of the total Optioned Shares shall be fully vested on the second anniversary of the Date of Grant, provided the Participant is employed by the Company or a Subsidiary on that date.

d.             An additional twenty-five percent (25%)  of the total Optioned Shares shall be shall be fully vested on the third anniversary of the Date of Grant, provided the Participant is employed by the Company or a Subsidiary on that date.

Notwithstanding the above, the Optioned Shares shall be fully vested automatically upon a Change in Control (as defined in Section 2.6 of the Plan) or upon the death of the Participant or the Total and Permanent Disability (as defined in Section 2.41 of the Plan) of the Participant, provided the Participant is still employed by the Company as of the date of one of such specified events.

4.             Term; Forfeiture.

a.             Except as otherwise provided in this Agreement, the unexercised portion of the Stock Option that relates to Optioned Shares which are vested will terminate and be forfeited at the first of the following to occur:

i.              5 p.m. on the date the Option Period terminates;

ii.             5 p.m. on the date which is one hundred eighty (180) days following the date of the Participant’s Termination of Service due to death or Total and Permanent Disability;

iii.            5 p.m. on the date which is ninety (90) days from the date of the Participant’s Retirement;

iv.            5 p.m. on the date of the Participant’s Termination of Service by the Company for cause (as defined herein);

v.             5 p.m. on the date which is thirty (30) days following the date of the Participant’s Termination of Service for any reason not otherwise specified in this Section 4.a.;

vi.            5 p.m. on the date the Company causes any portion of the Option to be forfeited pursuant to Section 7 hereof.

vii.           For purposes hereof, “cause” shall mean that the Participant shall have committed (i) an intentional material act of fraud or embezzlement in connection with his duties in the course of his employment with the Company; (ii) intentional wrongful material damage to property of the Company; or (iii) intentional wrongful disclosure of material secret processes or material confidential information of the Company.  For the purposes of this Agreement, no act, or failure to act, on the part of the Participant shall be deemed “intentional” unless done, or omitted to be done, by the Participant not in good faith and without reasonable belief that his action or omission was in the best interest of the Company.

5.             Who May Exercise.  Subject to the terms and conditions set forth in Sections 3 and 4 above, during the lifetime of the Participant, the Stock Option may be exercised only by the Participant, or by the Participant’s guardian or personal or legal representative.  If the Participant’s Termination of Service is due to

2

his death prior to the date specified in Section 4.a.i. hereof, or Participant dies prior to the termination dates specified in Sections 4.a.i., ii., iii., iv., v. or vi. hereof, and the Participant has not exercised the Stock Option as to the maximum number of vested Optioned Shares as set forth in Section 3 hereof as of the date of death, the following persons may exercise the exercisable portion of the Stock Option on behalf of the Participant at any time prior to the earliest of the dates specified in Section 4 hereof:  the personal representative of his estate, or the person who acquired the right to exercise the Stock Option by bequest or inheritance or by reason of the death of the Participant; provided that the Stock Option shall remain subject to the other terms of this Agreement, the Plan, and applicable laws, rules, and regulations.

6.             No Fractional Shares.  The Stock Option may be exercised only with respect to full shares, and no fractional share of stock shall be issued.

7.             Manner of Exercise.  Subject to such administrative regulations as the Committee may from time to time adopt, the Stock Option may be exercised by the delivery of written notice to the Committee setting forth the number of shares of Common Stock with respect to which the Stock Option is to be exercised, the date of exercise thereof (the “Exercise Date”) which shall be at least three (3) days after giving such notice unless an earlier time shall have been mutually agreed upon, and whether the Optioned Shares to be exercised will be considered as deemed granted under an Incentive Stock Option as provided in Section 11.  On the Exercise Date, the Participant shall deliver to the Company consideration with a value equal to the total Option Price of the shares to be purchased, payable as follows:  (a) cash, check, bank draft, or money order payable to the order of the Company, (b) Common Stock (including Restricted Stock) owned by the Participant on the Exercise Date, valued at its Fair Market Value on the Exercise Date, and which the Participant has not acquired from the Company within six (6) months prior to the Exercise Date; provided, that the six (6)-month holding requirement shall only apply to a Reporting Participant at any time following an IPO, (c) if the Company has completed an IPO, by delivery (including by FAX) to the Company or its designated agent of an executed irrevocable option exercise form together with irrevocable instructions from the Participant to a broker or dealer, reasonably acceptable to the Company, to sell certain of the shares of Common Stock purchased upon exercise of the Stock Option or to pledge such shares as collateral for a loan and promptly deliver to the Company the amount of sale or loan proceeds necessary to pay such purchase price, and/or (d) in any other form of valid consideration that is acceptable to the Committee in its sole discretion.  In the event that shares of Restricted Stock are tendered as consideration for the exercise of a Stock Option, a number of shares of Common Stock issued upon the exercise of the Stock Option equal to the number of shares of Restricted Stock used as consideration therefor shall be subject to the same restrictions and provisions as the Restricted Stock so tendered.

Upon payment of all amounts due from the Participant, the Company shall cause certificates for the Optioned Shares then being purchased to be delivered to the Participant (or the person exercising the Participant’s Stock Option in the event of his death) at its principal business office within ten (10) business days after the Exercise Date. The obligation of the Company to deliver shares of Common Stock shall, however, be subject to the condition that if at any time the Company shall determine in its discretion that the listing, registration, or qualification of the Stock Option or the Optioned Shares upon any securities exchange or under any state or federal law, or the consent or approval of any governmental regulatory body, is necessary as a condition of, or in connection with, the Stock Option or the issuance or purchase of shares of Common Stock thereunder, then the Stock Option may not be exercised in whole or in part unless such listing, registration, qualification, consent, or approval shall have been effected or obtained free of any conditions not reasonably acceptable to the Committee.

3

If the Participant fails to pay for any of the Optioned Shares specified in such notice or fails to accept delivery thereof, then the Stock Option, and right to purchase such Optioned Shares may be forfeited by the Company.

8.             Nonassignability.  The Stock Option is not assignable or transferable by the Participant except by will or by the laws of descent and distribution.

9.             Rights as Stockholder.  The Participant will have no rights as a stockholder with respect to any shares covered by the Stock Option until the issuance of a certificate or certificates to the Participant for the Optioned Shares.  The Optioned Shares shall be subject to the terms and conditions of this Agreement regarding such Optioned Shares.  Except as otherwise provided in Section 10 hereof, no adjustment shall be made for dividends or other rights for which the record date is prior to the issuance of such certificate or certificates.

10.           Adjustment of Number of Optioned Shares and Related Matters.  The number of shares of Common Stock covered by the Stock Option, and the Option Prices thereof, shall be subject to adjustment in accordance with Articles 11 - 13 of the Plan.

11.           Incentive Stock Option.  Subject to the provisions of the Plan, this Stock Option is an Incentive Stock Option.  To the extent the number of Optioned Shares exceeds the limit set forth in Section 6.3 of the Plan, such Optioned Shares shall be deemed granted pursuant to a Nonqualified Stock Option.  Unless otherwise indicated by the Participant in the notice of exercise pursuant to Section 7, upon any exercise of this Stock Option, the number of exercised Optioned Shares that shall be deemed to be exercised pursuant to an Incentive Stock Option shall equal the total number of Optioned Shares so exercised multiplied by a fraction, (i) the numerator of which is the number of unexercised Optioned Shares that could then be exercised pursuant to an Incentive Stock Option and (ii) the denominator of which is the then total number of unexercised Optioned Shares.

12.           Disqualifying Disposition. In the event that Common Stock acquired upon exercise of this Stock Option is disposed of by the Participant in a “Disqualifying Disposition,” such Participant shall notify the Company in writing within thirty (30) days after such disposition of the date and terms of such disposition.  For purposes hereof, “Disqualifying Disposition” shall mean a disposition of Common Stock that is acquired upon the exercise of this Stock Option (and that is not deemed granted pursuant to a Nonqualified Stock Option under Section 11) prior to the expiration of either two years from the Date of Grant of this Stock Option or one year from the transfer of shares to the Participant pursuant to the exercise of this Stock Option.

13.           [Reserved]

14.           Voting.  The Participant, as record holder of some or all of the Optioned Shares following exercise of this Stock Option, has the exclusive right to vote, or consent with respect to, such Optioned Shares until such time as the Optioned Shares are transferred in accordance with this Agreement; provided, however, that this Section shall not create any voting right where the holders of such Optioned Shares otherwise have no such right.

15.           Community Property.  Each spouse individually is bound by, and such spouse’s interest, if any, in any Optioned Shares is subject to, the terms of this Agreement.  Nothing in this Agreement shall create a community property interest where none otherwise exists.

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16.           Dispute Resolution.

a.             Arbitration.  All disputes and controversies of every kind and nature between any parties hereto arising out of or in connection with this Agreement or the transactions described herein as to the construction, validity, interpretation or meaning, performance, non-performance, enforcement, operation or breach, shall be submitted to arbitration pursuant to the following procedures:

i.              After a dispute or controversy arises, any party may, in a written notice delivered to the other parties to the dispute, demand such arbitration.  Such notice shall designate the name of the arbitrator (who shall be an impartial person) appointed by such party demanding arbitration, together with a statement of the matter in controversy.

ii.             Within 30 days after receipt of such demand, the other parties shall, in a written notice delivered to the first party, name such parties’ arbitrator (who shall be an impartial person).  If such parties fail to name an arbitrator, then the second arbitrator shall be named by the American Arbitration Association (the “AAA”).  The two arbitrators so selected shall name a third arbitrator (who shall be an impartial person) within 30 days, or in lieu of such agreement on a third arbitrator by the two arbitrators so appointed, the third arbitrator shall be appointed by the AAA.  If any arbitrator appointed hereunder shall die, resign, refuse or become unable to act before an arbitration decision is rendered, then the vacancy shall be filled by the method set forth in this Section for the original appointment of such arbitrator.

iii.            Each party shall bear its own arbitration costs and expenses.  The arbitration hearing shall be held in Dallas, Texas at a location designated by a majority of the arbitrators.  The Commercial Arbitration Rules of the American Arbitration Association shall be incorporated by reference at such hearing and the substantive laws of the State of Texas (excluding conflict of laws provisions) shall apply.

iv.            The arbitration hearing shall be concluded within ten (10) days unless otherwise ordered by the arbitrators and the written award thereon shall be made within fifteen (15) days after the close of submission of evidence.  An award rendered by a majority of the arbitrators appointed pursuant to this Agreement shall be final and binding on all parties to the proceeding, shall resolve the question of costs of the arbitrators and all related matters, and judgment on such award may be entered and enforced by either party in any court of competent jurisdiction.

v.             Except as set forth in Section 16.b., the parties stipulate that the provisions of this Section shall be a complete defense to any suit, action or proceeding instituted in any federal, state or local court or before any administrative tribunal with respect to any controversy or dispute arising out of this Agreement or the transactions described herein.  The arbitration provisions hereof shall, with respect to such controversy or dispute, survive the termination or expiration of this Agreement.

No party to an arbitration may disclose the existence or results of any arbitration hereunder without the prior written consent of the other parties; nor will any party to an arbitration disclose to any third party any confidential information disclosed by any other party to an arbitration in the course of an arbitration hereunder without the prior written consent of such other party.

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b.             Emergency Relief.  Notwithstanding anything in this Section 16 to the contrary, any party may seek from a court any provisional remedy that may be necessary to protect any rights or property of such party pending the establishment of the arbitral tribunal or its determination of the merits of the controversy or to enforce a party’s rights under Section 16.

17.           Participant’s Representations.  Notwithstanding any of the provisions hereof, the Participant hereby agrees that he will not exercise the Stock Option granted hereby, and that the Company will not be obligated to issue any shares to the Participant hereunder, if the exercise thereof or the issuance of such shares shall constitute a violation by the Participant or the Company of any provision of any law or regulation of any governmental authority.  Any determination in this connection by the Company shall be final, binding, and conclusive.  The obligations of the Company and the rights of the Participant are subject to all applicable laws, rules, and regulations.

18.           Investment Representation.  Unless the Common Stock is issued to the Participant in a transaction registered under applicable federal and state securities laws, by his execution hereof, the Participant represents and warrants to the Company that all Common Stock which may be purchased hereunder will be acquired by the Participant for investment purposes for his own account and not with any intent for resale or distribution in violation of federal or state securities laws.  Unless the Common Stock is issued to the Participant in a transaction registered under the applicable federal and state securities laws, all certificates issued with respect to the Common Stock shall bear an appropriate restrictive investment legend and shall be held indefinitely, unless they are subsequently registered under the applicable federal and state securities laws or the Participant obtains an opinion of counsel, in form and substance satisfactory to the Company and its counsel, that such registration is not required.

19.           Legend.  The following legend shall be placed on all certificates representing Optioned Shares:

On the face of the certificate:

“Transfer of this stock is restricted in accordance with conditions printed on the reverse of this certificate.”

On the reverse:

“The shares of stock evidenced by this certificate are subject to and transferable only in accordance with that certain EXCO Resources, Inc. 2005 Long-Term Incentive Plan, a copy of which is on file at the principal office of the Company in Dallas, Texas.  No transfer or pledge of the shares evidenced hereby may be made except in accordance with and subject to the provisions of said Plan.  By acceptance of this certificate, any holder, transferee or pledge hereof agrees to be bound by all of the provisions of said Plan.”

All Optioned Shares and shares into which Optioned Shares may be converted which are owned by the Participant shall be subject to the terms of this Agreement and shall be represented by a certificate or certificates bearing the foregoing legend.

20.           [Reserved]

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21.           Participant’s Acknowledgments.  The Participant acknowledges receipt of a copy of the Plan, which is annexed hereto, and represents that he or she is familiar with the terms and provisions thereof, and hereby accepts this Option subject to all the terms and provisions thereof. The Participant hereby agrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee or the Board, as appropriate, upon any questions arising under the Plan or this Agreement.

22.           Law Governing.  This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas (excluding any conflict of laws rule or principle of Texas law that might refer the governance, construction, or interpretation of this agreement to the laws of another state).

23.           No Right to Continue Service or Employment.  Nothing herein shall be construed to confer upon the Participant the right to continue in the employ or to provide services to the Company or any Subsidiary, whether as an employee or as a consultant or as an Outside Director, or interfere with or restrict in any way the right of the Company or any Subsidiary to discharge the Participant as an employee, consultant or Outside Director at any time.

24.           Legal Construction.  In the event that any one or more of the terms, provisions, or agreements that are contained in this Agreement shall be held by a Court of competent jurisdiction to be invalid, illegal, or unenforceable in any respect for any reason, the invalid, illegal, or unenforceable term, provision, or agreement shall not affect any other term, provision, or agreement that is contained in this Agreement and this Agreement shall be construed in all respects as if the invalid, illegal, or unenforceable term, provision, or agreement had never been contained herein.

25.           Covenants and Agreements as Independent Agreements. Each of the covenants and agreements that is set forth in this Agreement shall be construed as a covenant and agreement independent of any other provision of this Agreement.  The existence of any claim or cause of action of the Participant against the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants and agreements that are set forth in this Agreement.

26.           Entire Agreement.  This Agreement together with the Plan supersede any and all other prior understandings and agreements, either oral or in writing, between the parties with respect to the subject matter hereof and constitute the sole and only agreements between the parties with respect to the said subject matter.  All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement.  Each party to this Agreement acknowledges that no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement or the Plan and that any agreement, statement or promise that is not contained in this Agreement or the Plan shall not be valid or binding or of any force or effect.

27.           Parties Bound.  The terms, provisions, and agreements that are contained in this Agreement shall apply to, be binding upon, and inure to the benefit of the parties and their respective heirs, executors, administrators, legal representatives, and permitted successors and assigns, subject to the limitation on assignment expressly set forth herein.  No person or entity shall be permitted to acquire any Optioned Shares without first executing and delivering an agreement in the form satisfactory to the Company making such person or entity subject to the restrictions on transfer contained herein.

28.           Modification.  No change or modification of this Agreement shall be valid or binding upon the parties unless the change or modification is in writing and signed by the parties.  Notwithstanding the preceding sentence, the Company may amend the Plan or revoke this Stock Option to the extent permitted by the Plan.

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29.           Headings.  The headings that are used in this Agreement are used for reference and convenience purposes only and do not constitute substantive matters to be considered in construing the terms and provisions of this Agreement.

30.           Gender and Number.  Words of any gender used in this Agreement shall be held and construed to include any other gender, and words in the singular number shall be held to include the plural, and vice versa, unless the context requires otherwise.

31.           Notice.  Any notice required or permitted to be delivered hereunder shall be deemed to be delivered only when actually received by the Company or by the Participant, as the case may be, at the addresses set forth below, or at such other addresses as they have theretofore specified by written notice delivered in accordance herewith:

a.Notice to the Company shall be addressed and delivered as follows:

EXCO Resources, Inc.
12377 Merit Dr., Suite 1700
Dallas, Texas 75251
Attn:  Chief Financial Officer
Facsimile:  (214) 368-2087

b.Notice to the Participant shall be addressed and delivered as set forth on the signature page.

32.           Tax Requirements.  The Participant is hereby advised to consult immediately with his or her own tax advisor regarding the tax consequences of this Agreement, the availability method, and timing for filing an election to include income arising from this Agreement into the Participant’s gross income under Section 83(b) of the Code, and the tax consequences of such election.  By execution of this Agreement, the Participant agrees that if the Participant makes such an election, the Participant shall provide the Company with written notice of such election in accordance with the regulations promulgated under Code Section 83(b).  The Company or, if applicable, any Subsidiary (for purposes of this Section 32, the term “Company” shall be deemed to include any applicable Subsidiary), shall have the right to deduct from all amounts hereunder paid in cash or other form, any Federal, state, local, or other taxes required by law to be withheld in connection with this Award.  The Company may, in its sole discretion, also require the Participant receiving shares of Common Stock issued under the Plan to pay the Company the amount of any taxes that the Company is required to withhold in connection with the Participant’s income arising with respect to this Award.  Such payments shall be required to be made when requested by the Company and may be required to be made prior to the delivery of any certificate representing shares of Common Stock.  Such payment may be made (i) by the delivery of cash to the Company in an amount that equals or exceeds (to avoid the issuance of fractional shares under (iii) below) the required tax withholding obligations of the Company; (ii) if the Company, in its sole discretion, so consents in writing, the actual delivery by the exercising Participant to the Company of shares of Common Stock that the Participant has not acquired from the Company within six (6) months prior to the date of exercise, which shares so delivered have an aggregate Fair Market Value that equals or exceeds (to avoid the issuance of fractional shares under (iii) below) the required tax withholding payment; (iii) if the Company, in its sole discretion, so consents in writing, the Company’s withholding of a number of shares to be delivered upon the exercise of the Stock Option, which shares so withheld have an aggregate fair market value that equals (but does not exceed) the required tax withholding payment; or (iv) any combination of (i), (ii), or (iii). 

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The Company may, in its sole discretion, withhold any such taxes from any other cash remuneration otherwise paid by the Company to the Participant.

* * * * * * * *

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IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant, to evidence his consent and approval of all the terms hereof, has duly executed this Agreement, as of the date specified in Section 1 hereof.

COMPANY:

EXCO RESOURCES, INC.

By:

Name:  J. Douglas Ramsey

Title:  Vice President and Chief Financial Officer

PARTICIPANT:

Signature

Name:

Address:

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EX-10.26

Exhibit 10.26

NONQUALIFIED STOCK OPTION AGREEMENT

THE EXCO RESOURCES, INC.

2005 LONG-TERM INCENTIVE PLAN

1.             Grant of Option.  Pursuant to the EXCO Resources, Inc. 2005 Long-Term Incentive Plan (the “Plan”) for key employees, consultants, and outside directors of EXCO Resources, Inc., a Texas corporation (the “Company”), the Company grants to

(the “Participant”),

an option to purchase shares of Common Stock, par value $.001 per share (“Common Stock”), of the Company as follows:

On the date hereof, the Company grants to the Participant an option (the “Option” or “Stock Option”) to purchase                             (               ) full shares (the “Optioned Shares”) of Common Stock at an Option Price equal to $           per share (this amount must be equal to or greater than the fair market value of the underlying Common Stock on the date this Option is granted).  The Date of Grant of this Stock Option is                               , 20        .

The “Option Period” shall commence on the Date of Grant and shall expire on the date immediately preceding the tenth (10th) anniversary of the Date of Grant.  The Stock Option is a Nonqualified Stock Option.

2.             Subject to Plan.  The Stock Option and its exercise are subject to the terms and conditions of the Plan, and the terms of the Plan shall control to the extent not otherwise inconsistent with the provisions of this Agreement. The capitalized terms used herein that are defined in the Plan shall have the same meanings assigned to them in the Plan.  The Stock Option is subject to any rules promulgated pursuant to the Plan by the Board or the Committee and communicated to the Participant in writing.  In addition, if the Plan previously has not been approved by the Company’s stockholders, the Stock Option is granted subject to such stockholder approval of the Plan.

3.             Vesting; Time of Exercise.  Except as specifically provided in this Agreement and subject to certain restrictions and conditions set forth in the Plan, the Optioned Shares shall be vested  and exercisable as follows:

a.             Twenty-five percent (25%) of the total Optioned Shares shall be fully vested on the Date of Grant, provided the Participant is employed by (or, if the Participant is a Consultant or an Outside Director, is providing services to) the Company or a Subsidiary on that date.

b.             Twenty-five percent (25%) of the total Optioned Shares shall be fully vested on the first anniversary of the Date of Grant, provided the Participant is employed by (or, if the Participant is a Consultant or an Outside Director, is providing services to) the Company or a Subsidiary on that date.

c.             An additional twenty-five percent (25%)  of the total Optioned Shares shall be fully vested on the second anniversary of the Date of Grant, provided the Participant is employed by (or, if the Participant is a Consultant or an Outside Director, is providing services to) the Company or a Subsidiary on that date.

d.             An additional twenty-five percent (25%)  of the total Optioned Shares shall be shall be fully vested on the third anniversary of the Date of Grant, provided the Participant is employed by (or, if the Participant is a Consultant or an Outside Director, is providing services to) the Company or a Subsidiary on that date.

Notwithstanding the above, the Optioned Shares shall be fully vested automatically upon a Change in Control (as defined in Section 2.6 of the Plan) or upon the death of the Participant or the Total and Permanent Disability (as defined in Section 2.41 of the Plan) of the Participant, provided the Participant is still employed by the Company as of the date of one of such specified events.

4.             Term; Forfeiture.

a.             Except as otherwise provided in this Agreement, the unexercised portion of the Stock Option that relates to Optioned Shares which are vested will terminate at the first of the following to occur:

i.              5 p.m. on the date the Option Period terminates;

ii.             5 p.m. on the date which is one hundred eighty (180) days following the date of the Participant’s Termination of Service due to death or Total and Permanent Disability;

iii.            5 p.m. on the date which is ninety (90) days from the date of the Participant’s Retirement;

iv.            5 p.m. on the date of the Participant’s Termination of Service by the Company for cause (as defined herein);

v.             5 p.m. on the date which is thirty (30) days following the date of the Participant’s Termination of Service for any reason not otherwise specified in this Section 4.a.;

vi.            5 p.m. on the date the Company causes any portion of the Option to be forfeited pursuant to Section 7 hereof;

vii.           For purposes hereof, “cause” shall mean that the Participant shall have committed (i) an intentional material act of fraud or embezzlement in connection with his duties in the course of his employment with the Company; (ii) intentional wrongful material damage to property of the Company; or (iii) intentional wrongful disclosure of material secret processes or material confidential information of the Company.  For the purposes of this Agreement, no act, or failure to act, on the part of the Participant shall be deemed “intentional” unless done, or omitted to be done, by the Participant not in good faith and without reasonable belief that his action or omission was in the best interest of the Company.

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5.             Who May Exercise.  Subject to the terms and conditions set forth in Sections 3 and 4 above, during the lifetime of the Participant, the Stock Option may be exercised only by the Participant, or by the Participant’s guardian or personal or legal representative.  If the Participant’s Termination of Service is due to his death prior to the date specified in Section 4.a.i. hereof, or Participant dies prior to the termination dates specified in Sections 4.a.i., ii., iii., iv., v. or vi. hereof, and the Participant has not exercised the Stock Option as to the maximum number of vested Optioned Shares as set forth in Section 3 hereof as of the date of death, the following persons may exercise the exercisable portion of the Stock Option on behalf of the Participant at any time prior to the earliest of the dates specified in Section 4 hereof:  the personal representative of his estate, or the person who acquired the right to exercise the Stock Option by bequest or inheritance or by reason of the death of the Participant; provided that the Stock Option shall remain subject to the other terms of this Agreement, the Plan, and applicable laws, rules, and regulations.

6.             No Fractional Shares.  The Stock Option may be exercised only with respect to full shares, and no fractional share of stock shall be issued.

7.             Manner of Exercise.  Subject to such administrative regulations as the Committee may from time to time adopt, the Stock Option may be exercised by the delivery of written notice to the Committee setting forth the number of shares of Common Stock with respect to which the Stock Option is to be exercised, the date of exercise thereof (the “Exercise Date”) which shall be at least three (3) days after giving such notice unless an earlier time shall have been mutually agreed upon.  On the Exercise Date, the Participant shall deliver to the Company consideration with a value equal to the total Option Price of the shares to be purchased, payable as follows:  (a) cash, check, bank draft, or money order payable to the order of the Company, (b) Common Stock (including Restricted Stock) owned by the Participant on the Exercise Date, valued at its Fair Market Value on the Exercise Date, and which the Participant has not acquired from the Company within six (6) months prior to the Exercise Date; provided, that the six (6)-month holding requirement shall only apply to a Reporting Participant at any time following an IPO, (c) if the Company has completed an IPO, by delivery (including by FAX) to the Company or its designated agent of an executed irrevocable option exercise form together with irrevocable instructions from the Participant to a broker or dealer, reasonably acceptable to the Company, to sell certain of the shares of Common Stock purchased upon exercise of the Stock Option or to pledge such shares as collateral for a loan and promptly deliver to the Company the amount of sale or loan proceeds necessary to pay such purchase price, and/or (d) in any other form of valid consideration that is acceptable to the Committee in its sole discretion.  In the event that shares of Restricted Stock are tendered as consideration for the exercise of a Stock Option, a number of shares of Common Stock issued upon the exercise of the Stock Option equal to the number of shares of Restricted Stock used as consideration therefor shall be subject to the same restrictions and provisions as the Restricted Stock so tendered.

Upon payment of all amounts due from the Participant, the Company shall cause certificates for the Optioned Shares then being purchased to be delivered to the Participant (or the person exercising the Participant’s Stock Option in the event of his death) at its principal business office within ten (10) business days after the Exercise Date. The obligation of the Company to deliver shares of Common Stock shall, however, be subject to the condition that if at any time the Company shall determine in its discretion that the listing, registration, or qualification of the Stock Option or the Optioned Shares upon any securities exchange or under any state or federal law, or the consent or approval of any governmental regulatory body, is necessary as a condition of, or in connection with, the Stock Option or the issuance or purchase of shares of Common Stock thereunder, then the Stock Option may not be exercised in whole or in part unless such listing, registration, qualification, consent, or approval shall have been effected or obtained free of any conditions not reasonably acceptable to the Committee.

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If the Participant fails to pay for any of the Optioned Shares specified in such notice or fails to accept delivery thereof, then the Stock Option, and right to purchase such Optioned Shares may be forfeited by the Company.

8.             Nonassignability.  The Stock Option is not assignable or transferable by the Participant except by will or by the laws of descent and distribution.

9.             Rights as Stockholder.  The Participant will have no rights as a stockholder with respect to any shares covered by the Stock Option until the issuance of a certificate or certificates to the Participant for the Optioned Shares.  The Optioned Shares shall be subject to the terms and conditions of this Agreement regarding such Shares.  Except as otherwise provided in Section 10 hereof, no adjustment shall be made for dividends or other rights for which the record date is prior to the issuance of such certificate or certificates.

10.           Adjustment of Number of Optioned Shares and Related Matters.  The number of shares of Common Stock covered by the Stock Option, and the Option Prices thereof, shall be subject to adjustment in accordance with Articles 11 - 13 of the Plan.

11.           Nonqualified Stock Option.  The Stock Option shall not be treated as an Incentive Stock Option.

12.           [Reserved]

13.           Voting.  The Participant, as record holder of some or all of the Optioned Shares following exercise of this Stock Option, has the exclusive right to vote, or consent with respect to, such Optioned Shares until such time as the Optioned Shares are transferred in accordance with this Agreement; provided, however, that this Section shall not create any voting right where the holders of such Optioned Shares otherwise have no such right.

14.           Community Property.  Each spouse individually is bound by, and such spouse’s interest, if any, in any Optioned Shares is subject to, the terms of this Agreement.  Nothing in this Agreement shall create a community property interest where none otherwise exists.

15.           Dispute Resolution.

a.             Arbitration.           All disputes and controversies of every kind and nature between any parties hereto arising out of or in connection with this Agreement or the transactions described herein as to the construction, validity, interpretation or meaning, performance, non-performance, enforcement, operation or breach, shall be submitted to arbitration pursuant to the following procedures:

i.              After a dispute or controversy arises, any party may, in a written notice delivered to the other parties to the dispute, demand such arbitration.  Such notice shall designate the name of the arbitrator (who shall be an impartial person) appointed by such party demanding arbitration, together with a statement of the matter in controversy.

ii.             Within 30 days after receipt of such demand, the other parties shall, in a written notice delivered to the first party, name such parties’ arbitrator (who shall be an impartial person).  If such parties fail to name an arbitrator, then the second arbitrator shall be named by the American Arbitration Association (the “AAA”).  The two arbitrators so selected

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shall name a third arbitrator (who shall be an impartial person) within 30 days, or in lieu of such agreement on a third arbitrator by the two arbitrators so appointed, the third arbitrator shall be appointed by the AAA.  If any arbitrator appointed hereunder shall die, resign, refuse or become unable to act before an arbitration decision is rendered, then the vacancy shall be filled by the method set forth in this Section for the original appointment of such arbitrator.

iii.            Each party shall bear its own arbitration costs and expenses.  The arbitration hearing shall be held in Dallas, Texas at a location designated by a majority of the arbitrators. The Commercial Arbitration Rules of the American Arbitration Association shall be incorporated by reference at such hearing and the substantive laws of the State of Texas (excluding conflict of laws provisions) shall apply.

iv.            The arbitration hearing shall be concluded within ten (10) days unless otherwise ordered by the arbitrators and the written award thereon shall be made within fifteen (15) days after the close of submission of evidence.  An award rendered by a majority of the arbitrators appointed pursuant to this Agreement shall be final and binding on all parties to the proceeding, shall resolve the question of costs of the arbitrators and all related matters, and judgment on such award may be entered and enforced by either party in any court of competent jurisdiction.

v.             Except as set forth in Section 15.b., the parties stipulate that the provisions of this Section shall be a complete defense to any suit, action or proceeding instituted in any federal, state or local court or before any administrative tribunal with respect to any controversy or dispute arising out of this Agreement or the transactions described herein.  The arbitration provisions hereof shall, with respect to such controversy or dispute, survive the termination or expiration of this Agreement.

No party to an arbitration may disclose the existence or results of any arbitration hereunder without the prior written consent of the other parties; nor will any party to an arbitration disclose to any third party any confidential information disclosed by any other party to an arbitration in the course of an arbitration hereunder without the prior written consent of such other party.

b.             Emergency Relief.  Notwithstanding anything in this Section 15 to the contrary, any party may seek from a court any provisional remedy that may be necessary to protect any rights or property of such party pending the establishment of the arbitral tribunal or its determination of the merits of the controversy or to enforce a party’s rights under Section 15.

16.           Participant’s Representations.  Notwithstanding any of the provisions hereof, the Participant hereby agrees that he will not exercise the Stock Option granted hereby, and that the Company will not be obligated to issue any shares to the Participant hereunder, if the exercise thereof or the issuance of such shares shall constitute a violation by the Participant or the Company of any provision of any law or regulation of any governmental authority.  Any determination in this connection by the Company shall be final, binding, and conclusive.  The obligations of the Company and the rights of the Participant are subject to all applicable laws, rules, and regulations.

17.           Investment Representation.  Unless the Common Stock is issued to him in a transaction registered under applicable federal and state securities laws, by his execution hereof, the Participant represents and warrants to the Company that all Common Stock which may be purchased hereunder will be acquired by the Participant for investment purposes for his own account and not with any intent for resale or distribution in

5

violation of federal or state securities laws.  Unless the Common Stock is issued to him in a transaction registered under the applicable federal and state securities laws, all certificates issued with respect to the Common Stock shall bear an appropriate restrictive investment legend and shall be held indefinitely, unless they are subsequently registered under the applicable federal and state securities laws or the Participant obtains an opinion of counsel, in form and substance satisfactory to the Company and its counsel, that such registration is not required.

18.           Legend.  The following legend shall be placed on all certificates representing Optioned Shares:

On the face of the certificate:

“Transfer of this stock is restricted in accordance with conditions printed on the reverse of this certificate.”

On the reverse:

“The shares of stock evidenced by this certificate are subject to and transferable only in accordance with that certain EXCO Resources, Inc. 2005 Long-Term Incentive Plan, a copy of which is on file at the principal office of the Company in Dallas, Texas.  No transfer or pledge of the shares evidenced hereby may be made except in accordance with and subject to the provisions of said Plan.  By acceptance of this certificate, any holder, transferee or pledge hereof agrees to be bound by all of the provisions of said Plan.”

All Optioned Shares and shares into which Optioned Shares may be converted owned by the Participant shall be subject to the terms of this Agreement and shall be represented by a certificate or certificates bearing the foregoing legend.

19.           [Reserved]

20.           Participant’s Acknowledgments.  The Participant acknowledges receipt of a copy of the Plan, which is annexed hereto, and represents that he or she is familiar with the terms and provisions thereof, and hereby accepts this Option subject to all the terms and provisions thereof. The Participant hereby agrees to accept as binding, conclusive, and final all decisions or interpretations of the Committee or the Board, as appropriate, upon any questions arising under the Plan or this Agreement.

21.           Law Governing.  This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas (excluding any conflict of laws rule or principle of Texas law that might refer the governance, construction, or interpretation of this agreement to the laws of another state).

22.           No Right to Continue Service or Employment.  Nothing herein shall be construed to confer upon the Participant the right to continue in the employ or to provide services to the Company or any Subsidiary, whether as an employee or as a consultant or as an Outside Director, or interfere with or restrict in any way the right of the Company or any Subsidiary to discharge the Participant as an employee, consultant or Outside Director at any time.

23.           Legal Construction.  In the event that any one or more of the terms, provisions, or agreements that are contained in this Agreement shall be held by a Court of competent jurisdiction to be invalid, illegal, or

6

unenforceable in any respect for any reason, the invalid, illegal, or unenforceable term, provision, or agreement shall not affect any other term, provision, or agreement that is contained in this Agreement and this Agreement shall be construed in all respects as if the invalid, illegal, or unenforceable term, provision, or agreement had never been contained herein.

24.           Covenants and Agreements as Independent Agreements. Each of the covenants and agreements that is set forth in this Agreement shall be construed as a covenant and agreement independent of any other provision of this Agreement.  The existence of any claim or cause of action of the Participant against the Company, whether predicated on this Agreement or otherwise, shall not constitute a defense to the enforcement by the Company of the covenants and agreements that are set forth in this Agreement.

25.           Entire Agreement.  This Agreement together with the Plan supersede any and all other prior understandings and agreements, either oral or in writing, between the parties with respect to the subject matter hereof and constitute the sole and only agreements between the parties with respect to the said subject matter.  All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement.  Each party to this Agreement acknowledges that no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement or the Plan and that any agreement, statement or promise that is not contained in this Agreement or the Plan shall not be valid or binding or of any force or effect.

26.           Parties Bound.  The terms, provisions, and agreements that are contained in this Agreement shall apply to, be binding upon, and inure to the benefit of the parties and their respective heirs, executors, administrators, legal representatives, and permitted successors and assigns, subject to the limitation on assignment expressly set forth herein.  No person or entity shall be permitted to acquire any Optioned Shares without first executing and delivering an agreement in the form satisfactory to the Company making such person or entity subject to the restrictions on transfer contained herein.

27.           Modification.  No change or modification of this Agreement shall be valid or binding upon the parties unless the change or modification is in writing and signed by the parties.  Notwithstanding the preceding sentence, the Company may amend the Plan or revoke this Stock Option to the extent permitted by the Plan.

28.           Headings.  The headings that are used in this Agreement are used for reference and convenience purposes only and do not constitute substantive matters to be considered in construing the terms and provisions of this Agreement.

29.           Gender and Number.  Words of any gender used in this Agreement shall be held and construed to include any other gender, and words in the singular number shall be held to include the plural, and vice versa, unless the context requires otherwise.

30.           Notice.  Any notice required or permitted to be delivered hereunder shall be deemed to be delivered only when actually received by the Company or by the Participant, as the case may be, at the addresses set forth below, or at such other addresses as they have theretofore specified by written notice delivered in accordance herewith:

7

a.             Notice to the Company shall be addressed and delivered as follows:

EXCO Resources, Inc.

12377 Merit Dr., Suite 1700

Dallas, Texas 75251

Attn: Chief Financial Officer

Facsimile: (214) 368-2087

b.             Notice to the Participant shall be addressed and delivered as set forth on the signature page.

31.           Tax Requirements.  The Participant is hereby advised to consult immediately with his or her own tax advisor regarding the tax consequences of this Agreement, the availability, method, and timing for filing an election to include income arising from this Agreement into the Participant’s gross income under Section 83(b) of the Code, and the tax consequences of such election.  By execution of this Agreement, the Participant agrees that if the Participant makes such an election, the Participant shall provide the Company with written notice of such election in accordance with the regulations promulgated under Code Section 83(b). The Company or, if applicable, any Subsidiary (for purposes of this Section 31, the term “Company” shall be deemed to include any applicable Subsidiary), shall have the right to deduct from all amounts hereunder paid in cash or other form, any Federal, state, local, or other taxes required by law to be withheld in connection with this Award.  The Company may, in its sole discretion, also require the Participant receiving shares of Common Stock issued under the Plan to pay the Company the amount of any taxes that the Company is required to withhold in connection with the Participant’s income arising with respect to this Award.  Such payments shall be required to be made when requested by the Company and may be required to be made prior to the delivery of any certificate representing shares of Common Stock.  Such payment may be made (i) by the delivery of cash to the Company in an amount that equals or exceeds (to avoid the issuance of fractional shares under (iii) below) the required tax withholding obligations of the Company; (ii) if the Company, in its sole discretion, so consents in writing, the actual delivery by the exercising Participant to the Company of shares of Common Stock other than (A) Restricted Stock, (B) Callable Shares, or (C) Common Stock that the Participant has not acquired from the Company within six (6) months prior to the date of exercise, which shares so delivered have an aggregate Fair Market Value that equals or exceeds (to avoid the issuance of fractional shares under (iii) below) the required tax withholding payment; (iii) if the Company, in its sole discretion, so consents in writing, the Company’s withholding of a number of shares to be delivered upon the exercise of the Stock Option other than shares that will constitute Restricted Stock, which shares so withheld have an aggregate fair market value that equals (but does not exceed) the required tax withholding payment; or (iv) any combination of (i), (ii), or (iii).  The Company may, in its sole discretion, withhold any such taxes from any other cash remuneration otherwise paid by the Company to the Participant.

* * * * * * * *

8

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed by its duly authorized officer, and the Participant, to evidence his consent and approval of all the terms hereof, has duly executed this Agreement, as of the date specified in Section 1 hereof.

COMPANY:
EXCO RESOURCES, INC.
By:
Name:	J. Douglas Ramsey, Ph.D.
Title:	Vice President and Chief Financial Officer
PARTICIPANT:
Signature
Name:
Address:

9

EX-10.41

Exhibit 10.41

EXECUTION COPY

PURCHASE AND SALE AGREEMENT

BY AND AMONG

ANADARKO PETROLEUM CORPORATION,

ANADARKO E&P COMPANY LP,

HOWELL PETROLEUM CORPORATION AND

KERR-MCGEE OIL & GAS ONSHORE LP

AS SELLER

AND

EXCO RESOURCES, INC.

AS PURCHASER

Executed on February 1, 2007

TABLE OF CONTENTS

	PAGE
ARTICLE 1 PURCHASE AND SALE	1
Section 1.1      Purchase and Sale.	1
Section 1.2      Assets.	1
Section 1.3      Excluded Assets.	3
Section 1.4      Effective Time; Proration of Costs and Revenues.	4
Section 1.5      Delivery and Maintenance of Records.	5
ARTICLE 2 PURCHASE PRICE	6
Section 2.1      Purchase Price.	6
Section 2.2      Adjustments to Purchase Price.	6
Section 2.3      Allocation of Purchase Price for Tax Purposes	7
Section 2.4      Deposit	8
ARTICLE 3 TITLE MATTERS	8
Section 3.1      Seller’s Title.	8
Section 3.2      Definition of Defensible Title.	8
Section 3.3      Definition of Permitted Encumbrances.	10
Section 3.4      Notice of Title Defect Adjustments.	11
Section 3.5      Casualty or Condemnation Loss.	14
Section 3.6      Limitations on Applicability.	15
Section 3.7      Government Approvals Respecting Assets.	15
ARTICLE 4 ENVIRONMENTAL MATTERS	16
Section 4.1      Assessment.	16
Section 4.2      NORM, Wastes and Other Substances.	17
Section 4.3      Environmental Defects.	18
Section 4.4      Inspection Indemnity.	19
ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF SELLER	19
Section 5.1      Generally.	19
Section 5.2      Existence and Qualification.	19
Section 5.3      Power.	20
Section 5.4      Authorization and Enforceability.	20
Section 5.5      No Conflicts.	20
Section 5.6      Liability for Brokers’ Fees.	20
Section 5.7      Litigation.	20
Section 5.8      Taxes and Assessments.	21
Section 5.9      Compliance with Laws.	21
Section 5.10    Contracts.	21
Section 5.11    Payments for Hydrocarbon Production.	21

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Section 5.12    Governmental Authorizations.	22
Section 5.13    Preference Rights and Transfer Requirements.	22
Section 5.14    Payout Balances.	22
Section 5.15    Outstanding Capital Commitments.	22
Section 5.16    Imbalances.	22
Section 5.17    Condemnation.	23
Section 5.18    Bankruptcy.	23
Section 5.19    PUHCA/NGA.	23
Section 5.20    Investment Company.	23
Section 5.21    Production Allowables.	23
Section 5.22    Plugging and Abandonment.	24
Section 5.23    Foreign Person.	24
Section 5.24    Collective Bargaining Agreements.	24
ARTICLE 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER	24
Section 6.1      Existence and Qualification.	24
Section 6.2      Power.	24
Section 6.3      Authorization and Enforceability.	25
Section 6.4      No Conflicts.	25
Section 6.5      Liability for Brokers’ Fees.	25
Section 6.6      Litigation.	25
Section 6.7      Financing.	25
Section 6.8      Limitation.	25
Section 6.9      SEC Disclosure.	26
Section 6.10    Bankruptcy.	26
Section 6.11    Qualification.	26
ARTICLE 7 COVENANTS OF THE PARTIES	26
Section 7.1      Access.	26
Section 7.2      Government Reviews.	27
Section 7.3      Notification of Breaches.	28
Section 7.4      Letters-in-Lieu; Assignments; Operatorship.	28
Section 7.5      Public Announcements.	29
Section 7.6      Operation of Business.	29
Section 7.7      Preference Rights and Transfer Requirements.	30
Section 7.8      Tax Matters.	32
Section 7.9      Further Assurances.	33
Section 7.10    Reserved.	33
Section 7.11    Insurance; Financial Information.	33

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Section 7.12    No Solicitation of Transactions.	33
Section 7.13    Transition Services Agreement.	34
Section 7.14    Employees.	34
Section 7.15    Hedges.	34
Section 7.16    Contribution of Oklahoma Assets.	34
Section 7.17    [RESERVED].	35
Section 7.18    Cure of Misrepresentations.	35
Section 7.19    NAGS.	35
ARTICLE 8 CONDITIONS TO CLOSING	35
Section 8.1      Conditions of Seller to Closing.	35
Section 8.2      Conditions of Purchaser to Closing.	36
ARTICLE 9 CLOSING	37
Section 9.1      Time and Place of Closing.	37
Section 9.2      Obligations of Seller at Closing.	37
Section 9.3      Obligations of Purchaser at Closing.	38
Section 9.4      Closing Adjustments.	38
ARTICLE 10 TERMINATION	40
Section 10.1    Termination.	40
Section 10.2    Effect of Termination.	41
Section 10.3    Distribution of Deposit Upon Termination.	41
ARTICLE 11 POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS	41
Section 11.1    Receipts.	41
Section 11.2    Expenses.	42
Section 11.3    Assumed Seller Obligations.	42
Section 11.4    Survival.	43
Section 11.5    Indemnification by Seller.	44
Section 11.6    Indemnification by Purchaser.	44
Section 11.7    Indemnification Proceedings.	45
Section 11.8    Limitations on Indemnities.	46
Section 11.9    Release.	47
Section 11.10  Disclaimers.	47
Section 11.11  Waiver of Trade Practices Acts.	49
Section 11.12  Redhibition Waiver.	49
Section 11.13  Recording.	49

iv

ARTICLE 12 MISCELLANEOUS	50
Section 12.1    Counterparts.	50
Section 12.2    Notice.	50
Section 12.3    Sales or Use Tax Recording Fees and Similar Taxes and Fees.	51
Section 12.4    Expenses.	51
Section 12.5    Change of Name.	51
Section 12.6    Replacement of Bonds, Letters of Credit and Guarantees.	51
Section 12.7    Governing Law and Venue.	52
Section 12.8    Captions.	52
Section 12.9    Waivers.	52
Section 12.10  Assignment.	52
Section 12.11  Entire Agreement.	52
Section 12.12  Amendment.	52
Section 12.13  No Third-Party Beneficiaries.	53
Section 12.14  References.	53
Section 12.15  Construction.	53
Section 12.16  Conspicuousness.	54
Section 12.17  Severability.	54
Section 12.18  Time of Essence.	54
Section 12.19  Affiliate Liability.	54
Section 12.20  Schedules.	54
Section 12.21  Limitation on Damages.	54

v

EXHIBITS

Exhibit “A”	Leases and Mineral Interests
Exhibit “A-1”	Wells, Future Wells and Units
Exhibit “A-2”	Equipment
Exhibit “B”	Conveyance
Exhibit “C”	Indemnity Agreement
Exhibit “D”	Seismic License

SCHEDULES

Schedule 1.2(d)	Contracts
Schedule 1.2(e)	Surface Contracts
Schedule 1.2(g)	Pipelines
Schedule 1.3(e)	Excluded Items
Schedule 1.4	Effective Time; Proration of Costs and Revenues
Schedule 5.7(a)	Party Proceedings
Schedule 5.7(b)	Non-Party Proceedings
Schedule 5.8	Taxes and Assessments
Schedule 5.9	Compliance with Laws
Schedule 5.10	Certain Contract Matters
Schedule 5.11	Hydrocarbon Production Payments
Schedule 5.12	Governmental Authorizations
Schedule 5.13	Preference Rights and Transfer Requirements
Schedule 5.14	Payout Balances
Schedule 5.15	Outstanding Capital Commitments
Schedule 5.16	Imbalances

vi

Schedule 5.22	Plugging and Abandonment
Schedule 7.6	Operation of Business
Schedule 7.15	Hedging Transactions

vii

DEFINITIONS

“1031 Assets” has the meaning set forth in Section 7.8(c).

“actual knowledge” has the meaning set forth in Section 5.1(a).

“Adjusted Purchase Price” shall mean the Purchase Price after calculating and applying the adjustments set forth in Section 2.2.

“Adjustment Period” has the meaning set forth in Section 2.2(a).

“AFE” means authority for expenditure.

“Affiliates” with respect to any Person, means any Person that directly or indirectly controls, is controlled by or is under common control with such Person.  The concept of control, controlling or controlled as used in the aforesaid context means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise.  No Person shall be deemed an Affiliate of any Person by reason of the exercise or existence of rights, interests or remedies under this Agreement.

“Aggregate Benefit Deductible” has the meaning set forth in Section 3.4(j).

“Aggregate Defect Deductible” has the meaning set forth in Section 3.4(j).

“Agreed Accounting Firm” has the meaning set forth in Section 9.4(b).

“Agreed Interest Rate” means the rate of interest published in the Wall Street Journal from time to time, as the one month London Interbank Offered Rate (LIBOR) plus 75 basis points, with adjustments in that rate to be made on the same day as any change in that rate.

“Agreement” means this Purchase and Sale Agreement.

“Allocated Value” has the meaning set forth in Section 3.4(a).

“AEP” has the meaning set forth in the preamble hereto.

“APC” has the meaning set forth in the preamble hereto.

“Assessment” has the meaning set forth in Section 4.1.

“Assets” has the meaning set forth in Section 1.2.

“Assumed Seller Obligations” has the meaning set forth in Section 11.3.

“Audited Financial Statements” has the meaning set forth in Section 7.1(c).

“Business Day” means each calendar day except Saturdays, Sundays, and Federal holidays.

“CERCLA” has the meaning set forth in the definition of Environmental Laws.

“Claim Notice” has the meaning set forth in Section 11.4(b).

viii

“Closing” has the meaning set forth in Section 9.1(a).

“Closing Date” has the meaning set forth in Section 9.1(b).

“Closing Payment” has the meaning set forth in Section 9.4(a).

“Code” means the United States Internal Revenue Code of 1986, as amended.

“Confidentiality Agreement” has the meaning set forth in Section 7.1(a).

“Contracts” has the meaning set forth in Section 1.2(d).

“Conveyance” has the meaning set forth in Section 3.1(b).

“Counterparties” has the meaning set forth in Section 7.15.

“Cure Period” has the meaning set forth in Section 3.4(c).

“Deductible” has the meaning set forth in Section 11.8(a).

“Defensible Title” has the meaning set forth in Section 3.2.

“Deposit” has the meaning set forth in Section 2.4.

“DTPA” has the meaning set forth in Section 11.11(a).

“Earned” has the meaning set forth in Section 1.4(b).

“Effective Time” has the meaning set forth in Section 1.4(a).

“Environmental Claim Date” has the meaning set forth in Section 4.3.

“Environmental Defect” has the meaning set forth in Section 4.3.

“Environmental Defect Amount” has the meaning set forth in Section 4.3.

“Environmental Defect Notice” has the meaning set forth in Section 4.3.

“Environmental Laws” means, as the same may have been amended, any federal, state or local statute, law, regulation, ordinance, rule, order or decree including any rule of common law, relating to (i) the control of any potential pollutant or protection of the environment, including air, water or land, (ii) the generation, handling, treatment, storage, disposal or transportation of waste materials, or (iii) the regulation of or exposure to hazardous, toxic or other substances alleged to be harmful, including, but not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq. (“CERCLA”); the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. (“RCRA”); the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq. the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.S.C. § 136 et seq.; the Occupational Safety and Health Act, 29 U.S.C.

ix

§ 651 et seq.; the Atomic Energy Act, 42 U.S.C. § 2011 et seq.; and all applicable related law, whether local, state, territorial, or national, of any Governmental Body having jurisdiction over the property in question addressing pollution or protection of human health, safety, natural resources or the environment and all regulations implementing the foregoing.  The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Body pursuant to the foregoing.

“Environmental Liabilities” shall mean any and all environmental response costs (including costs of remediation), damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees, and other liabilities incurred or imposed (i) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar act (including settlements) by any Governmental Body to the extent arising out of any violation of, or remedial obligation under, any Environmental Laws which are attributable to the ownership or operation of the Assets prior to the Effective Time or (ii) pursuant to any claim or cause of action by a Governmental Body or other Person for personal injury, property damage, damage to natural resources, remediation or response costs to the extent arising out of any violation of, or any remediation obligation under, any Environmental Laws which is attributable to the ownership or operation of the Assets prior to the Closing.

“Equipment” has the meaning set forth in Section 1.2(f).

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“Event” has the meaning set forth in definition of Material Adverse Effect.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, together with the rules and regulations of the Securities and Exchange Commission promulgated thereunder.

“Excluded Assets” has the meaning set forth in Section 1.3.

“Excluded Seller Obligations” has the meaning set forth in Section 11.3.

“Final Purchase Price” has the meaning set forth in Section 9.4(b).

“Final Settlement Date” has the meaning set forth in Section 9.4(b).

“Fundamental Representations” has the meaning set forth in Section 11.4(a).

“Future Well” means a well to be drilled in the future on a Future Well Location, which (for the purposes of determining Defensible Title thereto and any Title Defects associated therewith pursuant to this Agreement) shall be treated as if such well had been drilled and completed and was in existence at or prior to the Effective Time.

“Future Well Location” means each drilling location identified on Exhibit A-1, subject to any depth restriction set forth in such Exhibit A-1 with respect to such location.

“GAAP” means generally accepted accounting principles in effect in the United States as amended from time to time.

“Governmental Authorizations” has the meaning set forth in Section 5.12.

x

“Governmental Body” or “Governmental Bodies” means any federal, state, local, municipal, or other government; any governmental, regulatory or administrative agency, commission, body, arbitrator or arbitration panel or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

“Hazardous Material” means (i) any “hazardous substance,” as defined by CERCLA, (ii) any “hazardous waste” or “solid waste,” in either case as defined by RCRA, and any analogous state statutes, and any regulations promulgated thereunder, (iii) any solid,  hazardous, dangerous or toxic chemical, material, waste or substance, within the meaning of and regulated by any applicable Environmental Laws, (iv) any radioactive material, including any naturally occurring radioactive material, and any source, special or byproduct material as defined in 42 U.S.C. 2011 et seq. and any amendments or authorizations thereof, (v) any regulated asbestos-containing materials in any form or condition, (vi) any regulated polychlorinated biphenyls in any form or condition, and (vii) petroleum, petroleum hydrocarbons or any fraction or byproducts thereof.

“Hedging Transactions” has the meaning set forth in Section 7.15.

“Howell” has the meaning set forth in the preamble hereto.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

“Hydrocarbons” means oil, gas, casinghead gas, condensate and other gaseous and liquid hydrocarbons or any combination thereof and sulphur and other minerals extracted from or produced with the foregoing.

“Imbalance” or “Imbalances” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Assets, regardless of whether such over-production, under-production, over-delivery under-delivery or similar imbalance arises at the platform, wellhead, pipeline, gathering system, transportation system, processing plant or other location.

“incurred” has the meaning set forth in Section 1.4(b).

“Indemnified Party” has the meaning set forth in Section 11.7(a).

“Indemnifying Party” has the meaning set forth in Section 11.7(a).

“Indemnity Agreement” has the meaning set forth in Section 3.4(d)(ii).

“Independent Expert” has the meaning set forth in Section 4.3.

“Individual Benefit Deductible” has the meaning set forth in Section 3.4(j).

“Individual Environmental Deductible” has the meaning set forth in Section 4.3.

“Individual Title Deductible” has the meaning set forth in Section 3.4(j).

“Invasive Activity” has the meaning set forth in Section 4.1.

“KMOG” has the meaning set forth in the preamble hereto.

xi

“Lands” has the meaning set forth in Section 1.2(a).

“Laws” means all statutes, laws, rules, regulations, ordinances, orders, and codes of Governmental Bodies.

“Leases” has the meaning set forth in Section 1.2(a).

“Like-Kind Exchange” has the meaning set forth Section 7.8(c).

“Losses” means any and all debts, obligations and other liabilities (whether absolute, accrued, contingent, fixed or otherwise, or whether known or unknown, or due or to become due or otherwise), diminution in value, monetary damages, fines, fees, Taxes, penalties, interest obligations, deficiencies, losses and expenses (including amounts paid in settlement, interest, court costs, costs of investigators, reasonable fees and expenses of attorneys, accountants, financial advisors and other experts, and other actual out of pocket expenses incurred in investigating and preparing for or in connection with any Proceeding).

“Lowest Cost Response” means the response required or allowed under Environmental Laws that addresses the condition present at the lowest cost (considered as a whole taking into consideration any material negative impact such response may have on the operations of the relevant assets and any potential material additional costs or liabilities that may likely arise as a result of such response) as compared to any other response that is required or allowed under Environmental Laws.

“Material Adverse Effect” means any change, inaccuracy, circumstance, effect, event, result, occurrence, condition or fact (each an “Event”) (whether or not (i) foreseeable or known as of the date of this Agreement or (ii) covered by insurance) that has had, or could reasonably be expected to have, a material adverse effect on (i) the ownership, operation or value of the Assets, taken as a whole, or (ii) the ability of Seller to consummate the transactions contemplated hereby.  Excluded from such Events for the purposes of determining whether a “Material Adverse Affect” has occurred or could reasonably be expected to occur are (A) Events resulting from entering into this Agreement or the announcement of the transactions contemplated by this Agreement, (B) Events resulting from changes in general market, economic, financial or political conditions or any outbreak of hostilities or war, (C) Events that affect the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally (including changes in commodity prices or general market prices in the Hydrocarbon exploration, production, development, processing, gathering and/or transportation industry generally), and (D) any effect resulting from a change in Laws or regulatory policies.

“Material Contracts” has the meaning set forth in Section 5.10.

“Maximum Indemnity Amount” has the meaning set forth in Section 11.8(a).

“Mineral Interests” has the meaning set forth in Section 1.2(a).

“NAGS” means those certain gathering assets owned by Anadarko Gathering Company that are subject to the NAGS Agreement.

xii

“NAGS Agreement” means that certain Gas Purchase and Sales Contract dated September 1, 1993, between APC and Anadarko Gathering Company, as amended, that is described on Schedule 1.2(d).

“NGA” has the meaning set forth in Section 5.19.

“NGPA” has the meaning set forth in Section 5.19.

“Net Revenue Interest” has the meaning set forth in Section 3.2(a).

“NORM” means naturally occurring radioactive material.

“Notice Period” has the meaning set forth in Section 11.7(a).

“Permitted Encumbrances” has the meaning set forth in Section 3.3.

“Permitted NAGS Buyer” means any of Oneok, Inc., Kinder Morgan, Inc., DCP Midstream Partners, LP or any of their respective wholly-owned subsidiaries.

“Person” means any individual, firm, corporation, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Body or any other entity.

“Personal Property” has the meaning set forth in Section 1.2(g).

“Pipelines” has the meaning set forth in Section 1.2(g).

“Preference Property” has the meaning set forth in Section 7.7(b).

“Preference Right” means any right or agreement that enables any Person to purchase or acquire any Asset or any interest therein or portion thereof as a result of or in connection with (i) the sale, assignment or other transfer of any Asset or any interest therein or portion thereof or (ii) the execution or delivery of this Agreement or the consummation or performance of the terms and conditions contemplated by this Agreement.

“Proceeding” or “Proceedings” has the meaning set forth in Section 5.7.

“Properties” has the meaning set forth in Section 1.2(c).

“Property Costs” has the meaning set forth in Section 1.4(b).

“Proprietary Seismic Data” means all of Seller’s proprietary geophysical, seismic and geological data collected or obtained from any 3D seismic surveys, covering the Lands, including any processed or reprocessed data.

“Purchase Price” has the meaning set forth in Section 2.1.

“Purchaser” has the meaning set forth in the preamble hereto.

“Purchaser Indemnified Persons” has the meaning set forth in Section 11.5.

“Q1” has the meaning set forth in Section 7.8(c).

xiii

“RCRA” has the meaning set forth in the definition of Environmental Laws.

“Records” has the meaning set forth in Section 1.2(i).

“REGARDLESS OF FAULT” means WITHOUT REGARD TO THE CAUSE OR CAUSES OF ANY CLAIM, INCLUDING, WITHOUT LIMITATION, EVEN THOUGH A CLAIM IS CAUSED IN WHOLE OR IN PART BY:

OTHER THAN GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, THE NEGLIGENCE (WHETHER SOLE, JOINT, CONCURRENT, COMPARATIVE, CONTRIBUTORY, ACTIVE OR PASSIVE), STRICT LIABILITY, OR OTHER FAULT OF THE SELLER INDEMNIFIED PERSONS; AND/OR

A PRE-EXISTING DEFECT, WHETHER PATENT OR LATENT, OF THE PREMISES OF PURCHASER’S PROPERTY OR SELLER’S PROPERTY (INCLUDING WITHOUT LIMITATION THE ASSETS), INVITEES AND/OR THIRD PARTIES; AND/OR

THE UNSEAWORTHINESS OF ANY VESSEL OR UNAIRWORTHINESS OF ANY AIRCRAFT OF A PARTY WHETHER CHARTERED, OWNED, OR PROVIDED BY THE PURCHASER INDEMNIFIED PERSONS, SELLER INDEMNIFIED PERSONS, INVITEES AND/OR THIRD PARTIES.

“Retained Asset” has the meaning set forth in Section 7.7(c).

“Retained Employee Liabilities” shall mean any liabilities of Seller or any of its Affiliates (i) to employees of Seller or any of its Affiliates arising under the Worker Adjustment and Retraining Notification Act of 1988, as amended (or similar state or local law), as a result of actions taken by Seller or any of its Affiliates on or prior to the Closing, (ii) arising out of claims by or on behalf of employees of Seller or any of its Affiliates with respect to events that occur on or prior to the Closing and that relate to their employment with, or the terminations of their employment from, Seller, (iii) with respect to employees of Seller or any of its Affiliates arising under any “employee benefit plan” (as defined in Section 3(3) of ERISA) that is or has been sponsored by, contributed to, or maintained by, Seller or any of its Affiliates, or (iv) arising under ERISA for which Purchaser may have any liability under ERISA solely as a result of the consummation of the transaction contemplated by this Agreement.

“Royalty Actions” means each Proceeding listed under Category 3 on Schedule 5.7(a) other than the Proceeding listed in item 6 and item 7 under the same category.

“Royalty Amounts” has the meaning set forth in Section 11.3.

“Securities Act” means the Securities Act of 1933, as amended.

“Seismic License” means that certain seismic license covering Proprietary Seismic Data in the form attached hereto as Exhibit D.

“Seller” has the meaning set forth in the preamble hereto.

“Seller Indemnified Persons” has the meaning set forth in Section 11.6.

“Seller Operated Assets” means Assets operated by Seller.

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“Statements of Revenues and Expenses” has the meaning set forth in Section 7.1(b).

“Surface Contracts” has the meaning set forth in Section 1.2(e).

“Tax Allocated Value” has the meaning set forth in Section 2.3.

“Taxes” means all federal, state, local, and foreign income, profits, franchise, sales, use, ad valorem, property, severance, production, excise, stamp, documentary, real property transfer or gain, gross receipts, goods and services, registration, capital, transfer, or withholding taxes or other governmental fees or charges imposed by any Governmental Body, including any interest, penalties or additional amounts which may be imposed with respect thereto.

“Tax Returns” has the meaning set forth in Section 5.8(a).

“Termination Date” has the meaning set forth in Section 10.1(b)(i).

“Third Party Claim” has the meaning set forth in Section 11.7(a).

“Title Arbitrator” has the meaning set forth in Section 3.4(i).

“Title Benefit” has the meaning set forth in Section 3.2(d).

“Title Benefit Amount” has the meaning set forth in Section 3.4(e).

“Title Benefit Notice” has the meaning set forth in Section 3.4(b).

“Title Claim Date” has the meaning set forth in Section 3.4(a).

“Title Defect” has the meaning set forth in Section 3.2(d).

“Title Defect Amount” has the meaning set forth in Section 3.4(d)(i).

“Title Defect Notice” has the meaning set forth in Section 3.4(a).

“Title Defect Property” has the meaning set forth in Section 3.4(a).

“Transfer Requirement” means any consent, approval, authorization or permit of, or filing with or notification to, any Person which is required to be obtained, made or complied with for or in connection with any sale, assignment or transfer of any Asset or any interest therein; provided, however, that “Transfer Requirement” shall not include any consent of, notice to, filing with, or other action by any Governmental Body in connection with the sale or conveyance of oil and/or gas leases or interests therein or Surface Contracts or interests therein, if they are not required prior to the assignment of such oil and/or gas leases, Surface Contracts or interests or they are customarily obtained subsequent to the sale or conveyance (including consents from state agencies).

“Transfer Taxes” has the meaning set forth in Section 12.3.

“Transition Services Agreement” has the meaning set forth in Section 7.13.

“Units” has the meaning set forth in Section 1.2(c).

“UTPCPL” has the meaning set forth in Section 11.11(a).

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“Warranty Well” means a Well or a Future Well, as the context requires.

“Wells” has the meaning set forth in Section 1.2(b).

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PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement is executed on February 1, 2007, by and among Anadarko Petroleum Corporation, a Delaware corporation (“APC”), Anadarko E&P Company LP, a Delaware limited partnership (“AEP”), Howell Petroleum Corporation, a Delaware corporation (“Howell”), and Kerr-McGee Oil & Gas Onshore LP, a Delaware limited partnership (“KMOG”; APC, AEP, Howell and KMOG are collectively called “Seller”), and EXCO Resources, Inc., a Texas corporation (“Purchaser”).

RECITALS

A.            Seller owns the Assets as more fully described in Section 1.2 and the exhibits hereto.

B.            Seller desires to sell to Purchaser and Purchaser desires to purchase from Seller the properties and rights of Seller hereafter described, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises, representations, warranties, covenants, conditions and agreements contained herein, and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1
PURCHASE AND SALE

Section 1.1            Purchase and Sale.

At the Closing, and upon the terms and subject to the conditions of this Agreement, Seller agrees to sell, transfer and convey the Assets to Purchaser and Purchaser agrees to purchase, accept and pay for the Assets and to assume the Assumed Seller Obligations.

Section 1.2            Assets.

As used herein, the term “Assets” means, subject to the terms and conditions of this Agreement, all of Seller’s right, title, interest and estate, real or personal, recorded or unrecorded, movable or immovable, tangible or intangible, in and to the following (but excluding the Excluded Assets):

(a)           All (i) of the oil and gas leases; subleases and other leaseholds; carried interests; farmout rights; options; and other properties and interests described on Exhibit A, subject to such depth limitations and other restrictions as may be set forth on Exhibit A (collectively, the “Leases”) and (ii) fee mineral interests, fee royalty interests and other fee interests in oil, gas and other minerals described on Exhibit A (collectively, the “Mineral Interests”), (in each case) together with each and every kind and character of right, title, claim, and interest that Seller has in and to the lands covered by the Leases and the Mineral Interests and the interests currently pooled, unitized, communitized or consolidated therewith (the “Lands”);

(b)           All oil, gas, water or injection wells located on the Lands, whether producing, shut-in, or temporarily abandoned, including the interests in the wells shown on Exhibit A-1 attached hereto (collectively, the “Wells”);

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(c)           All interests of Seller in or to any currently existing pools or units which include any Lands or all or a part of any Leases or Mineral Interests or include any Wells, including those pools or units shown on Exhibit A-1 (the “Units”; the Units, together with the Leases, Mineral Interests, Lands and Wells, being hereinafter referred to as the “Properties”), and including all interests of Seller in production of Hydrocarbons from any such Unit, whether such Unit production of Hydrocarbons comes from Wells located on or off of a Lease or the Mineral Interests, and all tenements, hereditaments and appurtenances belonging to the Leases, the Mineral Interests and Units;

(d)           All contracts, agreements and instruments by which the Properties are bound or subject, or that relate to or are otherwise applicable to the Properties, only to the extent applicable to the Properties rather than Seller’s or any of its Affiliates’ other properties, including but not limited to, operating agreements, unitization, pooling and communitization agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, exploration agreements, participation agreements, exchange agreements, transportation or gathering agreements, agreements for the sale and purchase of oil, gas or casinghead gas and processing agreements to the extent applicable to the Properties or the production of Hydrocarbons produced in association therewith from the Properties, including those identified on Schedule 1.2(d) (hereinafter collectively referred to as “Contracts”), but excluding any contracts, agreements and instruments to the extent transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.7 and provided that “Contracts” shall not include the instruments constituting the Leases;

(e)           All easements, permits, licenses, servitudes, rights-of-way, surface leases and other surface rights (“Surface Contracts”) appurtenant to, and used or held for use in connection with the Properties (including those identified on Schedule 1.2(e)), but excluding any permits and other rights to the extent transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not waived by Purchaser or satisfied pursuant to Section 7.7;

(f)            All treatment and processing plants and equipment, machinery, fixtures and other tangible personal property and improvements located on the Properties or used or held for use in connection with the operation of the Properties, including those identified on Exhibit A-2 (“Equipment”);

(g)           All flow lines, pipelines, gathering systems and appurtenances thereto located on the Properties or used, or held for use, in connection with the operation of the Properties, including those identified on Schedule 1.2(g) (“Pipelines” and, together with the Equipment and Wells, “Personal Property”);

(h)           All Hydrocarbons produced from or attributable to the Leases, Mineral Interests, Lands, and Wells from and after the Effective Time, together with Imbalances associated with the Properties;

(i)            All lease files; land files; well files; gas and oil sales contract files; gas processing files; division order files; abstracts; title opinions; land surveys; logs; maps; engineering data and reports; interpretive data, technical evaluations and technical outputs; and other books, records, data, files, and accounting records, in each case to the extent related to the Assets, or used or held for use in connection with the maintenance or operation thereof, but excluding (i) any books, records, data, files, logs, maps, evaluations, outputs, and accounting records to the

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extent disclosure or transfer would result in a violation of applicable Law or is restricted by any Transfer Requirement that is not satisfied pursuant to Section 7.7, (ii) computer or communications software or intellectual property (including tapes, codes, data and program documentation and all tangible manifestations and technical information relating thereto), (iii) attorney-client privileged communications and work product of Seller’s or any of its Affiliates’ legal counsel (other than title opinions), (iv) reserve studies and evaluations, and (v) records relating to the negotiation and consummation of the sale of the Assets (subject to such exclusions, the “Records”); provided, however, that Seller may retain the originals of such Records as Seller has reasonably determined may be required for existing litigation, tax, accounting, and auditing purposes; and

(j)            All vehicles or vessels used exclusively in connection with the Assets.

Section 1.3            Excluded Assets.

Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved and excluded from the transaction contemplated hereby (collectively, the “Excluded Assets”):

(a)           except to the extent necessary to satisfy Seller’s obligations under Section 7.1(b), (i) all corporate, financial, income and franchise tax and legal records of Seller that relate to Seller’s business generally (whether or not relating to the Assets), (ii) all books, records and files that relate to the Excluded Assets, (iii) those records retained by Seller pursuant to Section 1.2(i) and (iv) copies of any other Records retained by Seller pursuant to Section 1.5;

(b)           subject to the Seismic License, all geological and geophysical data (including all seismic data, including reprocessed data), reserve estimates, economic estimates, and, to the extent excluded from Section 1.2(i), all logs, interpretive data, technical evaluations and technical outputs;

(c)           all rights to any refund related to the Excluded Seller Obligations or Taxes or other costs or expenses borne by Seller or Seller’s predecessors in interest and title attributable to periods prior to the Effective Time;

(d)           Seller’s area-wide bonds, permits and licenses or other permits, licenses or authorizations used in the conduct of Seller’s business generally;

(e)           those items listed in Schedule 1.3(e);

(f)            all trade credits, account receivables, note receivables, take-or-pay amounts receivable, and other receivables attributable to the Assets with respect to any period of time prior to the Effective Time;

(g)           all claims and causes of action described in Schedule 5.7;

(h)           except to the extent specifically provided in Section 1.2(j), all right, title and interest of Seller in and to vehicles or vessels used in connection with the Assets;

(i)            all rights, titles, claims and interests of Seller or any Affiliate of Seller (i) to or under any policy or agreement of insurance or any insurance proceeds; except to the extent provided in Section 3.5, and (ii) to or under any bond or bond proceeds;

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(j)            subject to Section 12.5, any patent, patent application, logo, service mark, copyright, trade name or trademark of or associated with Seller or any Affiliate of Seller or any business of Seller or of any Affiliate of Seller;

(k)           a nonexclusive right to freely use any copies of any logs, interpretive data, technical outputs, technical evaluations, maps, engineering data and reports, reserve studies and evaluations, and other data and information being transferred as a part of the Assets that Seller is entitled to retain pursuant to Section 1.5; and

(l)            all Retained Assets not conveyed to Purchaser pursuant to Section 7.7 and any Property excluded pursuant to Section 3.4(d)(iii).

Section 1.4            Effective Time; Proration of Costs and Revenues.

(a)           Subject to Section 1.5, possession of the Assets shall be transferred from Seller to Purchaser at the Closing, but certain financial benefits and burdens of the Assets shall be transferred effective as of 7:00 A.M., local time, where the respective Assets are located, on January 1, 2007 (the “Effective Time”), as described below.

(b)           Purchaser shall be entitled to all Hydrocarbon production from or attributable to the Properties at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets at or after the Effective Time, and shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred at and after the Effective Time. Seller shall be entitled to all Hydrocarbon production from or attributable to the Properties prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets prior to the Effective Time, and shall be responsible for (and entitled to any refunds with respect to) all Property Costs incurred prior to the Effective Time. “Earned” and “incurred”, as used in this Agreement, shall be interpreted in accordance with GAAP and Council of Petroleum Accountants Society (COPAS) standards, as applicable. “Property Costs” means all costs attributable to the ownership and operation of the Assets (including without limitation costs of insurance relating specifically to the Assets and ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, but excluding any other Taxes) and capital expenditures incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to the Assets under the relevant operating agreement or unit agreement, if any, or, if none, the amounts shown under Schedule 1.4 shall be the overhead amounts deemed charged to the Assets, but excluding without limitation liabilities, losses, costs, and expenses attributable to (i) claims for personal injury or death, property damage or violation of any Law, (ii) obligations to plug wells or dismantle, abandon and salvage facilities, (iii) obligations to remediate any contamination of groundwater, surface water, soil, Equipment or Pipelines under applicable Environmental Laws, (iv) obligations to furnish make-up gas according to the terms of applicable gas sales, gathering or transportation contracts, (v) gas balancing obligations and (vi) obligations to pay working interests, royalties, overriding royalties or other interests held in suspense, all of which are addressed in Article 11 or elsewhere in this Agreement.  For purposes of this Section 1.4, determination of whether Property Costs are attributable to the period before or after the Effective Time shall be based on when services are rendered, when the goods are delivered, or when the work is performed.  For clarification, the date an item or work is ordered is not the date of a pre-Effective Time transaction for settlement purposes, but

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rather the date on which the item ordered is delivered to the job site, or the date on which the work ordered is performed, shall be the relevant date.  For purposes of allocating Hydrocarbon production (and accounts receivable with respect thereto), under this  Section 1.4, (i) liquid Hydrocarbons shall be deemed to be “from or attributable to” the Properties when they are placed into the storage facilities and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Properties when they pass through the delivery point sales meters on the pipelines through which they are transported. Seller shall utilize reasonable interpolative procedures to arrive at an allocation of Hydrocarbon production when exact meter readings or gauging and strapping data is not available. Seller shall provide to Purchaser, no later than three (3) Business Days prior to Closing, all data necessary to support any estimated allocation, for purposes of establishing the adjustment to the Purchase Price pursuant to Section 2.2 hereof that will be used to determine the Closing Payment.  Property Costs that are paid periodically shall be prorated based on the number of days in the applicable period falling before and the number of days in the applicable period falling at or after the Effective Time, except that Hydrocarbon production, severance and similar Taxes shall be prorated based on the number of units actually produced, purchased or sold or proceeds of sale, as applicable, before, and at or after, the Effective Time. In each case, Purchaser shall be responsible for the portion allocated to the period at and after the Effective Time and Seller shall be responsible for the portion allocated to the period before the Effective Time.

Section 1.5            Delivery and Maintenance of Records.

Seller, at Seller’s sole cost and expense, shall deliver the Records (FOB Seller’s office) to Purchaser within thirty (30) days following Closing; provided, however, that Seller shall be entitled to retain those original Records necessary to comply with its obligations under the Transition Services Agreement for so long as is reasonably necessary to comply with its obligations under the Transition Services Agreement and Seller, at Purchaser’s sole expense, shall provide Purchaser with copies of any such original Records retained by Seller as soon as reasonably practicable.  Other than any original Records retained by Seller pursuant to Section 1.2(i), Purchaser shall be entitled to all original Records maintained by Seller (other than such Records maintained at the Grogans Mill offsite storage facility, which is addressed below) ,and a scanned copy of all of the original Records and, to the extent available and specifically identifiable to the Assets, original Records maintained by Seller at its Grogans Mill offsite storage facility.  Seller shall be entitled to keep a copy or copies of all Records; provided, however, that Seller shall not sell or otherwise allow third parties to review, copy or otherwise use (for any purpose) any Records retained by Seller for their own account.  Purchaser shall preserve the Records for a period of ten (10) years following the Closing and will allow Seller and its representatives, consultants and advisors reasonable access, during normal business hours and upon reasonable notice, to the Records for any legitimate business reason of Seller, including in order for Seller to comply with a Tax or other legally required reporting obligation or Tax or legal dispute; provided, however, that Purchaser shall not be required to grant access to Seller or any of its representatives, consultants or advisors, to any Records that are subject to an attorney/client or attorney work product privilege or that would cause Purchaser to violate any obligation to any third party or breach any restriction legally binding on Purchaser.  Any such access shall be at the sole cost and expense of Seller.  Unless otherwise consented to in writing by Seller, for a period of ten (10) years following the Closing Date, Purchaser shall not and shall cause its Affiliates not to, destroy, alter or otherwise dispose of the Records, or any portions thereof, without first giving at least thirty (30) days prior written notice to Seller and offering to surrender to Seller the Records or such portions thereof.

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ARTICLE 2
PURCHASE PRICE

Section 2.1            Purchase Price.

The purchase price for the Assets (the “Purchase Price”) shall be $860,000,000 adjusted as provided in Section 2.2.

Section 2.2            Adjustments to Purchase Price.

The Purchase Price for the Assets shall be adjusted in the manner specified below (without duplication), with all such amounts being determined in accordance with GAAP and Council of Petroleum Accountants Society (COPAS) standards, as applicable, in order to reach the Adjusted Purchase Price:

(a)           Reduced by the aggregate amount of the following proceeds received by Seller between (and including) the Effective Time and the Closing Date (with the period between the Effective Time and the Closing Date referred to as the “Adjustment Period”): (i) proceeds from the sale of Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of production, gathering, processing and transportation costs and any production, severance, sales, excise or similar Taxes not reimbursed to Seller by the purchaser of production) produced from or attributable to the Properties during the Adjustment Period, and (ii) other proceeds earned with respect to the Assets during the Adjustment Period;

(b)           Reduced to the extent provided in Section 7.7 with respect to Preference Rights and Retained Assets;

(c)           (i) If the parties make the election under Section 3.4(d)(i) with respect to a Title Defect, subject to the Individual Title Deductible and the Aggregate Defect Deductible, reduced by the Title Defect Amount with respect to such Title Defect if the Title Defect Amount has been determined prior to Closing and (ii) subject to the Individual Benefit Deductible and the Aggregate Benefit Deductible, increased by the Title Benefit Amount with respect to each Title Benefit for which the Title Benefit Amount has been determined prior to Closing;

(d)           Increased by the amount of all Property Costs and other costs attributable to the ownership and operation of the Assets which are paid by Seller and incurred during the Adjustment Period (including any overhead costs under Schedule 1.4 deemed charged to the Assets with respect to the Adjustment Period even though not actually paid), except any Property Costs and other such costs already deducted in the determination of proceeds in Section 2.2(a);

(e)           Reduced to the extent provided in Section 3.4(d)(iii) for any Properties excluded from the Assets pursuant to Section 3.4(d)(iii) and reduced to the extent provided in Section 4.3 for Environmental Defects;

(f)            Reduced by the aggregate amounts payable to owners of working interests, royalties and overriding royalties and other interests in the Properties held in suspense by Seller as of the Closing Date;

(g)           Increased or reduced as mutually agreed upon in writing prior to Closing by Seller and Purchaser;

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(h)           Increased by the value of the amount of merchantable Hydrocarbons stored in tanks and pipelines attributable to the ownership and operation of the Assets that belong to Seller as of the Effective Time (which value shall be computed at the applicable third-party contract prices for the month of December 2006 for such stored Hydrocarbons); and

(i)            Reduced by the actual net aggregate Imbalances, if any, owed by Seller to third-parties, as of the Effective Time, multiplied by a price of $3.00 per MMBtu.

Each adjustment made pursuant to Section 2.2(a) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s entitlement under Section 1.4 to Hydrocarbon production from or attributable to the Properties during the Adjustment Period, and to the value of other income, proceeds, receipts and credits earned with respect to the Assets during the Adjustment Period, and as such, Purchaser shall not have any separate rights to receive any Hydrocarbon production or income, proceeds, receipts and credits with respect to which an adjustment has been made. Similarly, the adjustment described in Section 2.2(d) shall serve to satisfy, up to the amount of the adjustment, Purchaser’s obligation under Section 1.4 to pay Property Costs and other costs attributable to the ownership and operation of the Assets which are incurred during the Adjustment Period, and as such, notwithstanding anything in this Agreement to the contrary, Purchaser shall not be separately obligated to pay for any Property Costs or other such costs with respect to which an adjustment has been made.

The Purchase Price less the Deposit provided for in Section 2.4, adjusted as set forth in (a) through (i), shall be increased by simple interest thereon from the Effective Time to the Closing Date, computed at the Agreed Interest Rate.

Section 2.3            Allocation of Purchase Price for Tax Purposes

Purchaser and Seller will use commercially reasonable efforts to agree, on or before the Closing Date, upon an allocation of the unadjusted Purchase Price among each of the Assets, in compliance with the principles of Section 1060 of the Code, and the Treasury regulations thereunder.  Such allocation of value shall be generally treated as Class V assets for purposes of Internal Revenue Service Form 8594 to the extent possible consistent with the character of the Assets involved. The “Tax Allocated Value” for any Asset equals the portion of the unadjusted Purchase Price to be allocated to such Asset by the parties pursuant to this Section 2.3, increased or reduced as described in this Article 2.  Any adjustments to the Purchase Price other than the adjustments provided for in Sections 2.2(b), 2.2(c), and 2.2(e) shall be applied on a pro rata basis to the amounts agreed to by the parties pursuant to this Section 2.3 for all Assets to the maximum extent possible consistent with the character of the adjustments.  After all such adjustments are made, any adjustments to the Purchase Price pursuant to Sections 2.2(b), 2.2(c), and 2.2(e) shall be applied to the amounts agreed to by the parties pursuant to this Section 2.3 for the particular affected Assets. After Seller and Purchaser have agreed on the Tax Allocated Values for the Assets, Seller will be deemed to have accepted such Tax Allocated Values for purposes of this Agreement and the transactions contemplated hereby, but otherwise makes no representation or warranty as to the accuracy of such values. Seller and Purchaser agree (i) that the Tax Allocated Values shall be used by Seller and Purchaser as the basis for reporting asset values and other items for purposes of all federal, state, and local Tax Returns, including without limitation Internal Revenue Service Form 8594 and (ii) that neither they nor their Affiliates will take positions inconsistent with the Tax Allocated Values in notices to Governmental Bodies, in audit or other proceedings with respect to Taxes unless required by applicable Law or with the consent of the other party.  Purchaser and Seller agree that each shall furnish the other a copy of Form 8594 (Asset Acquisition Statement under Section 1060)

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proposed to be filed with the Internal Revenue Service by such party or any Affiliate thereof within ten (10) days prior to such filing.

Section 2.4            Deposit

On or before 12:00 p.m. on February 2, 2007, Purchaser will pay to Seller an earnest money deposit in an amount equal to $43,000,000 (the “Deposit”).  The Deposit shall be non-interest bearing and applied against the Purchase Price if the Closing occurs or shall be otherwise distributed in accordance with the terms of this Agreement.

ARTICLE 3
TITLE MATTERS

Section 3.1            Seller’s Title.

(a)           Except for the special warranty of title referenced in Section 3.1(b) and without limiting Purchaser’s right to adjust the Purchase Price by operation of this Article 3, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Purchaser hereby acknowledges and agrees that the sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets (i) before Closing, shall be as set forth in Section 3.4(d) and (ii) after Closing, shall be pursuant to the special warranty of title referenced in Section 3.1(b).

(b)           The conveyance covering the Assets to be delivered by Seller to Purchaser shall be substantially in the form of Exhibit B hereto (the “Conveyance”).  The Conveyance shall contain a special warranty of Defensible Title by, through and under Seller and its Affiliates, but not otherwise, to the Units, Warranty Wells and other Assets shown on Exhibit A-1, subject to the Permitted Encumbrances, but shall otherwise be without warranty of title of any kind, express, implied or statutory or otherwise.

(c)           Purchaser shall not be entitled to protection under Seller’s special warranty of title in the Conveyance against any Title Defect reported by Purchaser under Section 3.4(a) and/or any Title Defect actually known by any officer of Purchaser or any of its Affiliates prior to the Title Claim Date.

(d)           Notwithstanding anything herein provided to the contrary, if a Title Defect under this Article 3 results from any matter which could also result in the breach of any representation or warranty of Seller set forth in Article 5, then Purchaser shall only be entitled to assert such matter (i) before Closing, as a Title Defect to the extent permitted by this Article 3, or (ii) after Closing, as a breach of Seller’s special warranty of title contained in the Conveyance to the extent permitted by this Section 3.1, and shall be precluded from also asserting such matter as the basis of the breach of any such representation or warranty.

Section 3.2            Definition of Defensible Title.

As used in this Agreement, the term “Defensible Title” means that title of Seller with respect to the Units, Warranty Wells or other Assets shown in Exhibit A-1 that, except for and subject to Permitted Encumbrances:

(a)           Entitles Seller to receive a share of the Hydrocarbons produced, saved and marketed from any Unit, Warranty Well or other Asset shown in Exhibit A-1 throughout the

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duration of the productive life of such Unit, Warranty Well or other Asset (after satisfaction of all royalties, overriding royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) (a “Net Revenue Interest”), of not less than the Net Revenue Interest shown in Exhibit A-1 for such Unit, Warranty Well or other Asset, except (solely to the extent that such actions do not cause a breach of Seller’s covenants under Section 7.6) for decreases in connection with those operations in which Seller may from and after the Effective Time become a non-consenting co-owner, decreases resulting from the establishment or amendment from and after the Effective Time of pools or units, and decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries, and except as stated in such Exhibit A-1;

(b)           Obligates Seller to bear a percentage of the costs and expenses for the maintenance and development of, and operations relating to, (i) any Unit, Warranty Well or other Asset shown in Exhibit A-1  not greater than the “working interest” shown in Exhibit A-1 for such Unit, Warranty Well or other Asset without increase throughout the productive life of such Unit, Warranty Well or other Asset, except as stated in Exhibit A-1 and except for increases resulting from contribution requirements with respect to non-consenting co-owners under applicable operating agreements and increases that are accompanied by at least a proportionate increase in Seller’s Net Revenue Interest; and

(c)           Is free and clear of liens, encumbrances, obligations, security interests, irregularities, pledges, or other defects.

(d)           As used in this Agreement, the term “Title Defect” means any lien, charge, encumbrance, obligation (including contract obligation), defect, or other matter (including without limitation a discrepancy in Net Revenue Interest or working interest) that causes Seller not to have Defensible Title in and to the Units, Warranty Wells or other Assets shown on Exhibit A-1 as of the Effective Time and the Closing. As used in this Agreement, the term “Title Benefit” shall mean any right, circumstance or condition that operates to increase the Net Revenue Interest of Seller in any Unit, Warranty Well or other Asset shown on Exhibit A-1, without causing a greater than proportionate increase in Seller’s working interest above that shown in Exhibit A-1 as of the Effective Time. Notwithstanding the foregoing, the following shall not be considered Title Defects:

(i)defects based solely on (1) lack of information in Seller’s files, or (2) references to a document(s) if such document(s) is not in Seller’s files;

(ii)defects arising out of lack of corporate or other entity authorization unless Purchaser provides affirmative evidence that the action was not authorized;

(iii)defects based on failure to record Leases issued by any state or federal Governmental Body, or any assignments of such Leases, in the real property, conveyance or other records of the county or parish in which such Property is located;

(iv)defects based on a gap in Seller’s chain of title in the county or parish records as to Leases, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain which documents shall be included in a Title Defect Notice; and

(v)defects that have been cured by applicable Laws of limitation or prescription.

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Section 3.3            Definition of Permitted Encumbrances.

As used herein, the term “Permitted Encumbrances” means any or all of the following:

(a)           Royalties and any overriding royalties, reversionary interests and other burdens on production, to the extent that any such burden does not reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1 or increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in the Net Revenue Interest;

(b)           All Leases, unit agreements, pooling agreements, operating agreements, Hydrocarbon production sales contracts, division orders and other contracts, agreements and instruments applicable to the Assets, to the extent that they do not, individually or in the aggregate, reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1 or increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in the Net Revenue Interest;

(c)           Preference Rights applicable to this or any future transaction;

(d)           Transfer Requirements applicable to this or any future transaction;

(e)           Liens for current Taxes or assessments not yet delinquent;

(f)            Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s and other similar liens or charges arising in the ordinary course of business for amounts not yet delinquent (including any amounts being withheld as provided by Law);

(g)           All rights to consent by, required notices to, filings with, or other actions by Governmental Bodies in connection with the sale or conveyance of the Assets or interests therein pursuant to this or to any future transaction if they are not required or customarily obtained prior to the sale or conveyance;

(h)           Rights of reassignment arising upon final intention to abandon or release the Assets, or any of them;

(i)            Easements, rights-of-way, servitudes, permits, surface leases and other rights in respect of surface operations, to the extent that they do not (i) reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1, (ii) increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in Net Revenue Interest, or (iii) detract in any material respect from the value of, or interfere in any material respect with the use, ownership or operation of, the Assets subject thereto or affected thereby (as currently used, owned and operated) and which would be acceptable by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties;

(j)            Calls on Hydrocarbon production under existing Contracts that are listed on Schedule 1.2(d);

(k)           All rights reserved to or vested in any Governmental Body to control or regulate any of the Assets in any manner, and all obligations and duties under all applicable Laws or under any franchise, grant, license or permit issued by any such Governmental Body;

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(l)            Any encumbrance on or affecting the Assets which is discharged by Seller at or prior to Closing;

(m)          Any matters shown on Exhibit A-1;

(n)           Any other liens, charges, encumbrances, defects or irregularities which do not, individually or in the aggregate, detract in any material respect from the value of, or interfere in any material respect with the use or ownership of, the Assets subject thereto or affected thereby (as currently used or owned), which would be accepted by a reasonably prudent purchaser engaged in the business of owning and operating oil and gas properties, and which do not reduce Seller’s Net Revenue Interest below that shown in Exhibit A-1, or increase Seller’s working interest above that shown in Exhibit A-1 without a proportionate increase in Net Revenue Interest;

(o)           Matters that would otherwise be considered Title Defects but that do not meet the Individual Title Deductible set forth in Section 3.4(j);

(p)           Imbalances associated with the Assets; and

(q)           Liens granted under applicable joint operating agreements.

Section 3.4            Notice of Title Defect Adjustments.

(a)           To assert a claim of a Title Defect prior to Closing, Purchaser must deliver claim notices to Seller (each a “Title Defect Notice”) on or before April 2, 2007 (the “Title Claim Date”); provided, however, that Purchaser agrees that it shall furnish Seller once every two (2) weeks, commencing on the fourteenth (14th) day following the date of this Agreement until the Title Claim Date with a Title Defect Notice if any officer of Purchaser or its Affiliates discover or learn of any Title Defect during such two (2) week period.  Each Title Defect Notice shall be in writing and shall include (i) a description of the alleged Title Defect(s), (ii) the Units, Warranty Wells or other Assets in Exhibit A-1 affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents reasonably necessary for Seller (as well as any title attorney or examiner hired by Seller) to verify the existence of the alleged Title Defect(s), and (v) the amount by which Purchaser reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations and information upon which Purchaser’s belief is based. Notwithstanding any other provision of this Agreement to the contrary, but subject to Purchaser’s rights in connection with the special warranty of title referenced in Section 3.1(b), Purchaser shall be deemed to have waived its right to assert Title Defects of which Seller has not been given notice on or before the Title Claim Date.  For purposes hereof, the “Allocated Value” of an Asset shall mean the portion of the Purchase Price that has been allocated to a particular Unit, Warranty Well or other Asset in Exhibit A-1.

(b)           Seller shall have the right, but not the obligation, to deliver to Purchaser on or before the Title Claim Date, with respect to each Title Benefit, a notice (a “Title Benefit Notice”) including (i) a description of the Title Benefit, (ii) the Units, Warranty Wells or other Assets in Exhibit A-1 affected, (iii) the Allocated Values of the Units, Warranty Wells or other Assets in Exhibit A-1 subject to such Title Benefit and (iv) the amount by which Seller reasonably believes the Allocated Value of those Units, Warranty Wells or other Assets is increased by the Title Benefit, and the computations and information upon which Seller’s belief is based. Seller

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shall be deemed to have waived all Title Benefits of which it has not given notice to Purchaser on or before the Title Claim Date.

(c)           Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure or remove at any time prior to Closing (the “Cure Period”), unless the parties otherwise agree, any Title Defects of which it has been advised in writing by Purchaser.

(d)           Remedies for Title Defects.

In the event that any Title Defect is not waived by Purchaser or cured on or before Closing, Purchaser and Seller shall mutually elect to have one of the following remedies apply:

(i)subject to the Individual Title Deductible and the Aggregate Defect Deductible, have the Purchase Price reduced by an amount agreed upon (“Title Defect Amount”) pursuant to Section 3.4(g) or Section 3.4(i) by Purchaser and Seller as being the value of such Title Defect, taking into consideration the Allocated Value of the Property subject to such Title Defect, the portion of the Property subject to such Title Defect and the legal effect of such Title Defect on the Property affected thereby; provided, however, that the methodology, terms and conditions of Section 3.4(g) shall control any such determination;

(ii)indemnify Purchaser against all liability, loss, cost and expense resulting from such Title Defect pursuant to an indemnity agreement (the “Indemnity Agreement”) in the form attached hereto as Exhibit C; or

(iii)have Seller retain the entirety of the Property that is subject to such Title Defect, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Property.

In the event that Purchaser and Seller cannot mutually agree upon one of the foregoing remedies with respect to a Title Defect asserted by Purchaser pursuant to Section 3.4(a) prior to Closing, then Seller shall, at its sole election, select the remedy set forth in subsection (i) or (iii) above as the remedy for such Title Defect.

(e)           With respect to each Unit, Warranty Well or other Asset in Exhibit A-1 affected by Title Benefits reported under Section 3.4(b), subject to the Individual Benefit Deductible and the Aggregate Defect Deductible, the Purchase Price shall be increased by an amount (the “Title Benefit Amount”) equal to the increase in the Allocated Value for such Unit, Warranty Well or other Asset in Exhibit A-1 caused by such Title Benefits, as determined pursuant to Section 3.4(h).

(f)            Section 3.4(d) shall be the exclusive right and remedy of Purchaser with respect to Title Defects asserted by Purchaser pursuant to Section 3.4(a).

(g)           The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following methodology, terms and conditions:

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(i)if Purchaser and Seller agree on the Title Defect Amount, that amount shall be the Title Defect Amount;

(ii)if the Title Defect is a lien, encumbrance or other charge which is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii)if the Title Defect represents a discrepancy between (A) the Net Revenue Interest for any Title Defect Property and (B) the Net Revenue Interest stated on Exhibit A-1, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest stated on Exhibit A-1;

(iv)if the Title Defect represents an obligation, encumbrance, burden or charge upon or other defect in title to the Title Defect Property of a type not described in subsections (i), (ii) or (iii) above, the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Purchaser and Seller and such other factors as are necessary to make a proper evaluation; and

(v)notwithstanding anything to the contrary in this Article 3, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of the Title Defect Property.

(h)           The Title Benefit Amount for any Title Benefit shall be the product of the Allocated Value of the affected Unit, Warranty Well or other Asset in Exhibit A-1 multiplied by a fraction, the numerator of which is the Net Revenue Interest increase and the denominator of which is the Net Revenue Interest stated on Exhibit A-1.

(i)            Seller and Purchaser shall attempt in good faith to agree on all Title Defect Amounts and Title Benefit Amounts prior to Closing.  If Seller and Purchaser are unable to agree by Closing, the Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 3.4(i). There shall be a single arbitrator, who shall be a title attorney with at least ten (10) years experience in oil and gas titles involving properties in the regional area in which the Properties are located, as selected by mutual agreement of Purchaser and Seller within fifteen (15) Business Days after the end of the Cure Period, and absent such mutual agreement, by the Houston office of the American Arbitration Association (the “Title Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section. The Title Arbitrator’s determination shall be made within fifteen (15) Business Days after submission of the matters in dispute and shall be final and binding upon both parties, without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set forth in Section 3.4(g) and Section 3.4(h) and may consider such other matters as in

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the opinion of the Title Arbitrator are necessary or helpful to make a proper determination. Additionally, the Title Arbitrator may consult with and engage disinterested third parties to advise the arbitrator, including without limitation petroleum engineers.  The Title Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Title Defect Amounts and Title Benefit Amounts submitted by either party and may not award damages, interest or penalties to either party with respect to any matter. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case.  Each party shall bear one-half of the costs and expenses of the Title Arbitrator, including any costs incurred by the Title Arbitrator that are attributable to such third party consultation.  Within ten (10) days after the Title Arbitrator delivers written notice to Purchaser and Seller of his award with respect to a Title Defect Amount or a Title Benefit Amount, (i) Purchaser shall pay to Seller the amount, if any, so awarded by the Title Arbitrator to Seller, plus interest payable on such amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Seller and (ii) Seller shall pay to Purchaser the amount, if any, so awarded by the Title Arbitrator to Purchaser, plus interest payable on such amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Purchaser.

(j)            Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for any individual uncured Title Defect for which the Title Defect Amount therefor does not exceed $50,000 (“Individual Title Deductible”); and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for uncured Title Defects unless the aggregate Title Defect Amounts attributable to all uncured Title Defects, taken together with the aggregate Environmental Defect Amounts attributable to all uncured Environmental Defects, exceeds a deductible in an amount equal to $17,000,000 (“Aggregate Defect Deductible”), after which point adjustments to the Purchase Price or other remedies shall be made or available to Purchaser only with respect to uncured Title Defects and uncured Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts attributable thereto are in excess of such Aggregate Defect Deductible.  Notwithstanding anything to the contrary, (i) in no event shall there be any adjustments to the Purchase Price for any individual Title Benefit for which the Title Benefit Amount does not exceed $50,000 (“Individual Benefit Deductible”); and (ii) in no event shall there be any adjustments to the Purchase Price for any Title Benefit unless the aggregate Title Benefit Amounts attributable to all such Title Benefits, exceeds a deductible in an amount equal to $17,000,000 (“Aggregate Benefit Deductible”), after which point adjustments to the Purchase Price shall be made only with respect to such Title Benefit Amounts in excess of such Aggregate Benefit Deductible.

Section 3.5            Casualty or Condemnation Loss.

(a)           From and after the Effective Time, but subject to the provisions of Section 3.5(b) and (c) below, Purchaser shall assume all risk of loss with respect to and any change in the condition of the Assets and for production of Hydrocarbons through normal depletion (including but not limited to the watering out of any Well, collapsed casing or sand infiltration of any Well) and the depreciation of personal property due to ordinary wear and tear with respect to the Assets.

(b)           Subject to the provisions of Section 8.1(e) and Section 8.2(e) hereof, if, after the date of this Agreement but prior to the Closing Date, any portion of the Assets is destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain, and the loss as a result of such individual casualty or taking, taken together with all other casualty losses and

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takings, exceeds $2,600,000, the transactions evidenced by this Agreement shall nevertheless be consummated and Purchaser shall elect by written notice to Seller prior to Closing either (i) to cause the Assets affected by any casualty or taking to be repaired or restored to at least its condition prior to such casualty, at Seller’s sole cost, as promptly as reasonably practicable (which work may extend after the Closing Date), (ii) to have Seller indemnify Purchaser through a document reasonably acceptable to Seller and Purchaser against any costs or expenses that Purchaser reasonably incurs to repair the Assets subject to any casualty or taking or (iii) to treat such casualty or taking as a Title Defect with respect to the affected Property or Properties under Section 3.4; provided, however, that notwithstanding anything herein provided to the contrary, Purchaser cannot require Seller to comply with the remedy set forth in item (i) of this Section 3.5(b) without Seller’s prior written consent.  In each case, Seller shall retain all rights to insurance and other claims against third parties with respect to the casualty or taking except to the extent the parties otherwise agree in writing.

(c)           If, after the date of this Agreement but prior to the Closing Date, any portion of the Assets is destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain, and the loss to the Assets as a result of such individual casualty or taking, taken together with all other casualty losses and takings, is $2,600,000 or less, the transaction evidenced by this Agreement shall nevertheless be consummated and Seller shall, at Closing, pay to Purchaser all sums paid to Seller by third parties by reason of such casualty or taking and shall assign, transfer and set over to Purchaser all of Seller’s right, title and interest (if any) in insurance claims, unpaid awards, and other rights against third parties (other than Affiliates of Seller and its and their directors, officers, employees and agents) arising out of the casualty or taking.

Section 3.6            Limitations on Applicability.

Subject to the following sentence, the right of Purchaser to assert a Title Defect under this Agreement shall terminate as of the Title Claim Date, provided there shall be no termination of Purchaser’s or Seller’s rights under Section 3.4 with respect to any bona fide Title Defect properly reported in a Title Defect Notice or bona fide Title Benefit Claim properly reported in a Title Benefit Notice on or before the Title Claim Date. Thereafter, Purchaser’s sole and exclusive rights and remedies with regard to title to the Assets shall be as set forth in, and arising under, the Conveyance transferring the Assets from Seller to Purchaser.

Section 3.7            Government Approvals Respecting Assets.

(a)           Federal and State Approvals.  Purchaser shall, within thirty (30) days after Closing and at Purchaser’s own expense, file for approval with the applicable Governmental Bodies all assignment documents and other state and federal transfer documents required to effectuate the transfer of the Assets.  Purchaser further agrees, promptly after Closing, to take all other actions reasonably required of it by federal or state agencies having jurisdiction to obtain all requisite regulatory approvals with respect to this transaction, and to use its commercially reasonable efforts to obtain the approval by such federal or state agencies, as applicable, of Seller’s assignment documents requiring federal or state approval in order for Purchaser to be recognized by the federal or state agencies as the owner of the Assets.  Purchaser shall provide Seller with the resignation and designation of operator instruments, and approved copies of the assignment documents and other state and federal transfer documents, as soon as they are available.

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(b)           Title Pending Governmental Approvals.  Until all of the governmental approvals provided for in Section 3.7(a) have been obtained, the following shall occur with respect to the affected portion of the Assets:

(i)Seller shall continue to hold record title to the affected Leases and other affected portion of the Assets as nominee for Purchaser;

(ii)Purchaser shall be responsible for all Seller Assumed Obligations with respect to the affected Leases and other affected portion of the Assets as if Purchaser was the record owner of such Leases and other portion of the Assets as of the Effective Time; and

(iii)Seller shall act as Purchaser’s nominee but shall be authorized to act only upon and in accordance with Purchaser’s instructions, and Seller shall have no authority, responsibility or discretion to perform any tasks or functions with respect to the affected Leases and other affected portion of the Assets other than those which are purely administrative or ministerial in nature, unless otherwise specifically requested and authorized by Purchaser in writing.

(c)           Denial of Required Governmental Approvals.  If the federal or state agency fails to do so within twenty-four (24) months after the Closing, Seller may continue to hold record title to the affected Leases and other affected Assets as Purchaser’s nominee or, at Seller’s option, it may terminate this Agreement and all its obligations hereunder as to the affected Leases and other affected portion of the Assets by giving sixty (60) days written notice to Purchaser.  Upon such termination:  (i) this Agreement shall be null and void and terminated as to the affected Leases and other affected portion of the Assets, (ii) Purchaser shall promptly reassign and return to Seller the assignment documents and any and all other documents, materials and data previously delivered to Purchaser with respect to the affected  Leases and other affected portion of the Assets, and (iii) Seller shall pay to Purchaser the Allocated Value of the affected Property (without interest), less the proceeds of Hydrocarbon production received by Purchaser (which Purchaser may retain as its sole property) net of all expenses, overhead, royalties, and costs of operations (including plugging and abandonment expenses but excluding mortgage interest and any burdens, liens, or encumbrances created by Purchaser which must be released prior to this payment) attributable to the affected Leases or other affected portion of the Assets from the Effective Time forward, plus interest payable on such net amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Purchaser.  In no event, however, shall Seller ever be required to reimburse Purchaser for any expenditures associated with workovers, recompletions, sidetracks, or the drilling, completion or plugging and abandonment of wells drilled or work performed by Seller or any of its Affiliates.

ARTICLE 4
ENVIRONMENTAL MATTERS

Section 4.1            Assessment.

From and after the date of execution of this Agreement until the Closing Date, Seller shall afford to Purchaser and its officers, employees, agents and authorized representatives reasonable access to the Assets, including the Records in accordance with Section 7.1.  During such period, Seller shall also make available to Purchaser, upon reasonable notice during

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normal business hours, Seller’s personnel knowledgeable with respect to the Assets in order that Purchaser may make such diligent investigation as Purchaser considers desirable.  Upon notice to Seller, Purchaser shall have the right to conduct an environmental assessment of all or any portion of the Properties (the “Assessment”), to be conducted by a reputable environmental consulting or engineering firm approved in advance in writing by Seller (such approval not to be unreasonably withheld), but only to the extent that Seller may grant such right without violating any obligations to any third party (provided that Seller shall use its commercially reasonable efforts to obtain any necessary third party consents to any Assessment to be conducted by Purchaser).  The Assessment shall be conducted at the sole cost and expense of Purchaser, and shall be subject to the indemnity provisions of Section 4.4.  Prior to conducting any sampling, boring, drilling or other invasive investigative activity with respect to the Properties (“Invasive Activity”), Purchaser shall furnish for Seller’s review a proposed scope of such Invasive Activity, including a description of the activities to be conducted and a description of the approximate locations of such activities.  If any of the proposed activities may unreasonably interfere with normal operation of the Properties, Seller may request an appropriate modification of the proposed Invasive Activity.  Seller shall have the right to be present during any Assessment of the Properties and shall have the right, at its option and expense, to split samples with Purchaser.  After completing any Assessment of the Properties, Purchaser shall, at its sole cost and expense, restore the Properties to their condition prior to the commencement of such Assessment, unless Seller requests otherwise, and shall promptly dispose of all drill cuttings, corings, or other investigative-derived wastes generated in the course of the Assessment.  Purchaser shall maintain, and shall cause its officers, employees, representatives, consultants and advisors to maintain, all information obtained by Purchaser pursuant to any Assessment or other due diligence activity as strictly confidential until the Closing occurs, unless disclosure of any facts discovered through such Assessment is required under any Laws.  Purchaser shall provide Seller with a copy of the final draft of all environmental reports prepared by, or on behalf of, Purchaser with respect to any Assessment or Invasive Activity conducted on the Properties.  In the event that any necessary disclosures under applicable Laws are required with respect to matters discovered by any Assessment conducted by, for or on behalf of Purchaser, Purchaser agrees that Seller shall be the responsible party for disclosing such matters to the appropriate Governmental Bodies; provided that, if Seller fails to promptly make such disclosure and Purchaser or any of its Affiliates is legally obligated to make such disclosure, such Person shall have the right to fully comply with such legal obligation.

Section 4.2            NORM, Wastes and Other Substances.

Purchaser acknowledges that the Assets have been used for the exploration, development, and production of Hydrocarbons and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Properties or associated with the Assets.  Equipment and sites included in the Assets may contain Hazardous Materials, including NORM.  NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms.  The wells, materials, and equipment located on the Properties or included in the Assets may contain Hazardous Materials, including NORM.  Hazardous Materials, including NORM, may have come in contact with various environmental media, including without limitation, water, soils or sediment.  Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media and Hazardous Materials, including NORM, from the Assets.

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Section 4.3            Environmental Defects.

If, as a result of its investigation pursuant to Section 4.1, Purchaser determines that with respect to the Assets, there exists a violation of an Environmental Law (other than with respect to NORM) (in each case, an “Environmental Defect”), then on or prior to April 17, 2007 (the “Environmental Claim Date”), Purchaser may notify Seller in writing of such Environmental Defect (an “Environmental Defect Notice”).  For all purposes of this Agreement, Purchaser shall be deemed to have waived any Environmental Defect which Purchaser fails to assert as an Environmental Defect by an Environmental Defect Notice received by Seller on or before the Environmental Claim Date.  To be effective, each such notice shall set forth (i) a description of the matter constituting the alleged Environmental Defect, (ii) the Units/Warranty Wells and associated Assets affected by the Environmental Defect, (iii) the estimated Lowest Cost Response to eliminate the Environmental Defect in question (the “Environmental Defect Amount”), and (iv) supporting documents reasonably necessary for Seller to verify the existence of the alleged Environmental Defect and the Environmental Defect Amount.  Commencing on February 15, 2007, Purchaser shall furnish Seller once every two (2) weeks until the Environmental Claim Date with an Environmental Defect Notice if any officer of Purchaser or its Affiliates discover or become aware of an Environmental Defect during such two (2) week period.  Seller shall have the right, but not the obligation, to cure any Environmental Defect before Closing or, provided that the parties shall have agreed to the general plan of remediation with respect to such Environmental Defect and the time period by which such remediation shall take place, after Closing.  If Seller disagrees with any of Purchaser’s assertions with respect to the existence of an Environmental Defect or the Environmental Defect Amount, Purchaser and Seller will attempt to resolve the dispute prior to Closing.  If the dispute cannot be resolved within ten (10) days of the first meeting of Purchaser and Seller, either party may submit the dispute to an environmental consultant approved in writing by Seller and Purchaser that is experienced in environmental corrective action at oil and gas properties in the relevant jurisdiction and that shall not have performed professional services for either party or any of their respective Affiliates during the previous five years (the “Independent Expert”).  The Independent Expert may elect to conduct the dispute resolution proceeding by written submissions from Purchaser and Seller with exhibits, including interrogatories, supplemented with appearances by Purchaser and Seller, if necessary, as the Independent Expert may deem necessary.  After the parties and Independent Expert have had the opportunity to review all such submissions, the Independent Expert shall call for a final, written offer of resolution from each party.  The Independent Expert shall render its decision within twenty (20) Business Days of receiving such offers by selecting one or the other of the offers. The Independent Expert may not award damages, interest or penalties to either party with respect to any matter.  The decision of the Independent Expert shall be final and binding upon both parties, without right of appeal.  Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case to the Independent Expert. Each party shall bear one-half of the costs and expenses of the Independent Expert.  The parties shall adjust the Purchase Price to reflect the Environmental Defect Amounts, as agreed by the parties or as determined by the Independent Expert, for all uncured Environmental Defects; provided, that notwithstanding anything to the contrary, (a) in no event shall there be any adjustments to the Purchase Price for any individual uncured Environmental Defect for which the Environmental Defect Amount therefor does not exceed $100,000 (“Individual Environmental Deductible”); and (b) in no event shall there be any adjustments to the Purchase Price for any uncured Environmental Defect unless the aggregate Environmental Defect Amount attributable to all such Environmental Defects, taken together with the aggregate Title Defect Amounts attributable to all uncured Title Defects, exceeds the Aggregate Defect Deductible, after which point Purchaser shall be entitled to adjustments to the Purchase Price or other remedies only with respect to uncured Title Defects and uncured

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Environmental Defects where the aggregate Title Defect Amounts and Environmental Defect Amounts attributable thereto are in excess of such Aggregate Defect Deductible.  To the extent the Independent Expert fails to determine any disputed Environmental Defect Amounts prior to Closing, then, within ten (10) days after the Independent Expert delivers written notice to Purchaser and Seller of his award with respect to an Environmental Defect Amount, Seller shall pay to Purchaser the amount, if any, so awarded by the Independent Examiner, plus interest payable on such amount at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date on which such amount is paid to Purchaser.

Section 4.4            Inspection Indemnity.

PURCHASER HEREBY AGREES TO DEFEND, INDEMNIFY, RELEASE, PROTECT, SAVE AND HOLD HARMLESS THE SELLER INDEMNIFIED PERSONS FROM AND AGAINST ANY AND ALL LOSSES ARISING OUT OF OR RELATING TO ANY DUE DILIGENCE ACTIVITY CONDUCTED BY PURCHASER OR ITS AGENTS, WHETHER BEFORE OR AFTER THE EXECUTION OF THIS AGREEMENT, REGARDLESS OF FAULT.  The indemnity obligation set forth in this Section 4.4 shall survive the Closing or termination of this Agreement.

ARTICLE 5
REPRESENTATIONS AND WARRANTIES OF SELLER

Section 5.1            Generally.

(a)           Any representation or warranty qualified “to the knowledge of Seller” or “to Seller’s knowledge” or with any similar knowledge qualification is limited to matters within the actual knowledge of the officers of Seller or its Affiliates or those employees of Seller or any of its Affiliates who have responsibility for the Assets and who have the following titles:  General Manager and Production Engineering Manager.  “Actual knowledge” for purposes of this Agreement means information actually personally known by such Persons.

(b)           Inclusion of a matter on a Schedule in relation to a representation or warranty which addresses matters having a Material Adverse Effect shall not be deemed an indication that such matter does, or may, have a Material Adverse Effect. Likewise, the inclusion of a matter on a Schedule in relation to a representation or warranty shall not be deemed an indication that such matter necessarily would, or may, breach such representation or warranty absent its inclusion on such Schedule. Matters may be disclosed on a Schedule to this Agreement for purposes of information only.

(c)           Subject to the foregoing provisions of this Section 5.1, the disclaimers and waivers contained in Sections 11.10, 11.11 and 11.12 and the other terms and conditions of this Agreement, Seller represents and warrants to Purchaser the matters set out in the remainder of this Article 5.

Section 5.2            Existence and Qualification.

Each of APC and Howell is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business as a foreign corporation where the Assets owned by it are located, except where the failure to so qualify would not have a Material Adverse Effect.  Each of AEP and KMOG is a limited partnership duly formed, validly existing and in good standing under the laws of the State of

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Delaware and is duly qualified to do business as a foreign limited partnership where the Assets owned by it are located, except where the failure to so qualify would not have a Material Adverse Effect.

Section 5.3            Power.

Seller has the corporate or partnership power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

Section 5.4            Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary corporate or partnership action on the part of Seller. This Agreement has been duly executed and delivered by Seller (and all documents required hereunder to be executed and delivered by Seller at Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Seller, enforceable against Seller in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at Law).

Section 5.5            No Conflicts.

Subject to compliance with the Preference Rights and Transfer Requirements set forth in Schedule 5.13 and the HSR Act, the execution, delivery and performance of this Agreement by Seller, and the transactions contemplated by this Agreement will not (i) violate any provision of the certificate of incorporation, bylaws, limited partnership agreement or similar governing documents of Seller, (ii) result in default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or agreement to which Seller is a party or which affect the Assets, (iii) violate any judgment, order, ruling, or decree applicable to Seller as a party in interest, (iv) violate any Laws applicable to Seller or any of the Assets, except for (a) rights to consent by, required notices to, filings with, approval or authorizations of, or other actions by any Governmental Body where the same are not required prior to the assignment of the related Asset or they are customarily obtained subsequent to the sale or conveyance thereof and (b) any matters described in clauses (ii), (iii) or (iv) above which would not have a Material Adverse Effect.

Section 5.6            Liability for Brokers’ Fees.

Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Seller or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 5.7            Litigation.

With respect to the Assets and Seller’s or any of its Affiliates’ ownership, operation, development, maintenance, or use of any of the Assets, except as set forth in: (i) Schedule 5.7(a), no proceeding, arbitration, action, suit, pending settlement, or other legal proceeding of

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any kind or nature before or by any Governmental Body (each, a “Proceeding,” and collectively “Proceedings”) (including any take-or-pay claims) to which Seller or any of its Affiliates is a party and which relates to the Assets is pending or, to Seller’s knowledge, threatened against Seller or any of its Affiliates; (ii) Schedule 5.7(a), to Seller’s knowledge, no Proceeding or investigation to which Seller is not a party which relates to the Assets is pending or threatened; and (iii) Schedule 5.7(b), no notice in writing from any third party (including any Governmental Body) has been received by Seller or any of its Affiliates threatening any Proceeding relating to the Assets which could have a Material Adverse Effect (excluding any notices relating to any Environmental Liabilities or Environmental Law).

Section 5.8            Taxes and Assessments.

(a)           With respect to all Taxes related to the Assets, except as set forth on Schedule 5.8, (i) all reports, returns, statements (including estimated reports, returns or statements), and other similar filings (the “Tax Returns”) relating to the Assets required to be filed by Seller with respect to such Taxes have been timely filed with the appropriate Governmental Body in all jurisdictions in which such Tax Returns are required to be filed; and (ii) such Tax Returns are true and correct in all material respects, and (iii) all Taxes due with respect to such Tax Returns have been paid, except those being contested in good faith.

(b)           With respect to all Taxes related to the Assets, except as set forth on Schedule 5.8, (i) there are not currently in effect any extensions or waivers of any statute of limitations of any jurisdiction regarding the assessment or collection of any such Tax; (ii) there are no Proceedings against the Assets or Seller by any Governmental Body; and (iii) there are no Tax liens on any of the Assets except for liens for Taxes not yet due.

Section 5.9            Compliance with Laws.

Except as disclosed on Schedule 5.9, the Assets are, and the ownership, operation, development, maintenance, and use of any of the Assets are, in compliance with the provisions and requirements of all Laws of all Governmental Bodies having jurisdiction with respect to the Assets, or the ownership, operation, development, maintenance, or use of any of the Assets, except where the failure to so comply would not have a Material Adverse Effect.  Notwithstanding the foregoing, Seller makes no representation or warranty, express or implied, under this Section 5.9 relating to any Environmental Liabilities or Environmental Law.

Section 5.10          Contracts.

Except as disclosed on Schedule 5.10, to the knowledge of Seller, Seller has paid its share of all costs (including all Property Costs) payable by it under the contracts and agreements described in Schedule 1.2(d), or otherwise included in the Contracts.  Seller is in compliance and, to Seller’s knowledge, all counterparties are in compliance under all Contracts, except as disclosed on Schedule 5.10 and except for such non-compliance as would not, individually or the aggregate, have a Material Adverse Effect.

Section 5.11          Payments for Hydrocarbon Production.

Except as set forth on Schedule 5.11, (a) to the knowledge of Seller, all rentals, royalties, excess royalty, overriding royalty interests, Hydrocarbon production payments, and other payments due and payable by Seller to overriding royalty holders and other interest owners under or with respect to the Assets and the Hydrocarbons produced therefrom or

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attributable thereto, have been paid, and (b) Seller is not obligated under any contract or agreement for the sale of gas from the Assets containing a take-or-pay, advance payment, prepayment, or similar provision, or under any gathering, transmission, or any other contract or agreement with respect to any of the Assets to gather, deliver, process, or transport any gas  without then or thereafter receiving full payment therefor.

Section 5.12          Governmental Authorizations.

To Seller’s knowledge, except as disclosed on Schedule 5.12, Seller has obtained and is maintaining all material federal, state and local governmental licenses, permits, franchises, orders, exemptions, variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the “Governmental Authorizations”) that are presently necessary or required for the ownership and operation of the Seller Operated Assets as currently owned and operated (excluding Governmental Authorizations required by Environmental Law). To Seller’s knowledge, except as disclosed in Schedule 5.7(a), Schedule 5.7(b) or Schedule 5.12, (i) Seller has operated the Seller Operated Assets in all material respects in accordance with the conditions and provisions of such Governmental Authorizations, and (ii) no written notices of material violation have been received by Seller, and no Proceedings are pending or, to Seller’s knowledge, threatened in writing that might result in any material modification, revocation, termination or suspension of any such Governmental Authorizations or which would require any material corrective or remediation action by Seller.

Section 5.13          Preference Rights and Transfer Requirements.

To the knowledge of Seller, Schedule 5.13 sets forth all Preference Rights and Transfer Requirements contained in easements, rights-of-way or equipment leases included in the Assets. None of the other Assets, or any portion thereof, is subject to any Preference Right or Transfer Requirement which may be applicable to the transactions contemplated by this Agreement, except for Preference Rights and Transfer Requirements as are set forth on Schedule 5.13.

Section 5.14          Payout Balances.

To Seller’s knowledge, Schedule 5.14 contains a complete and accurate list of the status of any “payout” balance, as of the respective dates set forth therein, for the Wells and Units listed on Exhibit A-1 subject to a reversion or other adjustment at some level of cost recovery or payout (or passage of time or other event other than termination of a Lease by its terms).

Section 5.15          Outstanding Capital Commitments.

As of the date hereof, there are no outstanding AFEs or other commitments to make capital expenditures which are binding on the Assets and which Seller reasonably anticipates will individually require expenditures by the owner of the Assets after the Effective Time in excess of $250,000 other than those shown on Schedule 5.15.

Section 5.16          Imbalances.

To Seller’s knowledge, Schedule 5.16 accurately sets forth in all material respects all of Seller’s Imbalances as of the respective dates set forth therein, arising with respect to the Assets and, except as disclosed in Schedule 5.16, (i) no Person is entitled to receive any

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material portion of Seller’s Hydrocarbons produced from the Assets or to receive material cash or other payments to “balance” any disproportionate allocation of Hydrocarbons produced from the Assets under any operating agreement, gas balancing or storage agreement, gas processing or dehydration agreement, gas transportation agreement, gas purchase agreement, or other agreements, whether similar or dissimilar, (ii) Seller is not obligated to deliver any material quantities of gas or to pay any material penalties or other material amounts, in connection with the violation of any of the terms of any gas contract or other agreement with shippers with respect to the Assets, and (iii) Seller is not obligated to pay any material penalties or other material payments under any gas transportation or other agreement as a result of the delivery of quantities of gas from the Wells in excess of the contract requirements.  Except as set forth on Schedule 5.16, Seller has not received, or is not obligated to receive, prepayments (including payments for gas not taken pursuant to “take or pay” arrangements) for any of Seller’s share of the Hydrocarbons produced from the Properties, as a result of which the obligation exists to deliver Hydrocarbons produced from the Properties after the Effective Time without then or thereafter receiving payment therefor.

Section 5.17          Condemnation.

To Seller’s knowledge, there is no actual or threatened taking (whether permanent, temporary, whole or partial) of any part of the Properties by reason of condemnation or the threat of condemnation.

Section 5.18          Bankruptcy.

There are no bankruptcy, reorganization, or receivership proceedings pending against, or, to Seller’s knowledge, being contemplated by or threatened against Seller.

Section 5.19          PUHCA/NGA.

Seller is not a “holding company,” or a “subsidiary company” of a “holding company,” or an “affiliate” of a “holding company,” or an “affiliate” of a “subsidiary” of a “holding company,” or a “public-utility company” within the meaning of the Public Utility Holding Company Act of 2005, as amended. No consent is required in connection with the transaction contemplated hereby under the Natural Gas Policy Act of 1978, as amended (“NGPA”). Seller is not a natural gas company within the meaning of the Natural Gas Act of 1938 (“NGA”), and neither Seller nor any of its Affiliates has operated any of the Assets in a manner that would subject Seller or any of its Affiliates to the jurisdiction of, or invoke regulation by, the Federal Energy Regulatory Commission under the NGPA or the NGA with respect to the Assets.

Section 5.20          Investment Company.

Seller is not an investment company or a company controlled by an investment company within the meaning of the Investment Company Act of 1940, as amended.

Section 5.21          Production Allowables.

To Seller’s knowledge, Seller has not received written notice that there has been any change proposed in the production allowables for any Wells listed on Exhibit A-1.

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Section 5.22          Plugging and Abandonment.

To Seller’s knowledge, since the Effective Time through the date of this Agreement, Seller has not abandoned, and is not in the process of abandoning, any Wells (nor has it removed, nor is it in the process of removing, any material items of Personal Property, except those replaced by items of substantially equivalent suitability and value).  Except as set forth in Schedule 5.22 or as otherwise would not have a Material Adverse Effect, there are no Wells located on the Leases or the Lands that:

(a)           Seller has received an order from any Governmental Body requiring that such Well be plugged and abandoned;

(b)           formerly produced but that are currently shut in or temporarily abandoned; and

(c)           have been plugged and abandoned but have not been plugged in accordance with all applicable requirements of each Governmental Body having jurisdiction over the Properties.

Section 5.23          Foreign Person.

Seller is not a “foreign person” within the meaning of Section 1445 of the Code.

Section 5.24          Collective Bargaining Agreements.

Neither Seller or any of its Affiliates has agreed to recognize any labor union or other collective bargaining representative of, nor has any labor union or other collective bargaining representative been certified as the exclusive bargaining representative of, any individual employed or otherwise engaged by Seller (or an Affiliate thereof) who is primarily involved in the business associated with the Assets.

ARTICLE 6
REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to Seller the following:

Section 6.1            Existence and Qualification.

Purchaser is a corporation duly organized, validly existing and in good standing under the laws of the state of its incorporation; and Purchaser is duly qualified to do business as a foreign corporation in every jurisdiction in which it is required to qualify in order to conduct its business, except where the failure to so qualify would not have a material adverse effect on Purchaser; and Purchaser is or will be as of Closing duly qualified to do business as a foreign corporation in the respective jurisdictions where the Assets are located.

Section 6.2            Power.

Purchaser has the corporate power to enter into and perform this Agreement and consummate the transactions contemplated by this Agreement.

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Section 6.3            Authorization and Enforceability.

The execution, delivery and performance of this Agreement, and the performance of the transaction contemplated hereby, have been duly and validly authorized by all necessary corporate action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable against Purchaser in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

Section 6.4            No Conflicts.

Subject to compliance with the HSR Act, the execution, delivery and performance of this Agreement by Purchaser, and the  transactions contemplated by this Agreement will not (i) violate any provision of the organizational documents of Purchaser, (ii) result in a default (with due notice or lapse of time or both) or the creation of any lien or encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or agreement to which Purchaser is a party, (iii) violate any judgment, order, ruling, or regulation applicable to Purchaser as a party in interest, or (iv) violate any Law applicable to Purchaser or any of its assets, or (v) require any filing with, notification of or consent, approval or authorization of any Governmental Body or authority, except any matters described in clauses (ii), (iii), (iv) or (v) above which would not have a material adverse effect on Purchaser or the transactions contemplated hereby.

Section 6.5            Liability for Brokers’ Fees.

Seller shall not directly or indirectly have any responsibility, liability or expense, as a result of undertakings or agreements of Purchaser or its Affiliates, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 6.6            Litigation.

There are no Proceedings pending, or to the actual knowledge of Purchaser, threatened in writing before any Governmental Body against Purchaser or any Affiliate of Purchaser which are reasonably likely to impair materially Purchaser’s ability to perform its obligations under this Agreement.

Section 6.7            Financing.

At Closing, Purchaser will have sufficient sources of immediately available funds (in United States dollars) to enable it to pay the Closing Payment to Seller at the Closing and to otherwise satisfy its obligations under this Agreement.

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Section 6.8            Limitation.

Except for the representations and warranties expressly made by Seller in Article 5 of this Agreement, in the Conveyance or confirmed in any certificate furnished or to be furnished to Purchaser pursuant to this Agreement, Purchaser represents and acknowledges that (i) there are no representations or warranties, express, statutory or implied, as to the Assets or prospects thereof, and (ii) Purchaser has not relied upon any oral or written information provided by Seller.  Without limiting the generality of the foregoing, subject to Section 5.7, Purchaser represents and acknowledges that Seller has made and will make no representation or warranty regarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment or any other environmental condition of the Assets.  Purchaser further represents and acknowledges that it is knowledgeable of the oil and gas business and of the usual and customary practices of producers such as Seller and that it has had access to the Assets, the officers and employees of Seller, and the books, records and files made available by Seller relating to the Assets, and in making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Purchaser has relied solely on the basis of its own independent due diligence investigation of the Assets and Seller’s representations and warranties contained in this Agreement.

Section 6.9            SEC Disclosure.

Purchaser is acquiring the Assets for its own account for use in its trade or business, and not with a view toward or for sale associated with any distribution thereof, nor with any present intention of making a distribution thereof within the meaning of the Securities Act of 1933, as amended, and applicable state securities laws.

Section 6.10          Bankruptcy.

There are no bankruptcy, reorganization or receivership proceedings pending against, or, to the knowledge of Purchaser, being contemplated by, or threatened against Purchaser.

Section 6.11          Qualification.

As of Closing, Purchaser will be qualified to own and assume operatorship of federal and state oil, gas and mineral leases in all jurisdictions where the Assets to be transferred to it are located, and the consummation of the transactions contemplated in this Agreement will not cause Purchaser to be disqualified as such an owner or operator.  To the extent required by the applicable Law, as of the Closing, Purchaser will have lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, such state or federal regulations governing the ownership and operation of the Assets.

ARTICLE 7
COVENANTS OF THE PARTIES

Section 7.1            Access.

(a)           From the date of this Agreement until the Closing, Seller shall cooperate with Purchaser and provide Purchaser and its representatives, consultants and advisors, reasonable access to the Assets and access to the Records, but only to the extent that Seller may do so without violating any obligations to any third party and to the extent that Seller has authority to grant such access without breaching any restriction legally binding on Seller.  Purchaser shall conduct all such inspections and other information gathering described above only (i) (x) during

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regular business hours and (y) during any weekends and after hours requested by Purchaser that can be reasonably accommodated by Seller, and (ii) in a manner which will not unduly interfere with Seller’s operation of the Assets.  All information obtained by Purchaser and its representatives pursuant to this Section 7.1 shall be subject to the terms of that certain confidentiality agreement dated December 7, 2006 (the “Confidentiality Agreement”), by and between APC and Purchaser.

(b)           Seller shall use its commercially reasonable efforts to prepare, at the sole cost and expense of Purchaser, either (i) if relief is granted by the U.S. Securities and Exchange Commission, statements of revenues and direct operating expenses and all notes thereto related to the Assets or (ii) if such relief is not granted by the U.S. Securities and Exchange Commission, the financial statements required by the U.S. Securities and Exchange Commission (such financial statements set forth in the foregoing clauses (i) and (ii), as applicable, the “Statements of Revenues and Expenses”) in each case of clauses (i) and (ii), that will be required of Purchaser or any of its Affiliates in connection with reports, registration statements and other filings to be made by Purchaser or any of its Affiliates related to the transactions contemplated by this Agreement with the U.S. Securities and Exchange Commission pursuant to the Securities Act, or the Exchange Act, in such form that such statements and the notes thereto can be audited.  Seller (x) shall cooperate with and permit Purchaser to reasonably participate in the preparation of the Statements of Revenues and Expenses and (y) shall provide Purchaser and its representatives with reasonable access to the personnel of Seller and its Affiliates who engage in the preparation of the Statements of Revenues and Expenses.

(c)           Promptly after the date of this Agreement, Seller shall engage KPMG, LLP to perform an audit of the Statements of Revenues and Expenses and shall use commercially reasonable efforts to cause KPMG, LLP to issue unqualified opinions with respect to Statements of Revenues and Expenses (the Statements of Revenues and Expenses and related audit opinions being hereinafter referred to as the “Audited Financial Statements”) and provide its written consent for the use of its audit reports with respect to Statements of Revenues and Expenses in reports filed by Purchaser or any of its Affiliates under the Exchange Act or the Securities Act, as needed.  Purchaser shall reimburse Seller for all fees charged by KPMG, LLP pursuant to such engagement.  Seller shall take all action as may be necessary to facilitate the completion of such audit and delivery of the Audited Financial Statements to Purchaser or any of its Affiliates as soon as reasonably practicable, but no later than ten (10) days prior to the date that such Audited Financial Statements would be required to be filed by Purchaser or any of its Affiliates with a report on Form 8-K or an amendment thereto under the Exchange Act.  Seller shall provide to Purchaser a draft of the Audited Financial Statements no later than fifteen (15) days prior to the date that such Audited Financial Statements would be required to be filed by Purchaser or any of its Affiliates with a report on Form 8-K or an amendment thereto under the Exchange Act.  Seller shall keep Purchaser regularly informed regarding the progress of such audit and also shall periodically provide Purchaser with copies of drafts of the Audited Financial Statements and related audit opinions.

Section 7.2            Government Reviews.

(a)           Other than with respect to filings, negotiations and applications with respect to the HSR Act, which are addressed in Section 7.2(b), Seller and Purchaser shall in a timely manner (a) make all required filings, if any, with and prepare applications to and conduct negotiations with, each Governmental Body as to which such filings, applications or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby and

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(b) provide such information as each may reasonably request to make such filings, prepare such applications and conduct such negotiations.  Each party shall cooperate with and use all commercially reasonable efforts to assist the other with respect to such filings, applications and negotiations.

(b)           As promptly as practicable, and in any event not more than thirty (30) days following the date of this Agreement, Seller and Purchaser will file with the Federal Trade Commission and the Department of Justice, as applicable, the required notification and report forms and will as promptly as practicable furnish any supplemental information which may be requested in connection therewith.  Seller and Purchaser will request expedited treatment (i.e., early termination) of such filing.  Seller and Purchaser shall use commercially reasonable efforts to make all other filings and submissions on a prompt and timely basis in connection with the filings required by this Section 7.2(b) and cooperate with each other and use all commercially reasonable efforts to assist the other with respect to such filings, applications and negotiations.  All filing fees incurred in connection with the filings made pursuant to this Section 7.2 shall be borne fifty (50) percent by Seller and fifty (50) percent by Purchaser.

Section 7.3            Notification of Breaches.

Until the Closing,

(a)           Purchaser shall notify Seller promptly after Purchaser obtains actual knowledge that any representation or warranty of Seller, as applicable, contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect.

(b)           Seller shall notify Purchaser promptly after Seller obtains actual knowledge that any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date, or that any covenant or agreement to be performed or observed by Purchaser prior to or on the Closing Date has not been so performed or observed in any material respect.

(c)           If any of Purchaser’s or Seller’s representations or warranties is untrue or shall become untrue in any material respect between the date of execution of this Agreement and the Closing Date, or if any of Purchaser’s or Seller’s covenants or agreements to be performed or observed prior to or on the Closing Date shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing, then such breach shall be considered not to have occurred for all purposes of this Agreement.  No such notification shall affect the representations or warranties of the parties or the conditions to their respective obligations hereunder.

(d)           There shall be no breach of the covenants in this Section as a result of a party’s failure to report a breach of any representation or warranty or a failure to perform or observe any covenant or agreement of which it had knowledge if the party subject to the breach or failure also had knowledge thereof prior to Closing.

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Section 7.4            Letters-in-Lieu; Assignments; Operatorship.

(a)           Seller will execute on the Closing Date letters in lieu of division and transfer orders relating to the Assets, on forms prepared by Seller and reasonably satisfactory to Purchaser, to reflect the transaction contemplated hereby.

(b)           Seller will prepare and execute, and Purchaser will execute, on the Closing Date, all assignments necessary to convey to Purchaser all federal and state Leases in the form as prescribed by the applicable Governmental Body and otherwise acceptable to Purchaser and Seller.

(c)           Seller makes no representations or warranties to Purchaser as to transferability or assignability of operatorship of any Seller Operated Assets.  Rights and obligations associated with operatorship of such Properties are governed by operating and similar agreements covering the Properties and will be determined in accordance with the terms of such agreements. However, Seller will assist Purchaser in Purchaser’s efforts to succeed Seller as operator of any Wells and Units included in the Assets.  Purchaser shall, promptly following Closing, file all appropriate forms and declarations or bonds with federal and state agencies relative to its assumption of operatorship.  For all Seller Operated Assets, Seller shall execute and deliver to Purchaser, and Purchaser shall promptly file the appropriate forms (including a change of operator card on the form established by the Department of Conservation, duly executed by Seller and naming Purchaser as the successor operator) with the applicable regulatory agency transferring operatorship of such Assets to Purchaser.

Section 7.5            Public Announcements.

Until the Closing, neither Seller nor Purchaser shall make any press release or other public announcement regarding the existence of this Agreement, the contents hereof or the transactions contemplated hereby without the prior written consent of the others; provided, however, the foregoing shall not restrict disclosures by Purchaser or Seller which are required by applicable securities or other laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates; and provided, further, that, Purchaser may disclose the existence and contents of this Agreement, the transactions contemplated hereby and information regarding the Assets to the Standard & Poor’s and Moody’s rating agencies and any actual or potential lenders or other financing sources of Purchaser.  At or after Closing, the content of any press release or public announcement first announcing the consummation of this transaction shall be subject to the prior review and reasonable approval of Seller and Purchaser; provided, however, the foregoing shall not restrict disclosures by Purchaser or Seller which are required by applicable securities or other laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing party or its Affiliates.

Section 7.6            Operation of Business.

Except as set forth on Schedule 7.6, until the Closing, Seller (i) will operate the Assets and the business thereof in the ordinary course, (ii) will not, without the prior written consent of Purchaser, which consent shall not be unreasonably withheld, commit to any operation, or series of related operations thereon, reasonably anticipated to require future capital expenditures by Purchaser as owner of the Assets in excess of $150,000, or make any capital expenditures in respect of the Assets in excess of $150,000, or terminate, materially amend, execute or extend any material Contracts affecting the Assets, (iii) will maintain insurance coverage on the Assets presently furnished by nonaffiliated third parties in the amounts and of the types presently in force, (iv) will use commercially reasonable efforts to maintain in full force

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and effect all Leases, (v) will maintain all material governmental permits and approvals affecting the Assets, (vi) will not transfer, farmout, sell, hypothecate, encumber or otherwise dispose of any Assets, except for (A) sales and dispositions of Hydrocarbon production in the ordinary course of business consistent with past practices or (B) transfers, farmouts, hypothecations, encumbrances or other dispositions of Assets, in one or more transactions, not exceeding $500,000 of consideration (in any form), in the aggregate, (vii) will not enter into any settlement or agreement with respect to Taxes, or make or change any election with respect to Taxes, relating to the Assets and (viii) will not commit to do any of the foregoing. Purchaser’s approval of any action restricted by this Section 7.6 shall be considered granted within ten (10) days (unless a shorter time is reasonably required by the circumstances and such shorter time is specified in Seller’s written notice) of Seller’s written notice to Purchaser requesting such consent unless Purchaser notifies Seller to the contrary in writing during that period. In the event of an emergency, Seller may take such action as a prudent operator would take and shall notify Purchaser of such action promptly thereafter.

Purchaser acknowledges that Seller may own an undivided interest in certain of the Assets, and Purchaser agrees that the acts or omissions of the other working interest owners who are not affiliated with Seller shall not constitute a violation of the provisions of this Section 7.6 nor shall any action required by a vote of working interest owners constitute such a violation so long as Seller has voted its interest in a manner consistent with the provisions of this Section 7.6.

Section 7.7            Preference Rights and Transfer Requirements.

(a)           The transactions contemplated by this Agreement are expressly subject to all validly existing and applicable Preference Rights and Transfer Requirements.  Prior to the Closing Date, Seller shall initiate all procedures which are reasonably required to comply with or obtain the waiver of all Preference Rights and Transfer Requirements set forth in Schedule 5.13 with respect to the transactions contemplated by this Agreement.  Seller shall use its commercially reasonable efforts to obtain all applicable consents and to obtain waivers of applicable Preference Rights; provided, however, Seller shall not be obligated to pay any consideration to (or incur any cost or expense for the benefit of) the holder of any Preference Right or Transfer Requirement in order to obtain the waiver thereof or compliance therewith.

(b)           If the holder of a Preference Right elects prior to Closing to purchase the Asset subject to a Preference Right (a “Preference Property”) in accordance with the terms of such Preference Right, and Seller receives written notice of such election prior to the Closing, such Preference Property will be eliminated from the Assets and the Purchase Price shall be reduced by the Allocated Value of the Preference Property.

(c)           If

(i)a third party brings any suit, action or other proceeding prior to the Closing seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby in connection with a claim to enforce a Preference Right;

(ii)an Asset is subject to a Transfer Requirement that provides that transfer of such Asset without compliance with such Transfer Requirement will result in termination or other material impairment of any rights in relation

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to such Asset, and such Transfer Requirement is not waived, complied with or otherwise satisfied prior to the Closing Date; or

(iii)the holder of a Preference Right does not elect to purchase such Preference Property or waive such Preference Right with respect to the transactions contemplated by this Agreement prior to the Closing Date and the time in which the Preference Right may be exercised has not expired,

then, unless otherwise agreed by Seller and Purchaser, the Asset or portion thereof affected by such Preference Right or Transfer Requirement (a “Retained Asset”) shall be held back from the Assets to be transferred and conveyed to Purchaser at Closing and the Purchase Price to be paid at Closing shall be reduced by the Allocated Value of such Retained Asset pursuant to Section 7.7(b). Any Retained Asset so held back at the initial Closing will be conveyed to Purchaser at a delayed Closing (which shall become the new Closing Date with respect to such Retained Asset), within ten (10) days following the date on which the suit, action or other proceeding, if any, referenced in clause (i) above is settled or a judgment is rendered (and no longer subject to appeal) permitting transfer of the Retained Asset to Purchaser pursuant to this Agreement and Seller obtains, complies with, obtains a waiver of or notice of election not to exercise or otherwise satisfies all remaining Preference Rights and Transfer Requirements with respect to such Retained Asset as contemplated by this Section (or if multiple Assets are Retained Assets, on a date mutually agreed to by the parties in order to consolidate, to the extent reasonably possible, the number of Closings).  At the delayed Closing, Purchaser shall pay Seller a purchase price equal to the amount by which the Purchase Price was reduced on account of the holding back of such Retained Asset (as adjusted pursuant to Section 2.2 through the new Closing Date therefor); provided, however, if all such Preference Rights and Transfer Requirements with respect to any Retained Asset so held back at the initial Closing are not obtained, complied with, waived or otherwise satisfied as contemplated by this Section within one hundred eighty (180) days after the initial Closing has occurred with respect to any Asset, then such Retained Asset shall be eliminated from the Assets and shall become an Excluded Asset and this Agreement, unless Seller and Purchaser agree to proceed with a closing on such Retained Asset, in which case Purchaser and Purchaser shall be deemed to have waived any objection (and shall be obligated to indemnify the Seller Indemnified Persons for all Losses) with respect to non-compliance with such Preference Rights and Transfer Requirements with respect to such Retained
Asset(s).

(d)           Purchaser acknowledges that Seller desires to sell all of the Assets to Purchaser and would not have entered into this Agreement but for Purchaser’s agreement to purchase all of the Assets as herein provided.  Accordingly, it is expressly understood and agreed that Seller does not desire to sell any Property affected by a Preference Right to Purchaser unless the sale of all of the Assets is consummated by the Closing Date in accordance with the terms of this Agreement.  In furtherance of the foregoing, Seller’s obligation hereunder to sell the Preference Properties to Purchaser is expressly conditioned upon the consummation by the Closing Date of the sale of all of the Assets (other than Retained Assets or other Assets excluded pursuant to the express provisions of this Agreement) in accordance with the terms of this Agreement, either by conveyance to Purchaser or conveyance pursuant to an applicable Preference Right; provided that, nothing herein is intended or shall operate to extend or apply any Preference Right to any portion of the Assets which is not otherwise burdened thereby.  Time is of the essence with respect to the parties’ agreement to consummate the sale of the Assets by the Closing Date (or by the delayed Closing Date pursuant to Section 7.7(c)).

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Section 7.8            Tax Matters.

(a)           Subject to the provisions of Section 12.3, Seller shall be responsible for all Taxes related to the Assets (other than ad valorem, property, severance, Hydrocarbon production and similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, which are addressed in Section 1.4) attributable to any period of time at or prior to the Closing Date, and Purchaser shall be responsible for all such Taxes related to the Assets attributable to any period of time after the Closing Date.  Notwithstanding the foregoing, Seller shall handle payment to the appropriate Governmental Body of all Taxes with respect to the Assets which are required to be paid prior to Closing (and shall file all Tax Returns with respect to such Taxes).  If requested by Purchaser, Seller will assist Purchaser with preparation of all ad valorem and property Tax Returns for periods ending on or before the Closing Date (including any extensions requested).  Seller shall deliver to Purchaser within thirty (30) days of filing copies of all Tax Returns to be filed by Seller relating to the Assets and any supporting documentation to be provided by Seller to Governmental Bodies for Purchaser’s approval, which shall not be unreasonably withheld, excluding Tax Returns related to income tax, franchise tax, or other similar Taxes.  Purchaser shall file all Tax Returns covering Taxes treated as Property Costs that are required to be filed after the Closing Date unless covered above.  With respect to such Tax Returns covering a taxable period which includes the Effective Date, Purchaser shall provide a copy of such Tax Return to Seller within 30 days of filing for Seller’s approval, which shall not be unreasonably withheld.

(b)           Purchaser and Seller shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with the filing of any Tax Returns and any audit, litigation or other Proceeding with respect to Taxes.  Such cooperation shall include the retention and (upon the other party’s request) the provision of records and information which are reasonably relevant to any such audit, litigation or other Proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder.  Each of Purchaser and Seller agrees (i) to retain all books and records with respect to Tax matters pertinent to the acquired assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Purchaser or Seller, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Governmental Body, and (ii) to give the other party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other party so requests, each party shall allow the other party the option of taking possession of such books and records prior to their disposal.  Purchaser and Seller further agree, upon request, to use their commercially reasonable efforts to obtain any certificate or other document from any Governmental Body or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed with respect to the transactions contemplated.

(c)           Purchaser and Seller shall cooperate fully, as and to the extent reasonably requested by the other party, in connection of accommodating a 1031 exchange (as provided for under IRC Section 1031 of the Code).  Purchaser or Seller reserves the right, at or prior to Closing, to assign its rights under this Agreement with respect to all or a portion of the Purchase Price, and that portion of the Assets associated therewith (“1031 Assets”), to a Qualified Intermediary (“QI”) (as that term is defined in Section 1.1031(k)-1(g)(4)(v) of the Treasury Regulations) to accomplish this transaction, in whole or in part, in a manner that will comply with the requirements of a like-kind exchange (“Like-Kind Exchange”) pursuant to Section 1031 of the Code.  If Purchaser so elects, Purchaser may assign its rights under this Agreement to the

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1031 Assets to the QI.  Seller hereby (i) consents to Purchaser’s assignment of its rights in this Agreement with respect to the 1031 Assets, and (ii) if such an assignment is made, agrees to transfer all or a portion of the Assets into the qualified trust account at Closing as directed in writing by Purchaser.  Purchaser acknowledges and agrees that a whole or partial assignment of this Agreement to a QI shall not release Purchaser from any of its respective liabilities and obligations to Seller or expand any liabilities or obligations of Seller under this Agreement.  Neither party represents to the other that any particular tax treatment will be given to either party as a result of the Like-Kind Exchange.  Seller shall not be obligated to pay any additional costs or incur any additional obligations in its sale of the Assets if such costs are the result of Purchaser’s Like-Kind Exchange, and Purchaser shall hold harmless and indemnify Seller from and against all claims, losses and liabilities (including reasonable attorneys’ fees, court costs and related expenses), if any, resulting from such a Like-Kind Exchange.

Section 7.9            Further Assurances.

After Closing, Seller and Purchaser each agrees to take such further actions and to execute, acknowledge and deliver all such further documents as are reasonably requested by the other party for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement.

Section 7.10          Reserved.

Section 7.11          Insurance; Financial Information.

(a)           Effective as of the Closing Date, Purchaser shall cause the following insurance to be carried and maintained with respect to the Assets: (i) general liability insurance with combined single limits per occurrence of not less than $1,000,000.00 for bodily injury and property damage, including property damage by blowout and cratering, completed operations, and contractual liability as respects any contract into which Purchaser may enter under the terms of this Agreement; and (ii) operators extra expense insurance with limits of not less than $1,000,000.00 per occurrence, covering the costs of controlling a blowout, and certain other related and/or resulting costs and seepage and pollution liability.

(b)           Between the date of this Agreement and the Closing Date, Seller shall deliver to the Chief Operating Officer of Purchaser copies of all production reports and daily drilling reports relating to Seller’s operation of the Assets promptly after the preparation thereof in the ordinary course of business.

Section 7.12          No Solicitation of Transactions.

So long as Purchaser is not in default of this Agreement or, if Purchaser is in default hereunder, Purchaser cures such default within ten (10) days after receiving written notice thereof from Seller, Seller shall not, directly or indirectly, through any officer, director, stockholder, employee, agent, financial advisor, banker or other representative or Affiliate, or otherwise, solicit, initiate, or encourage the submission of any proposal or offer from any Person relating to any acquisition or purchase of all or any material portion of the Assets or participate in any negotiations regarding, or furnish to any other Person any information with respect to, or otherwise cooperate in any way with, or assist or participate in, facilitate, or encourage, any effort or attempt by any other Person to do or seek any of the foregoing.  Seller shall communicate as soon as reasonably practicable to Purchaser the material terms of any such proposal (and the identity of the party making such proposal) which it may receive and, if such

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proposal is in writing, Seller shall promptly deliver a copy of such proposal to Purchaser.  Seller agrees not to release any third party from, or waive any provision of, any confidentiality agreement relating to the Assets to which Seller or any of its Affiliates is a party.  Seller immediately shall cease and cause to be terminated all existing discussions or negotiations with any parties conducted heretofore with respect to any of the foregoing.

Section 7.13          Transition Services Agreement.

Between the date hereof and the Closing Date, each of Seller and Purchaser shall use its reasonable efforts to negotiate in good faith a form of transition services agreement on terms that are mutually acceptable to Seller and Purchaser to be executed at Closing by Seller and Purchaser (the “Transition Services Agreement”).

Section 7.14          Employees.

As promptly as reasonably practical following the execution of this Agreement, the parties will use reasonable efforts to work together concerning employees.

Section 7.15          Hedges.

(a)           Seller has entered into the hedging transactions set forth on Schedule 7.15 (the “Hedging Transactions”) with the counterparties specified therein (the “Counterparties”).  Purchaser covenants and agrees that each of the Counterparties has agreed and will (i) allow the assignment by Seller to Purchaser at the Closing of all of the trades that are the subject of the Hedging Transactions and (ii) release Seller from any and all obligations and liabilities related or attributable to such Hedging Transactions upon such assignment.  The respective agreements between Seller and each Counterparty shall be evidenced by a Novation Agreement that is in form and substance reasonably acceptable to Seller.

(b)           At the Closing, Purchaser shall accept an assignment from Seller of all of the trades that are the subject of the Hedging Transactions and shall assume all obligations and liabilities attributable thereto pursuant to documentation required by the Counterparties.

(c)           Within five (5) Business Days of the termination by Purchaser or Seller, as the case may be, of this Agreement in accordance with Section 10.1, Seller shall furnish to Purchaser written notice of whether it elects to unwind the Hedging Transactions.  If Seller notifies Purchaser that it does not elect to unwind the Hedging Transactions, Purchaser shall have no further obligations whatsoever to Seller with respect to the Hedging Transactions.  However, if Seller notifies Purchaser that it elects to unwind the Hedging Transactions, Purchaser shall be obligated for and shall promptly pay, and Purchaser does hereby agree to indemnify and hold harmless Seller from and against, any and all Losses suffered by Seller resulting from or attributable to the Hedging Transactions and the unwind thereof unless the termination of this Agreement resulted from the default by Seller of its obligations under this Agreement, in which case Purchaser shall not be liable for such Losses.

Section 7.16          Contribution of Oklahoma Assets.

Purchaser has requested that Seller, at least ten (10) Business Days prior to Closing, (a) form a Delaware limited liability company and (b) contribute or otherwise transfer all of the Properties and other related Assets located in Oklahoma to such limited liability company prior to Closing.  Although Purchaser acknowledges that Seller is under no obligation to

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accommodate Purchaser’s request, Seller agrees to analyze such request and to notify Purchaser within ten (10) Business Days after the date hereof as to whether Seller agrees to accommodate such request.  In the event Seller elects to accommodate Purchaser’s request, Seller shall convey all membership interests of such Delaware limited liability company to Purchaser as part of the Assets at Closing.  Purchaser further acknowledges that if Seller elects not to accommodate Purchaser’s request, Purchaser shall nonetheless be obligated to consummate the transactions contemplated under this Agreement in accordance with the terms hereof.

Section 7.17          [RESERVED].

Section 7.18          Cure of Misrepresentations.

If any of the representations and warranties contained in Article 5 hereof are determined (whether by notice from Purchaser or otherwise) to have been untrue or incorrect as of the date of this Agreement, then any cure by Seller of same shall be at its own expense.

Section 7.19          NAGS.

Anadarko Gathering Company shall have the right to convey NAGS to any Permitted NAGS Buyer without the prior consent of Purchaser, but not to any other Person without obtaining the prior written consent of Purchaser, which consent shall not be unreasonably withheld.  As a condition to such conveyance, the Permitted NAGS Buyer shall acquire NAGS subject to the terms of the NAGS Agreement.

ARTICLE 8
CONDITIONS TO CLOSING

Section 8.1            Conditions of Seller to Closing.

The obligations of Seller to consummate the transactions contemplated by this Agreement are subject, at the option of Seller, to the satisfaction or waiver by Seller on or prior to Closing of each of the following conditions:

(a)           Representations. Each of the representations and warranties of Purchaser contained in this Agreement shall be true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects (other than those representations and warranties of Purchaser that are qualified by materiality, which shall be true and correct in all respects) as of such specified date;

(b)           Performance.  Purchaser shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)           Proceedings.  No Proceeding by a third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order,

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writ, injunction or decree shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby; provided, however, the Closing shall proceed notwithstanding any Proceedings seeking to restrain, enjoin or otherwise prohibit consummation of the transactions contemplated hereby brought by holders of Preference Rights seeking to enforce such rights with respect to the Assets with aggregate Allocated Values of less than ten percent (10%) of the total unadjusted Purchase Price, and the Assets subject to such Proceedings shall be treated in accordance with Section 7.7;

(d)           Deliveries.  Purchaser shall have delivered (or be ready, willing and able to immediately deliver) to Seller duly executed counterparts of the Conveyance and all other documents and certificates to be delivered by Purchaser under Section 9.3 and shall have performed (or be ready, willing and able to immediately perform) the other obligations required to be performed by it under Section 9.3;

(e)           Title Defects.  The sum of all asserted but uncured Title Defect Amounts for Title Defects determined under Section 3.4(g) prior to Closing, less the sum of all Title Benefit Amounts for Title Benefits determined under Section 3.4(h) prior to the Closing, plus Environmental Defects Amounts attributable to Environmental Defects and plus Losses from casualties to and takings of the Assets, determined or asserted in accordance with this Agreement, shall be less than ten percent (10%) of the total unadjusted Purchase Price; and

(f)            HSR Act.  Any waiting period applicable to the consummation of the transaction contemplated by this Agreement under the HSR Act shall have lapsed or terminated (by early termination or otherwise).

Section 8.2            Conditions of Purchaser to Closing.

The obligations of Purchaser to consummate the transactions contemplated by this Agreement are subject, at the option of Purchaser, to the satisfaction or waiver by Purchaser on or prior to Closing of each of the following conditions:

(a)           Representations. Each of the representations and warranties of Seller contained in this Agreement shall be true and correct in all material respects (other than those representations and warranties of Seller that are qualified by materiality or Material Adverse Effect, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date, except to the extent that any such representation or warranty is made as of a specified date, in which case such representation or warranty shall have been true and correct in all material respects (other than those representations and warranties of Seller that are qualified by materiality or Material Adverse Effect, which shall be true and correct in all respects) as of such specified date;

(b)           Performance. Seller shall have performed and observed, in all material respects, all covenants and agreements to be performed or observed by it under this Agreement prior to or on the Closing Date;

(c)           Proceedings.  No Proceeding by a third party (including any Governmental Body) seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement shall be pending before any Governmental Body and no order,

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writ, injunction or decree shall have been entered and be in effect by any court or any Governmental Body of competent jurisdiction, and no statute, rule, regulation or other requirement shall have been promulgated or enacted and be in effect, that on a temporary or permanent basis restrains, enjoins or invalidates the transactions contemplated hereby; provided, however, the Closing shall proceed notwithstanding any Proceedings seeking to restrain, enjoin or otherwise prohibit consummation of the transactions contemplated hereby brought by holders of Preference Rights seeking to enforce such rights with respect to the Assets with aggregate Allocated Values of less than ten percent (10%) of the total unadjusted Purchase Price, and the Assets subject to such Proceedings shall be treated in accordance with Section 7.7;

(d)           Deliveries.  Seller shall have delivered (or be ready, willing and able to immediately deliver) to Purchaser duly executed counterparts of the Conveyance and all other documents and certificates to be delivered by Seller under Section 9.2;

(e)           Title Defects.  The sum of all asserted but uncured Title Defect Amounts for Title Defects determined under Section 3.4(g) prior to the Closing, less the sum of all Title Benefit Amounts for Title Benefits determined under Section 3.4(h) prior to the Closing, plus Environmental Defects Amounts attributable to Environmental Defects and plus Losses from casualties to and takings of the Assets, determined or asserted in accordance with this Agreement, shall be less than ten percent (10%) of the unadjusted Purchase Price;

(f)            HSR Act.  Any waiting period applicable to the consummation of the transaction contemplated by this Agreement under the HSR Act shall have lapsed or terminated (by early termination or otherwise); and

(g)           Required Transfer Requirements.  The sum of all Allocated Values for all Retained Assets resulting from Transfer Requirements that have not been obtained or waived prior to Closing shall not exceed $17,200,000.

ARTICLE 9
CLOSING

Section 9.1            Time and Place of Closing.

(a)           Unless this Agreement shall have been terminated and the transactions herein contemplated shall have been abandoned pursuant to Article 10, and subject to the satisfaction or waiver of the conditions set forth in Article 8 (other than conditions the fulfillment of which by their nature is to occur at the completion of the transactions contemplated by this Agreement (the “Closing”)), the Closing shall take place at 10:00 a.m., local time, on May 2, 2007, at the offices of Fulbright & Jaworski L.L.P., Houston, Texas, unless another date, time or place is mutually agreed to in writing by Purchaser and Seller.  If any of the conditions (other than conditions the fulfillment of which by their nature is to occur at the Closing) set forth in Article 8 are not satisfied or waived at the time the Closing is to occur pursuant to the foregoing sentence of this Section 9.1(a), then the Closing shall occur on a date thereafter that is the third Business Day after the satisfaction or waiver of all such conditions.

(b)           The date on which the Closing occurs is herein referred to as the “Closing Date.”

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Section 9.2            Obligations of Seller at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Seller shall deliver or cause to be delivered to Purchaser, or perform or cause to be performed, the following:

(a)           the Conveyance in sufficient duplicate originals to allow recording in all appropriate jurisdictions and offices, duly executed by Seller;

(b)           letters-in-lieu of transfer orders covering the Assets, duly executed by Seller;

(c)           a certificate duly executed by an authorized corporate officer of Seller, dated as of Closing, certifying on behalf of Seller that the conditions set forth in Section 8.2(a) and Section 8.2(b) have been fulfilled;

(d)           a legal opinion of APC’s Associate General Counsel, dated as of the Closing, regarding the due authorization, execution, delivery and performance by Seller of this Agreement and the transactions contemplated hereby, in form and substance reasonably satisfactory to Purchaser;

(e)           the Transition Services Agreement, duly executed by Seller; and

(f)            the Seismic License, duly executed by Seller.

Section 9.3            Obligations of Purchaser at Closing.

At the Closing, upon the terms and subject to the conditions of this Agreement, Purchaser shall deliver or cause to be delivered to Seller, or perform or caused to be performed, the following:

(a)           a wire transfer of the Closing Payment, in same-day funds;

(b)           the Conveyance, duly executed by Purchaser;

(c)           letters-in-lieu of transfer orders covering the Assets, duly executed by Purchaser;

(d)           a certificate by an authorized corporate officer of Purchaser, dated as of Closing, certifying on behalf of Purchaser that the conditions set forth in Section 8.1(a) and Section 8.1(b) have been fulfilled;

(e)           a legal opinion of counsel to Purchaser, dated as of the Closing, regarding the due authorization, execution, delivery and performance by Purchaser of this Agreement and the transactions contemplated hereby, in form and substance reasonably satisfactory to Seller;

(f)            the Transition Services Agreement, duly executed by Purchaser; and

(g)           the Seismic License, duly executed by Purchaser.

Section 9.4            Closing Adjustments.

(a)           Not later than three (3) Business Days prior to the Closing Date, Seller shall prepare and deliver to Purchaser, based upon the best information available to Seller, a preliminary settlement statement estimating the Adjusted Purchase Price after giving effect to all adjustments listed in Section 2.2.  The estimate delivered in accordance with this Section

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9.4(a) shall constitute the dollar amount to be paid by Purchaser to Seller at the Closing (the “Closing Payment”). Until one (1) Business Day before the Closing Date, Purchaser shall have the opportunity to review and discuss the preliminary settlement statement with Seller; provided, however, Seller shall not be required to make any change thereto to which Seller does not agree.

(b)           As soon as reasonably practicable after the Closing but not later than ninety (90) days following the Closing Date, Seller shall prepare and deliver to Purchaser a statement setting forth the final calculation of the Agreed Purchase Price and showing the calculation of each adjustment, based, to the extent possible, on actual credits, charges, receipts and other items before and after the Effective Time and taking into account all adjustments provided for in this Agreement (the “Final Purchase Price”). Seller shall, at Purchaser’s request, supply reasonable documentation available to support any credit, charge, receipt or other item.  Seller shall afford Purchaser and its representatives the opportunity to review such statement and the supporting schedules, analyses, workpapers, and other underlying records or documentation as are reasonably necessary and appropriate in Purchaser’s review of such statement.  Each party shall cooperate fully and promptly with the other and their respective representatives in such examination with respect to all reasonable requests related thereto.  As soon as reasonably practicable but not later than the 30th day following receipt of Seller’s statement hereunder, Purchaser shall deliver to Seller a written report containing any changes that Purchaser proposes be made to such statement. Seller and Purchaser shall undertake to agree on the final statement of the Final Purchase Price no later than one hundred eighty (180) days after the Closing Date (the “Final Settlement Date”).  In the event that Seller and Purchaser cannot reach agreement by the Final Settlement Date, either party may refer the remaining matters in dispute to Ernst & Young LLP, or such other nationally-recognized independent accounting firm as may be mutually accepted by Purchaser and Seller, for review and final determination (the “Agreed Accounting Firm”).  If issues are submitted to the Agreed Accounting Firm for resolution, Seller and Purchaser shall each enter into a customary engagement letter with the Agreed Accounting Firm at the time the issues remaining in dispute are submitted to the Agreed Accounting Firm.  The Agreed Accounting Firm will be directed to (i) review the statement setting forth Seller’s calculation of the Final Purchase Price and the records relating thereto only with respect to items identified by Purchaser in its written report containing changes to such statement that remain disputed immediately following the Final Settlement Date and (ii) determine the final adjustments.  Each party shall furnish the Agreed Accounting Firm such work papers and other records and information relating to the objections in dispute as the Agreed Accounting Firm may reasonably request and that are available to such party or its Affiliates (and such parties’ independent public accountants).  The parties will, and will cause their representatives to, cooperate and assist in the conduct of any review by the Agreed Accounting Firm, including, but not limited to, making available books, records and, as available, personnel as reasonably required.  The Agreed Accounting Firm shall conduct the arbitration proceedings in Houston, Texas in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section 9.4.  The Agreed Accounting Firm’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding on both parties, without right of appeal and such decision shall constitute an arbitral award upon which a judgment may be entered by a court having jurisdiction thereof.  In determining the proper amount of any adjustment to the Final Purchase Price, the Agreed Accounting Firm shall not increase the Final Purchase Price more than the increase proposed by Seller nor decrease the Final Asset Value more than the decrease proposed by Purchaser, as applicable, and may not award damages or penalties to either party with respect to any matter. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case. Each party shall bear one-half of the costs and expenses

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of the accounting firm. Within ten (10) Business Days after the date on which the parties or the Agreed Accounting Firm, as applicable, finally determines the disputed matters, (x) Purchaser shall pay to Seller the amount by which the Final Purchase Price exceeds the Closing Payment or (y) Seller shall pay to Purchaser the amount by which the Closing Payment exceeds the Final Purchase Price, as applicable. Any post-Closing payment pursuant to this Section 9.4(b) shall bear interest at the Agreed Interest Rate from (but not including) the Closing Date to (and including) the date both Purchaser and Seller have executed the final settlement statement.

(c)           All payments made or to be made hereunder to Seller shall be by electronic transfer of immediately available funds to the account of Anadarko Petroleum Corporation, Account No. 5762707 at JPMorgan Chase, Chicago, IL, ABA No. 021000021, for the credit of Seller or to such other bank and account as may be specified by Seller in writing. All payments made or to be made hereunder to Purchaser shall be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Seller.

ARTICLE 10
TERMINATION

Section 10.1          Termination.

This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Closing:

(a)           by mutual written consent of Seller and Purchaser;

(b)           by either Seller or Purchaser, if:

(i)the Closing shall not have occurred on or before June 1, 2007 (the “Termination Date”); provided, however, that the right to terminate this Agreement under this Section 10.1(b)(i) shall not be available (A) to Seller, if any breach of this Agreement by Seller has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date or (B) to Purchaser, if any breach of this Agreement by Purchaser has been the principal cause of, or resulted in, the failure of the Closing to occur on or before the Termination Date; or

(ii)there shall be any Law that makes consummation of the transactions contemplated hereby illegal or otherwise prohibited or a Governmental Body shall have issued an order, decree, or ruling or taken any other action permanently restraining, enjoining, or otherwise prohibiting the consummation of the transactions contemplated hereby, and such order, decree, ruling, or other action shall have become final and non appealable;

(c)           by Seller, if (i) any of the representations and warranties of Purchaser contained in this Agreement shall not be true and correct in all material respects (provided that any such representation or warranty that is already qualified by a materiality standard or a material adverse effect qualification shall not be further qualified); or (ii) Purchaser shall have failed to fulfill in any material respect any of its obligations under this Agreement; and, in the case of each of clauses (i) and (ii), such misrepresentation, or breach of warranty, if curable, has not been cured within ten (10) days after written notice thereof from Seller to Purchaser; provided

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that any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date; or

(d)           by Purchaser, if (i) any of the representations and warranties of Seller contained in this Agreement shall not be true and correct in all material respects (provided that any such representation or warranty that is already qualified by a materiality or Material Adverse Effect qualification shall not be further qualified); or (ii) Seller shall have failed to fulfill in any material respect any of its obligations under this Agreement, and, in the case of each of clauses (i) and (ii), such misrepresentation, breach of warranty or failure, if curable, has not been cured within ten (10) days after written notice thereof from Purchaser to Seller; provided that any cure period shall not extend beyond the Termination Date and shall not extend the Termination Date.

Section 10.2          Effect of Termination.

If this Agreement is terminated pursuant to Section 10.1, this Agreement shall become void and of no further force or effect (except for the provisions of Section 4.4, Section 5.6, Section 6.5, Section 7.5, Section 7.15, Section 11.10, Section 11.11 and Section 11.12 of this Agreement and this Article 10, the Section entitled “Definitions,” and Article 12 (other than Section 12.6), all of which shall continue in full force and effect).  Notwithstanding the foregoing, nothing contained in this Section 10.2 shall relieve any party from liability for Losses resulting from its breach of this Agreement.

Section 10.3          Distribution of Deposit Upon Termination.

(a)           If Seller terminates this Agreement (i) because Purchaser has failed to comply with any provision of Sections 8.1(a), 8.1(b) or 8.1(d); or (ii) as the result of any default or breach by Purchaser of Purchaser’s obligations hereunder, then Seller may retain the Deposit, as its sole and exclusive remedy as liquidated damages, free of any claims by Purchaser or any other Person with respect thereto.  It is expressly stipulated by the parties that the actual amount of damages resulting from such a termination would be difficult if not impossible to determine accurately because of the unique nature of this Agreement, the unique nature of the Assets, the uncertainties of applicable commodity markets and differences of opinion with respect to such matters, and that the liquidated damages provided for herein are a reasonable estimate by the parties of such damages.

(b)           If this Agreement is terminated for any reason other than the reasons set forth in Section 10.3(a), then Seller shall deliver the Deposit to Purchaser without interest thereon, free of any claims by Seller or any other Person with respect thereto after Purchaser has satisfied its obligations under Section 7.15.

(c)           Notwithstanding anything to the contrary in this Agreement, Purchaser shall not be entitled to receive interest on the Deposit, whether the Deposit is applied against the Purchase Price or returned to Purchaser pursuant to this Section 10.3.

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ARTICLE 11
POST-CLOSING OBLIGATIONS; INDEMNIFICATION;
LIMITATIONS; DISCLAIMERS AND WAIVERS

Section 11.1          Receipts.

Except as otherwise provided in this Agreement, any Hydrocarbons produced from or attributable to the Assets (and all products and proceeds attributable thereto) and any other income, proceeds, receipts and credits attributable to the Assets which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) all Hydrocarbons produced from or attributable to the Assets (and all products and proceeds attributable thereto) and all other income, proceeds, receipts and credits earned with respect to the Assets to which Purchaser is entitled under Section 1.4 shall be the sole property and entitlement of Purchaser, and, to the extent received by Seller, Seller shall fully disclose, account for and remit the same promptly to Purchaser, and (b) all Hydrocarbons produced from or attributable to the Assets (and all products and proceeds attributable thereto) and all other income, proceeds, receipts and credits earned with respect to the Assets to which Seller is entitled under Section 1.4 shall be the sole property and entitlement of Seller and, to the extent received by Purchaser, Purchaser shall fully disclose, account for and remit  the same promptly to Seller.

Section 11.2          Expenses.

Except for Royalty Amounts and except as otherwise provided in this Agreement, any Property Costs which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (a) all Property Costs for which Seller is responsible under Section 1.4 shall be the sole obligation of Seller and Seller shall promptly pay, or if paid by Purchaser, promptly reimburse Purchaser for and hold Purchaser harmless from and against same; and (b) all Property Costs for which Purchaser is responsible under Section 1.4 shall be the sole obligation of Purchaser, and Purchaser shall promptly pay, or if paid by Seller, promptly reimburse Seller for and hold Seller harmless from and against same. Seller is entitled to resolve all joint interest audits and other audits of Property Costs covering periods for which Seller is wholly responsible and Purchaser is entitled to resolve all joint interest audits and other audits of Property Costs covering periods for which Purchaser is in whole or in part responsible; provided that Purchaser shall not agree to any adjustments to previously assessed costs for which Seller is liable without the prior written consent of Seller, such consent not to be unreasonably withheld. Purchaser shall provide Seller with a copy of all applicable audit reports and written audit agreements received by Purchaser and relating to periods for which Seller is partially responsible.

Section 11.3          Assumed Seller Obligations.

Subject to the indemnification by Seller under  Section 11.5, on the Closing Date, Purchaser shall assume and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of Seller, known or unknown, with respect to the Assets, regardless of whether such obligations or liabilities arose prior to, on or after the Effective Time, including but not limited to obligations to (a) furnish makeup gas according to the terms of applicable gas sales, gathering or transportation contracts, and to satisfy all other gas balancing obligations, if any, (b) pay working interests, royalties, overriding royalties and other interests held in suspense, (c) properly plug and abandon any and all wells, including inactive wells or temporarily abandoned wells, drilled on the Properties, as required by Law, (d) replug any well, wellbore, or previously plugged well on the Properties to the extent required by Governmental Body, (e) dismantle, salvage and remove any equipment, structures, materials, platforms, flowlines, and property of whatever kind related to or associated with operations and activities conducted on the Properties, (f) clean up, restore and/or remediate the premises covered by or related to the Assets in accordance with applicable agreements and Laws, (g) perform all obligations applicable to or imposed on the

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lessee, owner, or operator under the Leases or with respect to the Mineral Interests and related contracts, or as required by applicable Laws, and (h) pay working interests, royalties, overriding royalties and other interests payable to third parties on account of production from the Assets other than any royalties owed on account of production from the Properties before the Closing Date as a result of or attributable to the resolution of the Royalty Actions (collectively, “Royalty Amounts”) (all of said obligations and liabilities, subject to the exclusions below, herein being referred to as the “Assumed Seller Obligations”); provided, however, that the Assumed Seller Obligations shall not include, and Purchaser shall have no obligation to assume, any obligations or liabilities of Seller to the extent that they are (such excluded obligations and liabilities, the “Excluded Seller Obligations”):

(i)attributable to or arise out of the Excluded Assets;

(ii)except for Royalty Amounts and except to the extent covered by Section 11.3(v)(D) below, the continuing responsibility of Seller under Section 11.1 or Section 11.2;

(iii)attributable to or arising out of matters for which Seller is required to indemnify Purchaser under Section 11.5(c);

(iv)except for Royalty Amounts, Property Costs for which Seller is responsible pursuant to Section 1.4(b);

(v)(A) attributable to or arising out of Proceedings set forth under Category 1 on Schedule 5.7(a), (B) Losses owed as a result of the resolution of the Proceeding listed in item 6 under Category 3 on Schedule 5.7(a) to the extent such Losses result from or are attributable to production from the Properties occurring before the Closing Date, (C) Losses owed as a result of the resolution of the Proceeding listed in item 7 under Category 3 on Schedule 5.7(a) to the extent such Losses result from or are attributable to actions occurring before the Closing Date, (D) royalties owed on account of production from the Properties before the Closing Date as a result of or attributable to the resolution of the Royalty Actions and all other Losses owed as a result of the resolution of the Royalty Actions to the extent such Losses result from or are attributable to production from such Properties before the Closing Date, (E) Proceedings arising out of or attributable to Seller’s ownership or operation of the Assets arising after the date hereof but before Closing, or (F) Proceedings that arise after Closing for personal injury or death arising and occurring before Closing which is attributable to Seller’s (or its Affiliates’) ownership or operation of the Assets;

(vi)attributable to or arise out of any noncompliance of Law set forth on Schedule 5.7(b);

(vii)Retained Employee Liabilities; or

(viii)attributable to or arise out of any off-site Environmental Liabilities occurring prior to the Closing Date that relate to the Assets.

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Section 11.4          Survival.

(a)           All representations and warranties of Seller and Purchaser contained herein shall survive the Closing Date and shall terminate on the first anniversary of the Closing Date; provided, however, that the representations and warranties contained in Section 5.3, Section 5.4, Section 5.6, Section 5.8, Section 6.2, Section 6.3, and Section 6.5 (collectively, the “Fundamental Representations”) shall survive until the expiration of the applicable statute of limitations period.  Upon the termination of a representation or warranty in accordance with the foregoing, such representation or warranty shall have no further force or effect for any purpose under this Agreement.  The covenants and other agreements of Seller and Purchaser set forth in this Agreement shall survive the Closing Date until fully performed.

(b)           No party hereto shall have any indemnification obligation pursuant to this Article 11 or otherwise in respect of any representation, warranty, covenant or agreement unless it shall have received from the party seeking indemnification a written notice (a “Claim Notice”) of the existence of the claim for or in respect of which indemnification in respect of such representation, warranty, covenant or agreement is being sought on or before the expiration of the applicable survival period set forth in Section 11.4(a).  If an Indemnified Party delivers a Claim Notice to an Indemnifying Party before the expiration of the applicable survival period set forth in Section 11.4(a), then the applicable representation, warranty, covenant or agreement shall survive until, but only for purposes of, the resolution of the matter covered by such Claim Notice.  A Claim Notice shall set forth with reasonable specificity (1) the basis for such claim under this Agreement, and the facts that otherwise form the basis of such claim and (2) to the extent reasonably estimable, an estimate of the amount of such claim (which estimate shall not be conclusive of the final amount of such claim) and an explanation of the calculation of such estimate.

Section 11.5          Indemnification by Seller.

From and after the Closing, subject to the terms and conditions of this Article 11, Seller shall jointly and severally indemnify, defend and hold harmless Purchaser and its directors, officers, employees, stockholders, members, agents, consultants, advisors and other representatives (including legal counsel, accountants and financial advisors) and Affiliates and the successors and permitted assigns of this Agreement of Purchaser (collectively, the “Purchaser Indemnified Persons”) from and against any and all Losses asserted against, resulting from, imposed upon, or incurred or suffered by any Purchaser Indemnified Person to the extent resulting from, arising out of or relating to:

(a)           any breach of any representation or warranty of Seller contained in this Agreement or confirmed in any certificate furnished by or on behalf of Seller in connection with this Agreement;

(b)           any breach or nonfulfillment of or failure to perform any covenant or agreement of Seller contained in this Agreement or confirmed in any certificate furnished by or on behalf of Seller in connection with this Agreement; and

(c)           any Excluded Seller Obligations.

Section 11.6          Indemnification by Purchaser.

From and after the Closing, subject to the terms and conditions of this Article 11, Purchaser shall indemnify, defend and hold harmless Seller and its directors, officers, employees, agents, consultants, stockholders, advisors and other representatives (including

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legal counsel, accountants and financial advisors), and Seller’s successors, permitted assigns of this Agreement and Affiliates (collectively, the “Seller Indemnified Persons”) from and against any and all Losses, asserted against, resulting from, imposed upon, or incurred or suffered by any Seller Indemnified Person, directly or indirectly, to the extent resulting from, arising out of, or relating to:

(a)           any breach of any representation or warranty of Purchaser contained in this Agreement or confirmed in any certificate furnished by or on behalf of Purchaser to Seller in connection with this Agreement REGARDLESS OF FAULT;

(b)           any breach or nonfulfillment of or failure to perform any covenant or agreement of Purchaser contained in this Agreement REGARDLESS OF FAULT or confirmed in any certificate furnished by or on behalf of Purchaser to Seller in connection with this Agreement;

(c)           the ownership, use or operation of the Assets after the Effective Time;

(d)           the Assumed Seller Obligations REGARDLESS OF FAULT; and

(e)           Environmental Laws, Environmental Liabilities, the release of materials into the environment or protection of human health, safety, natural resources or the environment, or any other environmental condition of the Assets, REGARDLESS OF FAULT.

Section 11.7          Indemnification Proceedings.

(a)           In the event that any claim or demand for which Seller or Purchaser (such Person, an “Indemnifying Party”) may be liable to an Purchaser Indemnified Person under Section 11.5 or to an Seller Indemnified Person under Section 11.6 (an “Indemnified Party”) is asserted against or sought to be collected from an Indemnified Party by a third party (a “Third Party Claim,”) the Indemnified Party shall with reasonable promptness notify the Indemnifying Party of such Third Party Claim by delivery of a Claim Notice, provided that the failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11, except (and solely) to the extent that the Indemnifying Party demonstrates that its defense of such Third Party Claim is actually and materially prejudiced thereby.  The Indemnifying Party shall have thirty (30) days from receipt of the Claim Notice from the Indemnified Party (in this Section 11.7, the “Notice Period”) to notify the Indemnified Party whether or not the Indemnifying Party desires, at the Indemnifying Party’s sole cost and expense, to defend the Indemnified Party against such claim or demand; provided, that the Indemnified Party is hereby authorized prior to and during the Notice Period, and at the cost and expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall reasonably deem necessary to protect its interests or those of the Indemnifying Party.  The Indemnifying Party shall have the right to assume the defense of such Third Party Claim only if and for so long as the Indemnifying Party (i) notifies the Indemnified Party during the Notice Period that the Indemnifying Party is assuming the defense of such Third Party Claim, (ii) uses counsel of its own choosing that is reasonably satisfactory to the Indemnified Party, and (iii) conducts the defense of such Third Party Claim in an active and diligent manner.  If the Indemnifying Party is entitled to, and does, assume the defense of any such Third Party Claim, the Indemnified Party shall have the right to employ separate counsel at its own expense and to participate in the defense thereof; provided, however, that notwithstanding the foregoing, the Indemnifying Party shall pay the reasonable attorneys’ fees of the Indemnified Party if the Indemnified Party’s counsel shall have advised the Indemnified Party that there is a conflict of interest that could make it inappropriate under applicable standards of professional conduct to

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have common counsel for the Indemnifying Party and the Indemnified Party (provided that the Indemnifying Party shall not be responsible for paying for more than one separate firm of attorneys and one local counsel to represent all of the Indemnified Parties subject to such Third Party Claim).  If the Indemnifying Party elects (and is entitled) to assume the defense of such Third Party Claim, (i) no compromise or settlement thereof or consent to any admission or the entry of any judgment with respect to such Third Party Claim may be effected by the Indemnifying Party without the Indemnified Party’s written consent (which shall not be unreasonably withheld, conditioned or delayed) unless the sole relief provided is monetary damages that are paid in full by the Indemnifying Party (and no injunctive or other equitable relief is imposed upon the Indemnified Party) and there is an unconditional provision whereby each plaintiff or claimant in such Third Party Claim releases the Indemnified Party from all liability with respect thereto and (ii) the Indemnified Party shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which shall not be unreasonably withheld).  If the Indemnifying Party elects not to assume the defense of such Third Party Claim (or fails to give notice to the Indemnified Party during the Notice Period or otherwise is not entitled to assume such defense), the Indemnified Party shall be entitled to assume the defense of such Third Party Claim with counsel of its own choice, at the expense and for the account of the Indemnifying Party; provided, however, that the Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of any Indemnifying Party without the prior written consent of such Indemnifying Party, which consent shall not be unreasonably withheld, conditioned or delayed.

(b)           Notwithstanding the foregoing, the Indemnifying Party shall not be entitled to control (but shall be entitled to participate at its own expense in the defense of), and the Indemnified Party, shall be entitled to have sole control over, the defense or settlement, compromise, admission, or acknowledgment of any Third Party Claim (i) at the reasonable expense of the Indemnifying Party, as to which the Indemnifying Party fails to assume the defense during the Notice Period after the Indemnified Party gives notice thereof to the Indemnifying Party or (ii) at the reasonable expense of the Indemnifying Party, to the extent the Third Party Claim seeks an order, injunction, or other equitable relief against the Indemnified Party which, if successful, could materially adversely affect the business, condition (financial or other), capitalization, assets, liabilities, results of operations or prospects of the Indemnified Party.  The Indemnified Party shall make no settlement, compromise, admission, or acknowledgment that would give rise to liability on the part of the Indemnifying Party without the prior written consent of the Indemnifying Party (which consent shall not be unreasonably withheld, conditioned or delayed).

(c)           In any case in which an Indemnified Party seeks indemnification hereunder and no Third Party Claim is involved, the Indemnified Party shall deliver a Claim Notice to the Indemnifying Party within a reasonably prompt period of time after an officer of such Indemnified Party or its Affiliates has obtained knowledge of the Loss giving rise to indemnification hereunder.  The failure or delay to so notify the Indemnifying Party shall not relieve the Indemnifying Party of its obligations under this Article 11 except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively mitigate the resulting Losses or otherwise prejudices the Indemnifying Party.

Section 11.8          Limitations on Indemnities.

(a)           Notwithstanding the foregoing, (i) Seller shall not be obligated to indemnify any Purchaser Indemnified Persons for Losses pursuant to Section 11.5(a), and Purchaser shall not be obligated to indemnify the Seller Indemnified Persons for Losses pursuant to Section

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11.6(a), in each case, pursuant to this Article 11 unless and until the amount of all Losses incurred by any Purchaser Indemnified Persons, or by any Seller Indemnified Persons, as the case may be, exceeds, in the aggregate, $21,500,000 (the “Deductible”), in which event the party or parties seeking indemnity may recover all Losses incurred in excess of the Deductible, and (i) Seller’s maximum liability for Losses pursuant to Section 11.5(a), and Purchaser’s maximum liability for Losses pursuant to Section 11.6(a), in each case, shall be $215,000,000 (the “Maximum Indemnity Amount”); provided, however, that, notwithstanding the foregoing, the Deductible and the Maximum Indemnity Amount shall not apply to (and the Indemnified Parties shall be entitled to be indemnified for all Losses relating to) any claims based on the occurrence of common law actual fraud and (B) any claims asserted under Section 11.5(a), or Section 11.6(a) insofar as such claims relate to any breach of Fundamental Representations or any certificate to the extent based on any such Fundamental Representation.

(b)           Solely for purposes of calculating the amount of Losses incurred arising out of or relating to any breach or inaccuracy of a representation or warranty (and not for determining whether a breach has occurred), the references to “Material Adverse Effect” or other materiality qualifications (or correlative terms) shall be disregarded.

(c)           The liability of any party under Article 11 shall be in addition to, and not exclusive of, any other liability that such party may have at Law or equity based on such party’s common law actual fraud.  None of the provisions set forth in this Agreement, including, but not limited to, the provisions set forth in Section 3.4(j) (relating to the Individual Defect Deductible), Section 11.4(b) (relating to limitations on the period during which a claim for indemnification may be brought) or Section 11.8(a) (relating to the Deductible), shall be deemed a waiver by any party to this Agreement of any right or remedy which such party may have at Law or equity based on any other party’s common law actual fraud, nor shall any such provisions limit, or be deemed to limit, (i) the amounts of recovery sought or awarded in any such claim for common law actual fraud, (ii) the time period during which a claim for common law actual fraud may be brought or (iii) the recourse which any such party may seek against another party with respect to a claim for common law actual fraud; provided, that with respect to such rights and remedies at law or equity, the parties further acknowledge and agree that none of the provisions of this Section 11.8(c), nor any reference to this Section 11.8(c) throughout this Agreement, shall be deemed a waiver of any defenses which may be available in respect of actions or claims for common law actual fraud, including but not limited to, defenses of statutes of limitations or limitations of damages.

Section 11.9          Release.

EXCEPT WITH RESPECT TO SECTION 5.7 AND POST-CLOSING REMEDIATION AGREED TO PURSUANT TO SECTION 4.3, PURCHASER HEREBY RELEASES, REMISES AND FOREVER DISCHARGES THE SELLER INDEMNIFIED PERSONS FROM ANY AND ALL CLAIMS, KNOWN OR UNKNOWN, WHETHER NOW EXISTING OR ARISING IN THE FUTURE, CONTINGENT OR OTHERWISE, WHICH PURCHASER MIGHT NOW OR SUBSEQUENTLY MAY HAVE AGAINST THE SELLER INDEMNIFIED PERSONS, RELATING DIRECTLY OR INDIRECTLY TO THE CLAIMS ARISING OUT OF OR INCIDENT TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, INCLUDING, WITHOUT LIMITATION, RIGHTS TO CONTRIBUTION UNDER CERCLA, REGARDLESS OF FAULT.

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Section 11.10       Disclaimers.

(a)           EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, OR CONFIRMED IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(c), IN THE CONVEYANCE, (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING, WITHOUT LIMITATION, ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF ITS AFFILIATES).

(b)           EXCEPT AS EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 5 OF THIS AGREEMENT, OR CONFIRMED IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION 9.2(c), IN THE CONVEYANCE, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I) TITLE TO ANY OF THE ASSETS, (II) THE CONTENTS, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (III) THE QUANTITY, QUALITY OR  RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE ASSETS, (IV) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY THIRD PARTIES, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM REDHIBITORY VICES OR DEFECTS (INCLUDING THOSE CONTEMPLATED IN LOUISIANA CIVIL CODE ARTICLES 2475, AND 2520 THROUGH 2548), FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT PURCHASER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS AND THAT PURCHASER HAS MADE OR CAUSED TO BE  MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE, OR (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT.

(c)           EXCEPT AS REPRESENTED IN SECTION 5.7, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, ENVIRONMENTAL LIABILITIES, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND

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NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND PURCHASER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

Section 11.11       Waiver of Trade Practices Acts.

(a)           It is the intention of the parties that Purchaser’s rights and remedies with respect to this transaction and with respect to all acts or practices of Seller, past, present or future, in connection with this transaction shall be governed by legal principles other than the Texas Deceptive Trade Practices—Consumer Protection Act, Tex. Bus. & Com. Code Ann. § 17.41 et seq. (the “DTPA”) or the Louisiana unfair trade practices and consumer protection law, La. R.S. 51:1402, et seq. (the “UTPCPL”).  As such, Purchaser hereby waives the applicability of the DTPA and the UTPCPL to this transaction and any and all duties, rights or remedies that might be imposed by the DTPA and/or the UTPCPL, whether such duties, rights and remedies are applied directly by the DTPA or the UTPCPL itself or indirectly in connection with other statutes; provided, however, Purchaser does not waive § 17.555 of the DTPA.  Purchaser acknowledges, represents and warrants that it is purchasing the goods and/or services covered by this Agreement for commercial or business use; that it has assets of $5,000,000.00 or more according to its most recent financial statement prepared in accordance with GAAP; that it has knowledge and experience in financial and business matters that enable it to evaluate the merits and risks of a transaction such as this; and that it is not in a significantly disparate bargaining position with Seller.

(b)           Purchaser expressly recognizes that the price for which Seller has agreed to perform its obligations under this Agreement has been predicated upon the inapplicability of the DTPA and the UTPCPL and this waiver of the DTPA and the UTPCPL.  Purchaser further recognizes that Seller, in determining to proceed with the entering into of this Agreement, has expressly relied on this waiver and the inapplicability of the DTPA and the UTPCPL.

Section 11.12       Redhibition Waiver.

Purchaser waives all rights in redhibition pursuant to Louisiana Civil Code Articles 2475 and 2520 through 2548, and acknowledges that this express waiver shall be considered a material and integral part of this transaction and the consideration thereof.  Purchaser acknowledges that this waiver has been brought to its attention and has been explained in detail and that Purchaser has voluntarily and knowingly consented to this waiver of warranty of fitness and warranty against redhibitory vices and defects for the Assets.

Section 11.13       Recording.

As soon as practicable after Closing, Purchaser shall record the Conveyance in the appropriate counties and/or parishes and provide Seller with copies of all recorded or approved instruments.  The Conveyance is intended to convey all of the Properties being conveyed pursuant to this Agreement.  Certain Properties or specific portions of the Properties that are leased from, or require the approval to transfer by, a Governmental Body are conveyed under the Conveyance and also are described and covered by other separate assignments made by Seller to Purchaser on officially approved forms, or forms acceptable to such entity, in sufficient multiple originals to satisfy applicable statutory and regulatory requirements.  The interests conveyed by such separate assignments are the same, and not in addition to, the interests conveyed in the Conveyance attached as Exhibit B.  Further, such assignments shall be deemed to contain the special warranty of title of Seller and all of the exceptions, reservations,

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rights, titles, power and privileges set forth herein and in the Conveyance as fully and only to the extent as though they were set forth in each such separate assignment.

ARTICLE 12
MISCELLANEOUS

Section 12.1          Counterparts.

This Agreement may be executed and delivered (including by facsimile transmission) in counterparts, each of which shall be deemed an original instrument, but all such counterparts together shall constitute but one agreement.

Section 12.2          Notice.

All notices which are required or may be given pursuant to this Agreement shall be sufficient in all respects if given in writing and delivered personally, by telecopy or by registered or certified mail, postage prepaid, as follows:

If to Seller:	Anadarko Petroleum Corporation
	Anadarko E&P Company LP
	Howell Petroleum Corporation
	Kerr-McGee Oil & Gas Onshore LP
	1201 Lake Robbins Drive
	The Woodlands, TX 77380
	Attention:		Transaction Manager, Business Development
	Telephone:		(832)636-3088
	Telecopy:		(832)636-5889
With a copy to (which:	Anadarko Petroleum Corporation
shall not constitute	1201 Lake Robbins Drive
notice to Seller):	The Woodlands, TX 77380
	Attention:		Associate General Counsel
			Oil, Gas and Minerals
	Telephone:		(832)636-7530
	Telecopy:		(832)636-5889
If to Purchaser:	EXCO Resources, Inc.
	12377 Merit Drive, Suite 1700
	Dallas, Texas 75251
	Attention:	William L. Boeing
	Telephone:	(214) 368-2084
	Telecopy:	(214) 706-3409
With a copy to (which
shall not constitute
notice to Purchaser):	Vinson & Elkins L.L.P.
	2001 Ross Avenue, Suite 3700
	Dallas, Texas 75201
	Attention:	Jeffrey A. Chapman

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Telephone:	(214) 220-7797
Telecopy:	(214) 999-7797
Attention:	P. Gregory Hidalgo
Telephone:	(214) 220-7959
Telecopy:	(214) 999-7959

Either party may change its address for notice by notice to the other in the manner set forth above.  All notices shall be deemed to have been duly given at the time of receipt by the party to which such notice is addressed.

Section 12.3          Sales or Use Tax Recording Fees and Similar Taxes and Fees.

Purchaser shall bear any sales, use, excise, real property transfer, gross receipts, goods and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees (collectively “Transfer Taxes”) incurred and imposed upon, or with respect to, the transactions contemplated by this Agreement.  Seller will determine, and Purchaser will cooperate with Seller in determining the amount of any Transfer Taxes, if any, that is due in connection with the transactions contemplated by this Agreement and Purchaser agrees to pay any such Transfer Tax to Seller or to the appropriate Governmental Body.  If any of the transactions contemplated by this Agreement are exempt from any such Transfer Taxes upon the filing of an appropriate certificate or other evidence of exemption, Purchaser will timely furnish to Seller such certificate or evidence.

Section 12.4          Expenses.

Except as otherwise expressly provided in Section 12.3 or elsewhere in this Agreement, (a) all expenses incurred by Seller in connection with or related to the authorization, preparation or execution of this Agreement, the Conveyance delivered hereunder and the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, including without limitation, all fees and expenses of counsel, accountants and financial advisers employed by Seller, shall be borne solely and entirely by Seller, and (b) all such expenses incurred by Purchaser shall be borne solely and entirely by Purchaser.

Section 12.5          Change of Name.

As promptly as practicable, but in any case within ninety (90) days after the Closing Date, Purchaser shall eliminate the names “Anadarko Petroleum Corporation”, “Anadarko” and any variants thereof and any names of Seller’s Affiliates and any variants thereof from the Assets acquired pursuant to this Agreement and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

Section 12.6          Replacement of Bonds, Letters of Credit and Guarantees.

The parties understand that none of the bonds, letters of credit and guarantees, if any, posted by Seller or any of its Affiliates with Governmental Bodies and relating to the Assets may

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be transferable to Purchaser.  Promptly following Closing, Purchaser shall obtain, or cause to be obtained in the name of Purchaser, replacements for such bonds, letters of credit and guarantees, to the extent such replacements are necessary to permit the cancellation of the bonds, letters of credit and guarantees posted by Seller or any of its Affiliates or to consummate the transactions contemplated by this Agreement.

Section 12.7          Governing Law and Venue.

THIS AGREEMENT AND THE LEGAL RELATIONS BETWEEN THE PARTIES SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS OTHERWISE APPLICABLE TO SUCH DETERMINATIONS.  JURISDICTION AND VENUE WITH RESPECT TO ANY DISPUTES ARISING HEREUNDER SHALL BE PROPER ONLY IN HARRIS COUNTY, TEXAS.

Section 12.8          Captions.

The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

Section 12.9          Waivers.

Any failure by any party or parties to comply with any of its or their obligations, agreements or conditions herein contained may be waived in writing, but not in any other manner, by the party or parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided.

Section 12.10       Assignment.

No party shall assign all or any part of this Agreement, nor shall any party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other party.  Purchaser shall have the right to designate an Affiliate to take title to the Assets located in Oklahoma and Kansas by providing written notice thereof to Seller no later than ten (10) Business Days prior to the Closing Date; provided, however, that no such designation shall relieve Purchaser from any of its obligations hereunder.  This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns.

Section 12.11       Entire Agreement.

The Confidentiality Agreement, this Agreement and the Exhibits and Schedules attached hereto, and the documents to be executed hereunder constitute the entire agreement between the parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties pertaining to the subject matter hereof.

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Section 12.12       Amendment.

(a)           This Agreement may be amended or modified only by an agreement in writing executed by the  parties hereto.

(b)           No waiver of any right under this Agreement shall be binding unless executed in writing by the party to be bound thereby.

Section 12.13       No Third-Party Beneficiaries.

Nothing in this Agreement shall entitle any Person other than Purchaser or Seller to any claims, remedy or right of any kind, except as to those rights expressly provided to the Seller Indemnified Persons and Purchaser Indemnified Persons (provided, however, any claim for indemnity hereunder on behalf of an Seller Indemnified Person or an Purchaser Indemnified Person must be made and administered by a party to this Agreement).

Section 12.14       References.

In this Agreement:

(a)           References to any gender includes a reference to all other genders;

(b)           References to the singular includes the plural, and vice versa;

(c)           Reference to any Article or Section means an Article or Section of this Agreement;

(d)           Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, all of which are incorporated into and made a part of this Agreement;

(e)           Unless expressly provided to the contrary, “hereunder”, “hereof’, “herein” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement;

(f)            “Include” and “including” shall mean include or including without limiting the generality of the description preceding such term; and

(g)           Capitalized terms used herein shall have the meanings ascribed to them in this Agreement as such terms are identified and/or defined in the Definitions section hereof.

Section 12.15       Construction.

Purchaser is a party capable of making such investigation, inspection, review and evaluation of the Assets as a prudent party would deem appropriate under the circumstances including with respect to all matters relating to the Assets, their value, operation and suitability. Each of Seller and Purchaser has had substantial input into the drafting and preparation of this Agreement and has had the opportunity to exercise business discretion in relation to the negotiation of the details of the transactions contemplated hereby. This Agreement is the result of arm’s-length negotiations from equal bargaining positions.  In the event of a dispute over the meaning or application of this Agreement, it shall be construed fairly and reasonably and neither more strongly for nor against either party.

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Section 12.16       Conspicuousness.

The parties agree that provisions in this Agreement in “bold” type satisfy any requirements of the “express negligence rule” and any other requirements at law or in equity that provisions be conspicuously marked or highlighted.

Section 12.17       Severability.

If any term or other provisions of this Agreement is held invalid, illegal or incapable of being enforced under any rule of law, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in a materially adverse manner with respect to either party; provided, however, that if any such term or provision may be made enforceable by limitation thereof, then such term or provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable Law.

Section 12.18       Time of Essence.

Time is of the essence in this Agreement.  If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

Section 12.19       Affiliate Liability.

Each of the following is herein referred to, for purposes of this Section 12.19, as an “Purchaser Affiliate”: (i) any direct or indirect holder of equity interests in Purchaser (whether shareholders or otherwise), and (ii) any director, officer, manager, employee, representative or agent of (a) Purchaser or (b) any Affiliate of Purchaser.  Except to the extent that a Purchaser Affiliate is an express signatory and party hereto, no Purchaser Affiliate shall have any liability or obligation of any nature whatsoever in connection with or under this Agreement, or the transactions contemplated hereby, and Seller hereby waives and releases all claims of any such liability and obligation.

Section 12.20       Schedules.

The disclosures in any Schedule must relate only to the representations and warranties in the Section of this Agreement to which it expressly relates and not to any other representation or warranty in this Agreement, unless some other representation and warranty is specifically and clearly referred to in such Schedule.

Section 12.21       Limitation on Damages.

Notwithstanding any other provision contained elsewhere in this Agreement to the contrary, the parties acknowledge that this Agreement does not authorize one party to sue for or collect from the other party its own punitive damages, or its own consequential or indirect damages in connection with this Agreement and the transactions contemplated hereby and each party expressly waives for itself and on behalf of its Affiliates, any and all Claims it may

54

have against the other party for its own such damages in connection with this Agreement and the transactions contemplated hereby.

[SIGNATURES BEGIN ON THE FOLLOWING PAGE]

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IN WITNESS WHEREOF, this Agreement has been signed by each of the parties hereto on the date first above written.

SELLER:
ANADARKO PETROLEUM CORPORATION
By:	/s/ ALBERT L. RICHEY
Albert L. Richey
Vice President, Corporate Development
ANADARKO E&P COMPANY LP
By:	/s/ ALBERT L. RICHEY
Albert L. Richey
Vice President, Corporate Development
HOWELL PETROLEUM CORPORATION
By:	/s/ ALBERT L. RICHEY
Albert L. Richey
Vice President, Corporate Development
KERR-MCGEE OIL & GAS ONSHORE LP
By:	/s/ ALBERT L. RICHEY
Albert L. Richey
Vice President
PURCHASER
EXCO RESOURCES, INC.
By:	/s/ JOHN D. JACOBI
Name: John D. Jacobi
Title: Vice President , Business Development

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EX-21.1

EXHIBIT 21.1

LIST OF SUBSIDIARIES OF
EXCO RESOURCES, INC.

Name of Subsidiary	State of Incorporation
ROJO Pipeline, LP	Delaware
EXCO Investment I, LLC	Delaware
EXCO Investment II, LLC	Delaware
EXCO Operating, LP	Delaware
North Coast Energy, Inc.	Delaware
North Coast Energy Eastern, Inc.	Delaware
Pinestone Resources, LLC	Delaware
TXOK Acquisition, LLC	Delaware
TXOK Energy Resources Company	Delaware
TXOK Energy Resources Holdings, L.L.C.	Delaware
TXOK Texas Energy Holdings, LLC	Delaware
TXOK Texas Energy Resources, L.P.	Delaware
EXCO Partners GP, LLC	Delaware
EXCO GP Partners, LP	Delaware
EXCO Partners GP LP, LLC	Delaware
EXCO Partners MLP LP, LLC	Delaware
Power Gas Marketing & Transmission, Inc.	Delaware
EXCO Partners, LP	Delaware
EXCO Partners OLP GP, LLC	Delaware
EXCO Partners Operating Partnership, LP	Delaware
Winchester Energy Company, LP	Delaware
Vaughan Holding Company, L.L.C.	Texas
Winchester Production Company, Ltd.	Texas
TGG Pipeline, Ltd.	Texas
Talco Midstream Assets, Ltd.	Texas
Garrison Gathering, LLC	Texas
Vaughan DE, LLC	Delaware
Vernon Holdings, LLC	Delaware
Southern G Holdings, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
EXCO Resources, Inc.:

We consent to the incorporation by reference in the registration statement on Form S-8 (No. 333-132551 and No. 333-133481) of EXCO Resources, Inc. and subsidiaries of our report dated March 16, 2007, with respect to the consolidated balance sheet of EXCO Resources, Inc. and subsidiaries as of December 31, 2006, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for the year ended December 31, 2006 which report appears in the December 31, 2006 annual report on Form 10-K of EXCO Resources, Inc.

KPMG LLP

Dallas, Texas
March 16, 2007

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File Nos. 333-132551 and 333-133481) of EXCO Resources, Inc. of our report dated March 31, 2006, except for Note 21, as to which the date is March 15, 2007, and our reports dated May 15, 2006, except for Note 21, as to which the date is March 15, 2007, relating to the financial statements, which appear in this Form 10-K.

 /s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 16, 2007

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

        As independent petroleum engineers, Lee Keeling and Associates, Inc. hereby consents to all references to our firm included in or made a part of the EXCO Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2006 and further consents to the incorporation by reference in the Registration Statements on Form S-8 (File No. 333-132551 and File No. 333-133481) of EXCO Resources, Inc. of information from our reserve report dated March 7, 2007 on the estimated proved oil and natural gas reserve quantities of EXCO Resources, Inc. and its consolidated subsidiaries presented as of December 31, 2006.

/s/ LEE KEELING AND ASSOCIATES, INC.

LEE KEELING AND ASSOCIATES, INC.

Tulsa, Oklahoma
March 16, 2007

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Douglas H. Miller, Chief Executive Officer of EXCO Resources, Inc., certify that:

1.I have reviewed this annual report on Form 10-K of EXCO Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 19, 2007	/s/ DOUGLAS H. MILLER
	Douglas H. Miller
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, J. Douglas Ramsey, Chief Financial Officer of EXCO Resources, Inc., certify that:

1.I have reviewed this annual report on Form 10-K of EXCO Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 19, 2007	/s/ J. DOUGLAS RAMSEY
	J. Douglas Ramsey
	Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, Mark E. Wilson, Chief Accounting Officer of EXCO Resources, Inc., certify that:

1.I have reviewed this annual report on Form 10-K of EXCO Resources, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 19, 2007	/s/ MARK E. WILSON
	Mark E. Wilson
	Chief Accounting Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), each of the undersigned officers of EXCO Resources, Inc. (the “Company”), does hereby certify, to such officer’s knowledge, that:

The Annual Report on Form 10-K for the year ended December 31, 2006 (the “Form 10-K”) of the Company fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and the information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for, the periods presented in the Form 10-K.

Date: March 19, 2007	/s/ DOUGLAS H. MILLER
	Douglas H. Miller
	Chief Executive Officer
	/s/ J. DOUGLAS RAMSEY
	J. Douglas Ramsey
	Chief Financial Officer
	/s/ MARK E. WILSON
	Mark E. Wilson
	Chief Accounting Officer

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.