Exco Resources 10Q 2006 Q3 Quarterly report

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EXCO RESOURCES, INC. INDEX

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

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2006
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission File Number 0-9204

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

Texas (State of incorporation)		74-1492779 (I.R.S. Employer Identification No.)
12377 Merit Drive Suite 1700, LB 82 Dallas, Texas (Address of principal executive offices)		75251 (Zip Code)
(214) 368-2084 (Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

YES ý NO o

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES o NO ý

The number of shares of common stock, par value $.001 per share, outstanding at October 26, 2006 was 104,098,313.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	1
	Condensed consolidated balance sheets at December 31, 2005 and September 30, 2006	1-2
	Condensed consolidated statements of operations for the three and nine months ended September 30, 2005 and 2006	3
	Condensed consolidated statements of cash flows for the nine months ended September 30, 2005 and 2006	4
	Condensed consolidated statements of changes in shareholders' equity for the nine months ended September 30, 2005 and 2006	5
	Notes to condensed consolidated financial statements	6-30
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	39
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	62
Item 4.	Controls and Procedures	64
Part II.	OTHER INFORMATION
Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	66
Item 6.	Exhibits	69
	Signatures	74
	Index to exhibits	75

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)

				December 31, 2005			September 30, 2006
							(Unaudited)
Assets
Current assets:
	Cash and cash equivalents			$	226,953		$	22,691
	Accounts receivable:
		Oil and natural gas sales			36,895			52,619
		Joint interest			1,081			8,962
		Canadian income tax receivable			18,483			—
		Interest and other			12,189			6,946
		Oil and natural gas derivatives			—			51,979
		Related party			2,621			—
	Deferred income taxes				29,968			—
	Deferred costs of initial public offering				3,380			—
	Other				10,955			7,152

			Total current assets		342,525			150,349

Oil and natural gas properties (full cost accounting method):
	Unproved oil and natural gas properties				53,121			137,606
	Proved developed and undeveloped oil and natural gas properties				873,595			1,804,259
	Accumulated depreciation, depletion and amortization				(13,281	)		(91,093	)

	Oil and natural gas properties, net				913,435			1,850,772

Gas gathering, office and field equipment, net					33,271			59,953
Investment in TXOK Acquisition, Inc.					20,837			—
Oil and natural gas derivatives					—			30,009
Other assets					419			1,910
Goodwill					220,006			306,142

			Total assets	$	1,530,493		$	2,399,135

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)

				December 31, 2005		September 30, 2006
						(Unaudited)
Liabilities and Shareholders' Equity
Current liabilities:
	Interim bank loan			$	350,000	$	—
	Accounts payable and accrued liabilities				25,182		46,454
	Accrued interest payable				23,779		8,135
	Revenues and royalties payable				11,266		31,063
	Income taxes payable				901		990
	Deferred income taxes				—		11,768
	Current portion of asset retirement obligations				1,408		1,428
	Oil and natural gas derivatives				53,189		9,182

			Total current liabilities		465,725		109,020

Long-term debt					1		404,000
7¹/4% senior notes due 2011					461,801		459,592
Asset retirement obligations and other long-term liabilities					15,766		27,139
Deferred income taxes					134,912		185,916
Oil and natural gas derivatives					81,406		38,186
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 and 104,067 at December 31, 2005 and September 30, 2006, respectively			50		104
	Additional paid-in capital				354,482		1,018,908
	Retained earnings				16,350		156,270

			Total shareholders' equity		370,882		1,175,282

			Total liabilities and shareholders' equity	$	1,530,493	$	2,399,135

See accompanying notes.

EXCO RESOURCES, INC.

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

			Three months ended September 30,					Nine months ended September 30,
			2005			2006		2005			2006
			Predecessor			Successor		Predecessor			Successor
Revenues and other income:
	Oil and natural gas		$	51,771		$	84,890	$	131,469		$	234,634
	Derivative financial instruments			(107,505	)		99,761		(177,253	)		175,768
	Other income			3,407			678		7,047			3,572

		Total revenues and other income		(52,327	)		185,329		(38,737	)		413,974

Costs and expenses:
	Oil and natural gas production			7,596			15,683		21,979			41,942
	Depreciation, depletion and amortization			8,775			31,354		24,490			81,329
	Accretion of discount on asset retirement obligations			206			394		612			1,078
	General and administrative			4,411			8,389		15,669			20,828
	Interest			9,186			13,280		26,502			41,285

		Total costs and expenses		30,174			69,100		89,252			186,462

Equity in net income of TXOK Acquisition, Inc.				—			—		—			1,593

Income (loss) from continuing operations before income taxes				(82,501	)		116,229		(127,989	)		229,105
Income tax expense (benefit)				(32,778	)		44,484		(54,010	)		89,185

Income (loss) from continuing operations				(49,723	)		71,745		(73,979	)		139,920

Discontinued operations:
	Loss from discontinued operations			—			—		(4,402	)		—
	Gain on disposition of Addison Energy Inc.			—			—		175,717			—
	Income tax expense			—			—		49,282			—

		Income from discontinued operations		—			—		122,033			—

		Net income (loss)	$	(49,723	)	$	71,745	$	48,054		$	139,920

Earnings per share:
	Basic
		Net income (loss) from continuing operations	$	(0.43	)	$	0.69	$	(0.64	)	$	1.46

		Net income (loss)	$	(0.43	)	$	0.69	$	0.41		$	1.46

		Weighted average common shares outstanding		115,947			104,056		115,947			96,144

	Diluted
		Net income (loss) from continuing operations	$	(0.43	)	$	0.68	$	(0.64	)	$	1.43

		Net income (loss)	$	(0.43	)	$	0.68	$	0.41		$	1.43

		Weighted average common and common equivalent shares outstanding		115,947			105,424		115,947			97,572

See accompanying notes.

EXCO RESOURCES, INC.

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

				Nine months ended September 30,
				2005			2006
				Predecessor			Successor
Operating Activities:
Net income				$	48,054		$	139,920
Income from discontinued operations					(122,033	)		—
Adjustments to reconcile net income to net cash provided by operating activities:
	Equity in net income of TXOK Acquisition, Inc.				—			(1,593	)
	Foreign currency transaction loss				3,461			—
	Gain on sale of other assets				(373	)		(89	)
	Depreciation, depletion and amortization				24,490			81,329
	Stock option compensation expense				—			2,427
	Accretion of discount on asset retirement obligations				612			1,078
	Non-cash change in fair value of derivatives				114,410			(164,618	)
	Deferred income taxes				(59,467	)		89,185
	Amortization of deferred financing costs and premium on 7¹/4% senior notes due 2011				1,314			4,505
		Effect of changes in:
			Accounts receivable		(23,458	)		42,944
			Other current assets		(277	)		(773	)
			Accounts payable and other current liabilities		5,708			(21,421	)
Net cash used in operating activities of discontinued operations					(73,285	)		—

Net cash provided by (used in) operating activities					(80,844	)		172,894

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment					(151,182	)		(342,634	)
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	)
Proceeds from disposition of property and equipment and other					46,010			4,613
Proceeds from sale of marketable securities					59			—
Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415 (discontinued operations)					443,397			—
Net cash used in investing activities of discontinued operations					(442	)		—

Net cash provided by (used in) investing activities					337,842			(526,286	)

Financing Activities:
Borrowings under credit agreement					41,300			498,000
Payments on interim bank loan					—			(350,000	)
Payments on long-term debt					(148,247	)		(615,849	)
Principal and interest on notes receivable—officers and employees					311			—
Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition					—			(38,098	)
Proceeds from issuance of common stock, net of underwriters' commissions and initial public offering costs					—			656,598
Deferred financing costs and other					—			(1,521	)
Net cash provided by financing activities of discontinued operations					59,601			—

Net cash provided by (used in) financing activities					(47,035	)		149,130

Net increase (decrease) in cash					209,963			(204,262	)
Cash at beginning of period					26,408			226,953

Cash at end of period				$	236,371		$	22,691

Supplemental Cash Flow Information:
Interest paid				$	33,099		$	49,983

Income taxes paid				$	38,213		$	—

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

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(Unaudited, in thousands)

	Class A Common Stock			Class B Common Stock
														Accumulated other comprehensive income (loss)
							Notes receivable— officers			Additional paid-in capital		Retained earnings					Total shareholders' equity
	Shares	Amount		Shares	Amount		Notes receivable— officers			Additional paid-in capital		Retained earnings					Total shareholders' equity
Predecessor:
Balance at December 31, 2004	115,947	$	116	11,926	$	12	$	(1,573	)	$	173,804	$	10,159	$	21,367		$	203,885
Principal and interest payments	—		—	—		—		311			—		—		—			311
Reclassification of foreign currency translation adjustment	—		—	—		—		—			—		—		(21,399	)		(21,399	)
Unrealized gain on equity investments	—		—	—		—		—			—		—		32			32
Net income	—		—	—		—		—			—		48,054		—			48,054

Balance at September 30, 2005	115,947	$	116	11,926	$	12	$	(1,262	)	$	173,804	$	58,213	$	—		$	230,883

	Class A Common Stock			Class B Common Stock
														Accumulated other comprehensive income (loss)
							Notes receivable— officers		Additional paid-in capital			Retained earnings				Total shareholders' equity
	Shares	Amount		Shares	Amount		Notes receivable— officers		Additional paid-in capital			Retained earnings				Total shareholders' equity
Successor:
Balance at December 31, 2005	50,000	$	50	—	$	—	$	—	$	354,482		$	16,350	$	—	$	370,882
Issuance of common stock, net of expenses	54,004		54	—		—		—		666,760					—		666,814
Issuance of common stock, exercise of options	63		—	—		—		—		476			—		—		476
Initial public offering costs	—		—	—		—		—		(6,027	)		—		—		(6,027	)
Share-based compensation	—		—	—		—		—		3,217			—		—		3,217
Net income	—		—	—		—		—		—			139,920		—		139,920

Balance at September 30, 2006	104,067	$	104	—	$	—	$	—	$	1,018,908		$	156,270	$	—	$	1,175,282

See accompanying notes.

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2006
(Unaudited)

1. Organization and basis of presentation

EXCO Resources, Inc., or EXCO Resources, a Texas corporation incorporated in 1955, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore properties located in the continental United States and, until February 10, 2005, in Canada. Our operations are focused in key North American oil and natural gas areas including Appalachia, East Texas, Mid-Continent, Permian and the Rockies. Our assets are 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.

Unless the context requires otherwise, references in this quarterly report to "EXCO," "EXCO Resources," "we," "us," "our" and the "Company" are to EXCO Resources, its consolidated subsidiaries and EXCO Holdings Inc., or EXCO Holdings, our former parent company, which was acquired by and into which EXCO Holdings II, Inc., or Holdings II, merged on October 3, 2005. On February 14, 2006, EXCO Holdings merged with and into EXCO Resources.

Our previously filed reports exclude the financial position and results of operations of our parent, EXCO Holdings, and Holdings II for the period prior to October 2, 2005 and subsequent to October 3, 2005, respectively. Due to the merger of our parent, EXCO Holdings (formerly EXCO Holdings II), into EXCO 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 quarterly 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 three and nine months ended September 30, 2005, financial information presented in our condensed consolidated statements of operations reflect the consolidated information of EXCO Resources and EXCO Holdings, our parent company until October 2, 2005. The condensed consolidated statements of cash flows and condensed consolidated statements of changes in shareholders' equity for the nine months ended September 30, 2005 also reflect the consolidated activities of EXCO Resources and EXCO Holdings.

Successor—For the three and nine months ended September 30, 2006, financial information presented in our condensed consolidated statements of operations reflect the consolidated information of EXCO Resources and Holdings II, which became our parent company on October 3, 2005 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 condensed consolidated statements of cash flows and the condensed consolidated statements of changes in shareholders' equity for the nine months ended September 30, 2006 also reflect the new basis. 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.

In addition, as a result of the redemption of TXOK Acquisition, Inc. preferred stock (See Note 4. "Significant recent transactions—TXOK acquisition") on February 14, 2006, our investment in TXOK Acquisition, Inc. which would have been accounted for using the cost method of accounting became a

wholly-owned subsidiary which required the use of the equity method of accounting for our investment in TXOK Acquisition, Inc. from October 7, 2005 until February 13, 2006.

The condensed consolidated balance sheet as of December 31, 2005 reflects the consolidated financial position of EXCO and Holdings II (being the 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 condensed consolidated balance sheet as of September 30, 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 condensed consolidated balance sheets as of December 31, 2005 and September 30, 2006, results of operations for the three and nine months ended September 30, 2005 and 2006 and cash flows and changes in shareholders' equity for the nine months ended September 30, 2005 and 2006, are for EXCO, its subsidiaries, and prior to the IPO, its parent. All intercompany transactions have been eliminated. Our results of operations for the three and nine months ended September 30, 2005 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.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the SEC and in the opinion of management reflect all adjustments necessary to present fairly the consolidated financial position of EXCO at September 30, 2006 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. You should read these unaudited interim financial statements in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2005 and with the audited financial statements of EXCO Resources, Inc. filed with our Current Report on Form 8-K, dated May 15, 2006 and filed on May 16, 2006 which presents our consolidated financial statements for 2005 including EXCO Holdings.

The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

2. Recent accounting pronouncements

In July 2006, the Financial Accounting Standards Board 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 are currently assessing the impact, if any, of FIN 48 on our financial statements.

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 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. The Company is currently evaluating the impact that SAB 108 may have on its financial position, results of operations and cash flows.

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157, "Fair Value Measurements," or SFAS No. 157 which defines fair value and provides guidance for using fair value to measure assets and liabilities. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or a liability and establishes a fair value hierarchy that prioritizes information used to develop those assumptions. Under SFAS No. 157, fair value measurements are to be separately disclosed by levels (i.e. levels 1, 2 and 3, as defined) within the fair value hierarchy and companies are required to provide enhanced disclosure regarding fair value amounts in the level 3 category (recurring fair value measurements using significant observable inputs), and a reconciliation of beginning and ending balances separately for each category of assets and liabilities. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of SFAS No. 157, if any, on our financial position, results of operations or cash flows.

3. Significant accounting policies

As a result of our increased activities in acquisitions, we consider business combinations and purchase accounting as a significant accounting policy. We follow SFAS No. 141 to account for these transactions. The policy includes significant estimates to be made by management using information

available at the time. 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.

When computing our full cost accounting ceiling test limitation (See Note 7. "Oil and natural gas properties"), 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 period date, we subsequently evaluate the limitation for price changes that occur after the balance sheet date to assess impairment as permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities.

4. Significant recent transactions

TXOK acquisition

On September 16, 2005, Holdings II formed TXOK Acquisition, Inc., or 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 $642.9 million, or $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, 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.

Prior to TXOK's redemption of the preferred stock concurrently with the IPO, we held an 11% economic interest in TXOK and would have used the cost method of accounting for that investment until the merger. However, since the redemption of the preferred stock resulted in TXOK becoming a wholly-owned subsidiary on February 14, 2006, we applied the equity method of accounting for our investment in TXOK for the period of October 7, 2005 until the February 14, 2006 effective date of the acquisition.

Equity Buyout

On October 3, 2005, Holdings II, an entity formed by our management, purchased 100% of the outstanding equity securities of EXCO Holdings in an equity buyout, or Equity Buyout, for an aggregate price of approximately $699.3 million, resulting in a change of control and a new basis of accounting. To fund the Equity Buyout, Holdings II raised $350.0 million in interim debt financing, including $0.7 million for working capital, from a group of lenders and $183.1 million of equity

financing from new institutional and other investors as well as stockholders of EXCO Holdings. In addition, current management and other stockholders of EXCO Holdings exchanged $166.9 million of their EXCO Holdings common stock for Holdings II common stock. EXCO Holdings' majority stockholder sold all of its EXCO Holdings common stock for cash. Promptly following the completion of the Equity Buyout, Holdings II merged with and into EXCO Holdings. As a result of the merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of EXCO Holdings common stock and all shares of EXCO Holdings common stock held by Holdings II were cancelled.

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 EXCO 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, EXCO 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. Goodwill resulting from the acquisition of TXOK was allocated to our U.S. (excluding Appalachia) business segment. The preliminary 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).

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. Goodwill resulting from the acquisition of PGMT was allocated to our Appalachia

business segment. The allocation of the purchase price to the assets and liabilities of PGMT, which is preliminary and subject to change, 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

Pro forma results of operations

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

	Nine months ended September 30,
	2005			2006
Revenues and other income	$	44,661		$	461,858
Income (loss) from continuing operations		(70,334	)		161,024
Net income		51,699			161,024
Basic earnings per share		0.45			1.67
Diluted earnings per share		0.45			1.65

5. Sale of Addison Energy Inc.

On January 17, 2005, our directors approved the Share and Debt Purchase Agreement, or the Addison Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., a corporation organized under the laws of the Province of Alberta, or Purchaser, and a wholly-owned subsidiary of NAL Oil & Gas Trust, an Alberta trust, EXCO and Taurus Acquisition, Inc., or Taurus, our wholly-owned subsidiary that has since been renamed ROJO Pipeline, Inc., or ROJO. 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., or 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. $443.3 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 remitted to the Canadian government for income taxes resulting from the sale of the stock. As of December 31, 2005, we had recorded a receivable in the amount of Cdn. $21.5 million (U.S. $18.5 million) for our estimate of the excess of the amount withheld for Canadian income taxes from the sales proceeds over the estimated amount of Canadian income taxes that are actually owed on the gain from the sale. This receivable was collected in March 2006. As of September 30, 2006, 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.

All severance payments paid or payable in respect of employees terminated up to May 31, 2005 were borne by EXCO, unless the Purchaser or its affiliates made an employment offer to a terminated employee and the employee accepted the offer, in which case 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.

During the nine months ended September 30, 2005, 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. These amounts were considered in the determination of the gain on the sale.

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.

6. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations as of September 30, 2005 and 2006 (in thousands):

	Nine months ended September 30,
	2005			2006
	(Unaudited)
Asset retirement obligation at January 1	$	28,043		$	15,823
Acquisition of TXOK Acquisition, Inc.		—			8,203
Acquisition of Power Gas Marketing & Transmission, Inc.		—			1,527
Sale of Addison Energy Inc.		(14,796	)		—
Liabilities incurred during the period		1,686			2,174
Liabilities settled during the period		(1,275	)		(238	)
Accretion of discount		612			1,078

Asset retirement obligations as of September 30		14,270			28,567
Less current portion		1,713			1,428

Long-term portion	$	12,557		$	27,139

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

7. 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 present value of future net revenues plus the lower of cost or fair market value of unproved properties less the income tax effects related to book and tax basis of the oil and natural gas properties involved. The full cost pool is comprised of lease and well equipment and exploration and development costs incurred, plus intangible acquired proved leaseholds.

Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not Proved Reserves can be assigned to such properties. At December 31, 2005 and September 30, 2006, $53.1 million and $137.6 million, respectively, in unproved oil and natural gas properties were excluded from our full cost pool in calculating our depreciation, depletion and amortization. We assess our unproved oil and natural gas properties for impairment on a quarterly basis. We use a combination of individual assessment for impairment on our significant unproved assets and aggregate assessments for less significant groupings of unproved properties.

Depreciation, depletion and amortization of evaluated oil and natural gas properties are calculated separately for the United States and, until February 10, 2005, Canadian full cost pools using the unit-of-production method based on total Proved Reserves, as determined by independent petroleum reservoir engineers or by our internal engineers for our Canadian Proved Reserves at December 31, 2004.

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

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

As of September 30, 2006, due primarily to significant declines in natural gas prices, most notably a 31% decrease in spot prices at Henry Hub (from $6.09 per Mmbtu on June 30, 2006 to $4.18 per Mmbtu on September 30, 2006), our carrying costs of unamortized proved oil and natural gas properties, net of deferred taxes, exceeded the September 30, 2006 present value of future net revenues calculated on a constant price basis by $498.5 million, after tax. Subsequent to September 30, 2006, prices for natural gas increased. As of October 30, 2006, the spot market price at Henry Hub was $7.41 per Mmbtu. Accordingly, the requirement to record a ceiling test write-down was eliminated as a result of these price increases and therefore, we have not recorded a ceiling test write-down as of September 30, 2006.

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.

8. Goodwill

We test goodwill annually, as of December 31, for impairment, unless an earlier indication of impairment indicator arises. As a result of the potential ceiling test write-down described in Note 7. "Oil and natural gas properties" above, we performed a goodwill impairment test as of September 30, 2006. The results indicated no impairment was required. Goodwill resulting from the acquisition of TXOK was allocated to our U.S. (excluding Appalachia) business segment while goodwill arising from our PGMT acquisition was allocated to our Appalachia business segment. As of September 30, 2006, goodwill totaled $141.6 million and $164.5 million for our U.S. (excluding Appalachia) business segment and Appalachia segment, respectively. As a result of the October 2, 2006 acquisition described in Note 16. "Subsequent event," we expect additional goodwill to be recognized. The following table presents the activity for our goodwill balances from the acquisition of TXOK and PGMT (in thousands):

Balance as of December 31, 2005	$	220,006
Acquisition of TXOK Acquisition, Inc.		64,887
Acquisition of Power Gas Marketing & Transmission, Inc.		21,249

Balance as of September 30, 2006	$	306,142

9. Earnings per share

We account for earnings per share in accordance with Statement of Financial Accounting Standard No. 128, "Earnings Per Share", or SFAS No. 128. SFAS No. 128 requires companies to present two calculations of earnings per share (EPS), basic and diluted. Basic earnings (loss) per common share for the three and nine months ended September 30, 2005 and 2006 equals the net income divided by the weighted average common shares outstanding during the period. Diluted earnings (loss) per common share for the three and nine months ended September 30, 2005 and 2006 equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents assumed to be issued. Common stock equivalents for the three and nine months ended September 30, 2005 and 2006 are shares assumed to be issued if EXCO's outstanding stock options were in-the-money and exercised. As a result of the loss from continuing operations for the three and nine months ended September 30, 2005, the potential common stock equivalents from the assumed conversion of stock options of 8,801,351 have been excluded from the diluted EPS calculation.

The following table presents the basic and diluted earnings (loss) per share computations for the three and nine months ended September 30, 2005 and 2006 (in thousands, except per share amounts):

		Three months ended September 30,					Nine months ended September 30,
		2005			2006		2005			2006
Basic earnings per share:
	Income (loss) from continuing operations	$	(49,723	)	$	71,745	$	(73,979	)	$	139,920
	Income from discontinued operations		—			—		122,033			—

	Net income (loss)	$	(49,723	)	$	71,745	$	48,054		$	139,920

Shares:
	Weighted average number of common shares outstanding		115,947			104,056		115,947			96,144

Basic earnings (loss) per share:
	Continuing operations.	$	(0.43	)	$	0.69	$	(0.64	)	$	1.46
	Discontinued operations		—			—		1.05			—

	Total basic earnings (loss) per share	$	(0.43	)	$	0.69	$	0.41		$	1.46

Diluted earnings per share:
	Income (loss) from continuing operations	$	(49,723	)	$	71,745	$	(73,979	)	$	139,920
	Income from discontinued operations		—			—		122,033			—

	Net income (loss)	$	(49,723	)	$	71,745	$	48,054		$	139,920

Shares:
	Weighted average number of common shares outstanding		115,947			104,056		115,947			96,144
	Dilutive effect of stock options		—			1,368		—			1,428

	Weighted average common shares and common stock equivalents		115,947			105,424		115,947			97,572

Diluted earnings (loss) per share:
	Continuing operations	$	(0.43	)	$	0.68	$	(0.64	)	$	1.43
	Discontinued operations		—			—		1.05			—

	Total diluted earnings (loss) per share	$	(0.43	)	$	0.68	$	0.41		$	1.43

10. Stock options

In August 2005, Holdings II adopted the 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan. As a result of the merger of Holdings II with and into EXCO Holdings in connection with the Equity Buyout, the 2005 Incentive Plan was assumed by EXCO Holdings. As a result of the merger of EXCO Holdings with and into EXCO Resources in connection with the IPO, the 2005 Incentive Plan was assumed by EXCO Resources effective February 14, 2006. All awards previously granted under the 2005 Incentive Plan were then converted into awards in EXCO Resources common stock pursuant to the requirements of Treasury Regulation section 1.424-1.

We adopted Statement of Financial Accounting Standards No. 123(R), "Share-Based Compensation", or SFAS No. 123(R), on October 3, 2005. As required by SFAS 123(R), the granting of options to our employees under the 2005 Incentive Plan 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 volatility of our common stock from October 1, 2001 to December 31, 2002 and the daily closing prices from five comparable public companies. For the three and nine months ended September 30, 2006, total share-based compensation was $1.0 million and $3.2 million, respectively. A portion of our share-based compensation is capitalized to oil and natural gas properties. The capitalized amounts for the three months ended September 30, 2006 were $0.3 million and $0.7 million for the nine months ended September 30, 2006. Total share-based compensation to be recognized on unvested awards as of September 30, 2006 is $7.2 million over a weighted average period of 2.5 years.

During the nine months ended September 30, 2006, options to purchase 812,100 shares were granted by EXCO under the 2005 Incentive Plan at prices ranging from $11.90 to $13.45 per share, with fair values ranging from $3.84 to $4.52. The options expire ten years following 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 of December 31, 2005 and September 30, 2006, there were 5,026,925 and 4,342,900 shares available to be granted under the 2005 Incentive Plan, respectively.

Prior to October 3, 2005, as allowed by Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation", we elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," or APB 25, and provide pro forma disclosures of earnings and earnings per share as if a fair value based method of accounting for employee stock compensation plans were adopted. Under APB 25, no compensation expense is recognized upon the issuance of stock options to our employees as the exercise price of the option is equal to or higher than the fair value of the underlying common stock at the date of grant.

11. Segment information

We have operations in only one industry segment—the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have geographic operating segments in the United States and, until February 10, 2005, in Canada. Upon the acquisition of TXOK at the closing of the IPO, our geographic operating segments in the United States were the U.S. (excluding Appalachia), which includes the properties of EXCO, excluding

Appalachia, and the TXOK properties, and the Appalachian segment, which includes the properties of North Coast. The following tables provide our geographic operating segment data:

			U.S. (excluding Appalachia)			Appalachia			Total
			(in thousands)
Three months ended September 30, 2005:
Revenues and other income:
	Oil and natural gas		$	20,928		$	30,843		$	51,771
	Derivative financial instruments			(35,846	)		(71,659	)		(107,505	)
	Other income			2,739			668			3,407

		Total revenues and other income		(12,179	)		(40,148	)		(52,327	)

Costs and expenses:
	Oil and natural gas production			3,731			3,865			7,596
	Depreciation, depletion and amortization			3,696			5,079			8,775
	Accretion of discount on asset retirement obligations			87			119			206
	General and administrative			2,906			1,505			4,411
	Interest			4,104			5,082			9,186

		Total costs and expenses		14,524			15,650			30,174

	Loss before income taxes			(26,703	)		(55,798	)		(82,501	)
	Income tax benefit			(10,505	)		(22,273	)		(32,778	)

	Net loss		$	(16,198	)	$	(33,525	)	$	(49,723	)

	Goodwill at end of period		$	19,984		$	—		$	19,984

	Total assets at end of period		$	463,904		$	446,615		$	910,519

			U.S. (excluding Appalachia)		Appalachia		Total
			(in thousands)
Three months ended September 30, 2006:
Revenues and other income:
	Oil and natural gas		$	56,221	$	28,669	$	84,890
	Derivative financial instruments			62,954		36,807		99,761
	Other income			307		371		678

		Total revenues and other income		119,482		65,847		185,329

Costs and expenses:
	Oil and natural gas production			10,271		5,412		15,683
	Depreciation, depletion and amortization			21,611		9,743		31,354
	Accretion of discount on asset retirement obligations			221		173		394
	General and administrative			6,555		1,834		8,389
	Interest			5,806		7,474		13,280

		Total costs and expenses		44,464		24,636		69,100

	Income before income taxes			75,018		41,211		116,229
	Income tax expense			28,805		15,679		44,484

	Net income		$	46,213	$	25,532	$	71,745

	Goodwill at end of period		$	141,673	$	164,469	$	306,142

	Total assets at end of period		$	1,371,504	$	1,027,631	$	2,399,135

			U.S. (excluding Appalachia)			Appalachia			Total
			(in thousands)
Nine months ended September 30, 2005:
Revenues and other income:
	Oil and natural gas		$	54,642		$	76,827		$	131,469
	Derivative financial instruments			(56,704	)		(120,549	)		(177,253	)
	Other income			5,784			1,263			7,047

		Total revenues and other income		3,722			(42,459	)		(38,737	)

Costs and expenses:
	Oil and natural gas production			11,329			10,650			21,979
	Depreciation, depletion and amortization			11,277			13,213			24,490
	Accretion of discount on asset retirement obligations			275			337			612
	General and administrative			11,820			3,849			15,669
	Interest			17,719			8,783			26,502

		Total costs and expenses		52,420			36,832			89,252

	Loss before income taxes			(48,698	)		(79,291	)		(127,989	)
	Income tax benefit			(14,249	)		(39,761	)		(54,010	)

	Loss from continuing operations			(34,449	)		(39,530	)		(73,979	)

	Discontinued operations:
	Loss from discontinued operations			(4,402	)		—			(4,402	)
	Gain on sale of Addison Energy Inc.			175,717			—			175,717
	Income tax expense			49,282			—			49,282

	Net income from discontinued operations			122,033			—			122,033

	Net income (loss)		$	87,584		$	(39,530	)	$	48,054

	Goodwill at end of period		$	19,984		$	—		$	19,984

	Total assets at end of period		$	463,904		$	446,615		$	910,519

			U.S. (excluding Appalachia)		Appalachia		Total
			(in thousands)
Nine months ended September 30, 2006:
Revenues and other income:
	Oil and natural gas		$	143,136	$	91,498	$	234,634
	Derivative financial instruments			91,124		84,644		175,768
	Other income			2,248		1,324		3,572

		Total revenues and other income		236,508		177,466		413,974

Costs and expenses:
	Oil and natural gas production			27,201		14,741		41,942
	Depreciation, depletion and amortization			53,848		27,481		81,329
	Accretion of discount on asset retirement obligations			601		477		1,078
	General and administrative			16,340		4,488		20,828
	Interest			20,659		20,626		41,285

		Total costs and expenses		118,649		67,813		186,462

	Equity in net income of TXOK Acquisition, Inc.			1,593		—		1,593

	Income before income taxes			119,452		109,653		229,105
	Income tax expense			46,887		42,298		89,185

	Net income		$	72,565	$	67,355	$	139,920

	Goodwill at end of period		$	141,673	$	164,469	$	306,142

	Total assets at end of period		$	1,371,504	$	1,027,631	$	2,399,135

12. 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. Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activity," or SFAS No. 133, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings.

We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the derivative's fair value currently in earnings.

In January and March 2005, we closed several of our derivative financial instrument contracts and made payments to our counterparties totaling $67.6 million, 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 for increased volumes and with higher underlying product prices.

In April 2006, we closed all of the hedge positions of PGMT we assumed in that acquisition and replaced those hedges with derivative contracts at higher prices.

The fair values at September 30, 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 September 30, 2006. We have the right to offset amounts we expect to receive or pay among our individual counterparties, all of which are lenders under our credit agreement. As a result, we have offset amounts for financial statement presentation purposes. The following table sets forth our oil and natural gas derivatives as of September 30, 2006 (in thousands, except prices).

Natural gas:		Volume Mmbtus/bbls	Weighted average strike price		Weighted average differential to NYMEX			Fair value at September 30, 2006
Swaps:
	Remainder 2006	7,514	$	8.41				$	18,860
	2007	29,790		8.52					24,731
	2008	25,140		8.50					12,079
	2009	7,705		7.14					(4,120	)
	2010	6,985		6.63					(5,380	)
	2011	1,825		4.51					(4,169	)
	2012	1,830		4.51					(3,564	)
	2013	1,825		4.51					(3,046	)

		82,614

Basis Swaps:
	Remainder 2006	1,380			$	(0.32	)		210

Total natural gas									35,601

Oil:
Swaps:
	Remainder 2006	173		71.02					1,140
	2007	734		69.52					1,055
	2008	327		62.67					(1,832	)
	2009	120		60.80					(689	)
	2010	108		59.85					(518	)

		1,462

Floor:
	Remainder 2006	27		50.35					1

Ceiling:
	Remainder 2006	27		60.00					(138	)

Total oil									(981	)

Total oil and natural gas								$	34,620

At September 30, 2006, the average forward NYMEX oil prices per Bbl for the remainder of calendar 2006 and for 2007 were $64.36 and $68.05, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of calendar 2006 and for 2007 were $5.72 and $7.67, respectively.

13. Long-term debt and interim bank loan

Long-term debt is summarized as follows:

		December 31, 2005		September 30, 2006
		(in thousands)
Short-term debt:
Interim bank loan		$	350,000	$	—

Long-term debt:
Borrowings under our credit agreement		$	1	$	404,000
7¹/4% senior notes due 2011			444,720		444,720
Unamortized premium on 7¹/4% senior notes due 2011			17,081		14,872

	Total long-term debt	$	461,802	$	863,592

Credit agreement

On March 17, 2006, we entered into an amended and restated credit agreement, or 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 the credit agreement maturity date to December 31, 2010. The borrowing base will be redetermined each November 1 and May 1, beginning November 1, 2006. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. Financial covenants under this credit agreement require that we:

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

Borrowings under our credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast and TXOK. As of March 17, 2006, 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 and was raised to $500.0 million on May 11, 2006. This aggregate commitment minimum remained at $500.0 million as of September 30, 2006.

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 base 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.

any new indebtedness we may incur under the credit agreement. At December 31, 2005 and September 30, 2006, we had $1,000 and $404.0 million, respectively, of outstanding indebtedness under our credit agreement. As of September 30, 2006, we had $96.0 million available under our credit agreement based on the current aggregate commitment of $500.0 million. Management believes our cash flows from operations will provide sufficient cash to service our debt.

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 September 30, 2006, we were in compliance with our debt covenants. On October 2, 2006, we amended our credit agreement, and our borrowing base was reduced to $600.0 million and the commitment reduced to $400.0 million. See Note 16. "Subsequent events" for further details.

7¹/4% senior notes due January 15, 2011

The estimated fair value of our 7¹/4% senior notes due January 15, 2011, or senior notes, at September 30, 2006 was $434.7 million as compared to the carrying amount of $459.6 million (including $14.9 million of unamortized premium). The fair value of the senior notes is estimated based on quoted market prices for the senior notes.

Interim bank loan

In order to fund the Equity Buyout on October 3, 2005, Holdings II borrowed $350.0 million in interim debt financing under a credit agreement dated October 3, 2005. The interim bank loan was collateralized by a first priority lien on all of the common stock of EXCO. The maturity date of the interim bank 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.

The interim bank loan was initially legally in the name of Holdings II. Upon completion of the Equity Buyout and the merger of Holdings II into EXCO Holdings, the interim bank loan became an obligation of EXCO Holdings. The Equity Buyout resulted in a change of control. Generally Accepted Accounting Principals in the United States, or GAAP, requires the acquisition by Holdings II to be accounted for as a purchase transaction in accordance with SFAS No. 141. In addition, GAAP requires the application of "push down accounting" in situations where the ownership of an entity has changed, meaning that the post transaction financial statements of the acquired entity (EXCO) reflect the new basis of accounting in accordance with Staff Accounting Bulletin 54, or SAB 54. In addition to the stepped-up basis resulting from the Equity Buyout, the interim bank loan was "pushed-down" to EXCO and was presented as a component of consolidated debt.

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

14. Commitments and contingencies

On October 11, 2006, a putative class action was filed against our subsidiary, North Coast. The case is styledPRC Holdings, LLC, et al. v. North Coast Energy, Inc. (Civil Action No. 06-C-80E) and is pending in the Circuit Court of Roane County, 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 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 styledThe 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 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. The Company intends to vigorously defend this action. Because this action is in a very preliminary stage, the ultimate outcome of this litigation cannot be determined at this time. However, management does not expect the ultimate outcome of the lawsuit to have a material effect on the financial position, results of operations or cash flows of EXCO Resources.

We, and our subsidiaries, are from time to time parties to legal proceedings, lawsuits and other claims incident to our business activities. Such matters may include, among other things, assertions of contract breach, landowner claims, lessor claims, title disputes, or claims for indemnity arising in the course of our business. Such matters are subject to many uncertainties and outcomes are not predictable with assurance. Consequently, we may be unable to ascertain the ultimate aggregate amount of monetary liability, amounts which may be covered by insurance or recoverable from third parties, or the financial impact with respect to these matters as of the date of this report.

15. Acquisitions and dispositions

Transactions, other than TXOK and PGMT, that occurred during the nine months ended September 30, 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 $137.3 million, which was funded with indebtedness drawn under our credit agreement.

In August and September 2006, we closed two acquisitions of producing properties and acreage for an aggregate purchase price of $76.6 million, after contractual adjustments, adding properties and acreage in our Appalachia and Rockies areas. In our Appalachia business segment, we acquired approximately 16.3 Bcfe of Proved Reserves (primarily in Devonian Sands), using the September 30, 2006 spot price, approximately 25,000 net acres, and 3.0 Mmcfe per day of production for $49.1 million. In our U.S. (excluding Appalachia) business segment, we paid $27.5 million for properties located in Wyoming containing approximately 112,000 net acres, 6.0 Bcfe of Proved Reserves (using the September 30, 2006 spot price) and 1.0 Mmcfe per day of production.

During the three months ended September 30, 2006, we sold one property for $3.1 million.

Transactions, other than the sale of Addison, that occurred during the nine months ended September 30, 2005

During the nine months ended September 30, 2005, we completed seven oil and natural gas property acquisitions. Estimated total Proved Reserves net to our interest from the acquisitions included approximately 0.1 Mmbbls of oil and 59.8 Bcf of natural gas. The total purchase price for the acquisitions was approximately $102.3 million, funded with borrowings under our 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 nine months ended September 30, 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 nine months ended September 30, 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.

16. Subsequent events

On July 24, 2006, we announced an agreement to acquire Winchester Energy Company, Ltd., or Winchester, and its affiliated entities, or Winchester, from Progress Energy, Inc., through our wholly-owned subsidiary, Winchester Acquisition, LLC, or Winchester Acquisition. The acquisition consists of producing and undeveloped natural gas properties with current production of approximately 72.0 Mmcfe per day from 549 producing wells, of which 81% are operated. The properties contain approximately 734 gross (675.1 net) drilling locations and are located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. Proved Reserves acquired were approximately 209.3 Bcfe using the September 30, 2006 spot price. As a result of price increases in natural gas subsequent to September 30, 2006, the Proved Reserves from the Winchester acquisition would increase to 385.0 Bcfe using the October 30, 2006 spot price for natural gas applied on a constant price basis. The acquisition also included six gathering systems with 300 miles of pipe and a 54 mile, 16 inch pipeline with throughput of 115 Mmcf per day, approximately 25% of which represents Winchester production. We paid approximately $1.1 billion after closing adjustments, subject to additional post-closing price adjustments, and closed on October 2, 2006.

��Concurrent with the closing, we formed EXCO Partners, LP, or EXCO Partners, our wholly-owned subsidiary. We contributed to EXCO Partners all of our East Texas oil and natural gas properties and related assets and four of our subsidiaries, ROJO Pipeline, LP (formerly known as ROJO Pipeline, Inc.), TXOK Energy Resources Holding, LLC, TXOK Texas Energy Holding, LLC and TXOK Texas Energy Resources, L.P. (the contributed assets and subsidiaries being collectively the EXCO Legacy Assets), in exchange for $150.0 million of cash and additional equity interests in EXCO Partners. The entities contributed are no longer guarantors or restricted subsidiaries under our credit agreement, or the Indenture governing our 7¹/4% senior notes. We also contributed Winchester Acquisition concurrent with the closing of the Winchester transaction.

EXCO Partners borrowed a total of $1.3 billion to finance the acquisition of Winchester and pay EXCO for its contribution of assets. The borrowings were made under two new credit arrangements, a new revolving credit facility of $750.0 million with an initial conforming borrowing base of $650.0 million and a $650.0 million senior term credit agreement.

A summary of each of the credit agreements entered into by EXCO Partners follows:

EXCO Partners Revolving Credit Facility

To finance the Winchester merger and the $150.0 million payment to EXCO Resources for the EXCO Legacy Assets, EXCO Partners' wholly-owned subsidiary, EXCO Partners Operating Partnership, LP, or EPOP, entered into a Senior Revolving Credit Agreement, or the Revolving Credit Facility, dated October 2, 2006, with a group of lenders led by JPMorgan Chase Bank, N.A. The

Revolving Credit Facility has a face amount of $750.0 million with an initial borrowing base of $750 million and an initial conforming borrowing base of $650.0 million. Interest on the initial conforming borrowing base is LIBOR plus 175 basis points. Borrowings in excess of the conforming borrowing base is LIBOR plus 250 points. The borrowing base must be conforming by April 1, 2007. The 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 of EPOP. 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 ratio of (A) Consolidated Funded Indebtedness (as defined) as of the end of a fiscal quarter to (B) Consolidated EBITDAX (as defined) for such quarter, may not be greater than (i) 5.00 to 1.00 as of the end of December 31, 2006 (Consolidated EBITDAX for such quarter to be multiplied by four), (ii) 4.00 to 1.00 for the first or second quarter of 2007 (Consolidated EBITDAX calculated using a defined trailing period multiplied by a fraction) or (iii) 4.00 to 1.00 for any quarter ending on or after September 30, 2007 (with Consolidated EBITDAX calculated using the trailing four quarter period ending on such date.) EPOP will not permit its ratio of Consolidated EBITDAX to Consolidated Interest Expenses (as defined) to be less than 2.50 to 1.00 for specified measurement periods. Finally, EPOP will not permit its ratio of net present value (calculated pursuant to the terms of the Revolving Credit Facility) to Consolidated Funding Indebtedness (as defined) to be less than (i) 1.15 to 1.00 determined as of December 31, 2006 or (ii)1.25 to 1.00 determined as of each succeeding June 30 and December 31. The Revolving Credit Facility contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The 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 million of the Revolving Credit Facility. To the extent usage exceeds the initial conforming borrowing base, the 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. The Revolving Credit Facility contains a pricing grid based on availability. Finally, as a condition precedent to the funding of the 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.

EXCO Partners Senior Term Credit Agreement

bps, with 25 bps step ups on October 2, 2007 and January 2, 2008, and a total cap of LIBOR + 650 bps. Additionally, the Senior Term Credit Agreement matures five years from the closing date, amortizes at 1% per year, with a bullet payment at maturity. Upon an initial public offering by EXCO Partners, EPOP shall prepay the principal outstanding (plus accrued interest) under the Senior Term Credit Agreement at par plus the 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 Senior Term Credit Agreement) toward prepayment at par of the 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 Senior Term Credit Agreement. Any principal payment prior to the first anniversary, other than the Excess Cash Flow 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 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, or 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 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 Senior Term Credit Agreement can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become "Restricted Subsidiaries" under EXCO's 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 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 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 Senior Term Credit Agreement.

Amendment to EXCO Credit Agreement

In connection with the formation of EXCO Partners, we amended our credit agreement. The subsidiaries contributed to EXCO Partners are no longer guarantors or restricted subsidiaries under our credit agreement, nor are they guarantors or pledgors of assets under our credit agreement. As a result of the contribution of the EXCO Legacy Assets to EXCO Partners, the borrowing base was reduced to $600.0 million with a reduced commitment of $400.0 million.

Other

Subsequent to September 30, 2006, we issued stock options to purchase approximately 600,000 shares of our common stock, primarily to new employees hired as a result of the Winchester acquisition. We expect this issuance to increase the related share-based compensation by approximately $0.7 million in the fourth quarter of 2006.

In connection with our acquisition of Winchester, we assumed derivative financial instruments covering production for the remainder of 2006 through 2008. For the remainder of 2006, approximately 1,915,000 Mmbtu are subject to swap agreements with a weighted average price of $9.52 per Mmbtu while 2,640,000 Mmbtu were subject to collars with a weighted average floor of $6.26 per Mmbtu and a weighted average ceiling of $9.48. For 2007, 2008 and 2009, we assumed swap agreements covering 18,000,000 Mmbtu per year at a weighted average price of $9.07, $8.80 and $8.39 per Mmbtu, respectively.

17. Consolidating financial statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary. The senior notes are jointly and severally and unconditionally guaranteed by our current and some of our future subsidiaries in the United States (referred to as Guarantor Subsidiaries). All of our subsidiaries are wholly-owned. Addison was not a guarantor of the senior notes. Instead, the notes were secured, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison. This share pledge was limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever was greatest) of such pledged capital stock was not equal to or greater than 20% of the then outstanding aggregate principal amount of the senior notes.

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

•: EXCO Resources;
•: the guarantor subsidiaries on a combined basis;
•: the non-guarantor subsidiary;
•: elimination entries necessary to consolidate EXCO Resources, the guarantor subsidiaries and the non-guarantor subsidiary; and
•: EXCO on a consolidated basis.

ROJO Pipeline, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC are guarantors of the senior notes. These companies have no material operations and, accordingly, these companies have been omitted from the guarantor financial information. Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the guarantor and non-guarantor subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investment in subsidiaries and intercompany balances and transactions. On February 14, 2006, TXOK became a

guarantor of our senior notes. On April 28, 2006, PGMT became a guarantor of our senior notes. On October 2, 2006, ROJO Pipeline, LP and the TXOK subsidiaries that hold certain of our East Texas oil and natural gas assets were released from their guaranties of our senior notes and are no longer restricted subsidiaries thereunder. On October 2, 2006, ROJO Pipeline, Inc. and certain of the TXOK subsidiaries were released from their guarantees of the senior notes. See Note 16. "Subsequent Events."

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

December 31, 2005

	EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	191,499		$	35,454		$	—	$	—		$	226,953
Other current assets		67,649			47,923			—		—			115,572

Total current assets		259,148			83,377			—		—			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			53,072			—		—			53,121
Proved developed and undeveloped oil and natural gas properties		94,872			778,723			—		—			873,595
Allowance for depreciation, depletion and amortization		(1,650	)		(11,631	)		—		—			(13,281	)

Oil and natural gas properties, net		93,271			820,164			—		—			913,435

Gas gathering, office and field equipment, net		1,745			31,526			—		—			33,271
Goodwill		76,786			143,220			—		—			220,006
Investments in and advances to affiliates		892,653			(742	)		—		(891,911	)		—
Other assets, net		—			419			—		—			419

Total assets	$	1,344,440		$	1,077,964		$	—	$	(891,911	)	$	1,530,493

Liabilities and Shareholders' Equity
Current liabilities	$	769,209		$	52,569		$	—	$	(356,053	)	$	465,725
Long-term debt		461,802			—			—		—			461,802
Deferred income taxes		34,151			100,761			—		—			134,912
Other liabilities		56,974			40,198			—		—			97,172
Payable to parent		(348,578	)		371,199			—		(22,621	)		—
Commitments and contingencies		—			—			—		—			—
Shareholders' equity		370,882			513,237			—		(513,237	)		370,882

Total liabilities and shareholders' equity	$	1,344,440		$	1,077,964		$	—	$	(891,911	)	$	1,530,493

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

September 30, 2006

	EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	7,460		$	15,231		$	—	$	—		$	22,691
Other current assets		31,764			95,894			—		—			127,658

Total current assets		39,224			111,125			—		—			150,349

Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		11,565			126,041			—		—			137,606
Proved developed and undeveloped oil and natural gas properties		132,836			1,671,423			—		—			1,804,259
Allowance for depreciation, depletion and amortization		(7,811	)		(83,282	)		—		—			(91,093	)

Oil and natural gas properties, net		136,590			1,714,182			—		—			1,850,772

Gas gathering, office and field equipment, net		2,956			56,997			—		—			59,953
Deferred financing costs		1,005			405			—		—			1,410
Oil and natural gas derivatives		8,451			21,558			—		—			30,009
Goodwill		78,317			227,825			—		—			306,142
Investments in and advances to affiliates		1,362,514			61,047			—		(1,423,561	)		—
Other assets, net		—			500			—		—			500

Total assets	$	1,629,057		$	2,193,639		$	—	$	(1,423,561	)	$	2,399,135

Liabilities and Shareholders' Equity
Current liabilities	$	36,277		$	72,743		$	—	$	—		$	109,020
Long-term debt		863,592			—			—		—			863,592
Deferred income taxes		38,854			147,062			—		—			185,916
Other liabilities		8,555			56,770			—		—			65,325
Payable to parent		(115,236	)		577,664			—		(462,428	)		—
Commitments and contingencies		—			—			—		—			—
Shareholders' equity		797,015			1,339,400			—		(961,133	)		1,175,282

Total liabilities and shareholders' equity	$	1,629,057		$	2,193,639		$	—	$	(1,423,561	)	$	2,399,135

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the three months ended September 30, 2005

		EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiary		Eliminations			Consolidated
		(In thousands)
Revenues and other income:
	Oil and natural gas sales	$	8,693		$	43,078		$	—	$	—		$	51,771
	Derivative financial instruments		(35,849	)		(71,656	)		—		—			(107,505	)
	Other income (loss)		7,554			936			—		(5,083	)		3,407
	Equity in earnings of subsidiaries		(25,150	)		—			—		25,150			—

	Total revenues and other income		(44,752	)		(27,642	)		—		20,067			(52,327	)

Costs and expenses:
	Oil and natural gas production		2,239			5,357			—		—			7,596
	Depreciation, depletion and amortization		1,272			7,503			—		—			8,775
	Accretion of discount on asset retirement obligations		79			130			—		—			206
	General and administrative		2,906			1,505			—		—			4,411
	Interest		9,006			5,260			—		(5,083	)		9,186

	Total costs and expenses		15,502			19,755			—		(5,083	)		30,174

Income (loss) before income taxes			(60,254	)		(47,397	)		—		25,150			(82,501	)
Income tax benefit			(10,531	)		(22,247	)		—		—			(32,778	)

Net income (loss)		$	(49,723	)	$	(25,150	)	$	—	$	25,150		$	(49,723	)

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the three months ended September 30, 2006

		EXCO Resources		Guarantor subsidiaries		Non- guarantor subsidiary		Eliminations			Consolidated
		(In thousands)
Revenues and other income:
	Oil and natural gas sales	$	8,393	$	76,497	$	—	$	—		$	84,890
	Derivative financial instruments		25,659		74,102		—		—			99,761
	Other income (loss)		7,356		805		—		(7,483	)		678
	Equity in earnings of subsidiaries		64,254		—		—		(64,254	)		—

	Total revenues and other income		105,662		151,404		—		(71,737	)		185,329

Costs and expenses:
	Oil and natural gas production		2,497		13,186		—		—			15,683
	Depreciation, depletion and amortization		2,780		28,574		—		—			31,354
	Accretion of discount on asset retirement obligations		61		333		—		—			394
	General and administrative		5,090		3,299		—		—			8,389
	Interest		13,289		7,474		—		(7,483	)		13,280

	Total costs and expenses		23,717		52,866		—		(7,483	)		69,100

Income (loss) before income taxes			81,945		98,538		—		(64,254	)		116,229
Income tax expense			10,200		34,284		—		—			44,484

Net income (loss)		$	71,745	$	64,254	$	—	$	(64,254	)	$	71,745

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the nine months ended September 30, 2005

		EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiary			Eliminations			Consolidated
		(In thousands)
Revenues and other income:
	Oil and natural gas sales	$	22,323		$	109,146		$	—		$	—		$	131,469
	Derivative financial instruments		(56,708	)		(120,545	)		—			—			(177,253	)
	Other income (loss)		31,679			1,663			—			(26,295	)		7,047
	Equity in earnings of subsidiaries		(36,405	)		—			—			36,405			—

	Total revenues and other income		(39,111	)		(9,736	)		—			10,110			(38,737	)

Costs and expenses:
	Oil and natural gas production		6,783			15,198			—			(2	)		21,979
	Depreciation, depletion and amortization		3,881			20,609			—			—			24,490
	Accretion of discount on asset retirement obligations		232			380			—			—			612
	General and administrative		11,821			3,848			—			—			15,669
	Interest		26,428			26,369			—			(26,295	)		26,502

	Total costs and expenses		49,145			66,404			—			(26,297	)		89,252

Income (loss) before income taxes			(88,256	)		(76,140	)		—			36,407			(127,989	)
Income tax benefit			(14,275	)		(39,735	)		—			—			(54,010	)

Income (loss) from continuing operations			(73,981	)		(36,405	)		—			36,407			(73,979	)

Discontinued operations:
Loss from discontinued operations			—			—			(4,402	)		—			(4,402	)
Gain on sale of Addison Energy Inc.			175,717			—			—			—			175,717
Income tax expense (benefit)			49,762			—			(480	)		—			49,282

Net income (loss) from discontinued operations			125,955			—			(3,922	)		—			122,033

Net income (loss)		$	51,974		$	(36,405	)	$	(3,922	)	$	36,407		$	48,054

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the nine months ended September 30, 2006

		EXCO Resources		Guarantor subsidiaries		Non- guarantor subsidiary		Eliminations			Consolidated
		(In thousands)
Revenues and other income:
	Oil and natural gas sales	$	22,815	$	211,819	$	—	$	—		$	234,634
	Derivative financial instruments		46,965		128,803		—		—			175,768
	Other income (loss)		21,818		2,391		—		(20,637	)		3,572
	Equity in earnings of subsidiaries		135,686		—		—		(134,093	)		1,593

	Total revenues and other income		227,284		343,013		—		(154,730	)		415,567

Costs and expenses:
	Oil and natural gas production		7,489		34,453		—		—			41,942
	Depreciation, depletion and amortization		6,937		74,392		—		—			81,329
	Accretion of discount on asset retirement obligations		116		962		—		—			1,078
	General and administrative		14,006		6,822		—		—			20,828
	Interest		40,619		21,303		—		(20,637	)		41,285

	Total costs and expenses		69,167		137,932		—		(20,637	)		186,462

Income (loss) before income taxes			158,117		205,081		—		(134,093	)		229,105
Income tax expense			18,197		70,988		—		—			89,185

Net income (loss)		$	139,920	$	134,093	$	—	$	(134,093	)	$	139,920

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the nine months ended September 30, 2005

	EXCO Resources			Guarantor subsidiaries			Non-guarantor subsidiary			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by (used in) operating activities	$	(95,934	)	$	15,090		$	—		$	—	$	(80,844	)

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(4,545	)		(146,637	)		—			—		(151,182	)
Proceeds from disposition of property and equipment		9,961			36,049			—			—		46,010
Proceeds from sale of Addison Energy Inc., net of cash sold		453,798			—			(10,401	)		—		443,397
Proceeds from the sale of marketable securities		59			—			—			—		59
Net cash used in investing activities of discontinued operations		(442	)		—			—			—		(442	)

Net cash provided by (used in) investing activities		458,831			(110,588	)		(10,401	)		—		337,842

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—officers and employees		311			—			—			—		311
Net cash provided by financing activities of discontinued operations		59,601			—			—			—		59,601

Net cash used in financing activities		(47,035	)		—			—			—		(47,035	)

Net increase (decrease) in cash		315,862			(95,498	)		(10,401	)		—		209,963
Cash at beginning of period		8,535			7,472			10,401			—		26,408

Cash at end of period	$	324,397		$	(88,026	)	$	—		$	—	$	236,371

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the nine months ended September 30, 2006

	EXCO Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations			Consolidated
	(In thousands)
Operating Activities:
Net cash provided by (used in) operating activities	$	(1,566	)	$	174,460		$	—	$	—		$	172,894

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(228,252	)		(114,382	)		—		—			(342,634	)
Proceeds from disposition of property and equipment and other		3,802			811			—		—			4,613
Cash acquired in acquisition of TXOK Acquisition, Inc.		—			32,261			—		—			32,261
Payment to TXOK Acquisition, Inc. for preferred stock redemptions		(158,750	)		—			—		—			(158,750	)
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired		—			(61,776	)		—		—			(61,776	)

Net cash used in investing activities		(383,200	)		(143,086	)		—		—			(526,286	)

Financing Activities:
Proceeds from long-term debt		498,000			—			—		—			498,000
Payments on long-term debt		(952,751	)		(13,096	)		—		(2	)		(965,849	)
Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition		—			(38,098	)		—		—			(38,098	)
Proceeds from issuance of common stock, net of underwriters' commissions and initial public offering costs		656,598			—			—		—			656,598
Deferred financing costs and other		(1,116	)		(405	)		—		—			(1,521	)

Net cash provided by (used in) financing activities		200,731			(51,599	)		—		(2	)		149,130

Net decrease in cash		(184,035	)		(20,225	)		—		(2	)		(204,262	)
Cash at beginning of period		196,888			30,065			—		—			226,953

Cash at end of period	$	12,853		$	9,840		$	—	$	(2	)	$	22,691

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

This quarterly 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 derivative financial instrument activities; and
•: our plans and forecasts.

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

We use the words "may," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget" and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this quarterly report, including, but not limited to:

•: fluctuations in prices of oil and natural gas;
•: future capital requirements and availability of financing;
•: estimates of reserves;
•: 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;
•: 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;
•: 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;
•: fluctuations in interest rates; and
•: our ability to effectively integrate companies and properties that we acquire.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2005.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties 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 have completed additional property and corporate acquisitions in excess of $339.5 million through the nine months ended September 30, 2006. On October 2, 2006, we completed the acquisition of Winchester Energy Company, Ltd., or Winchester, for $1.1 billion in cash after closing adjustments, subject to additional post-closing price adjustments. This 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.

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. The price of oil has shown similar volatility. In 2005, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas increased by approximately 38% and 40%, respectively. For the nine months ended September 30, 2006, our average realized price for natural gas (before the

impact of derivative financial instruments) has declined to $7.03 per Mcf from an average $8.59 per Mcf for the year ended December 31, 2005. The historically high commodity price environment in 2004 through 2006 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. During the quarter ended September 30, 2006, the industry experienced a significant decrease in the price for natural gas. We cannot predict the impact this decline in pricing 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, capital budget and employs the use of derivative financial instruments to lessen the impact of fluctuating prices for oil and natural gas.

At the beginning of 2006, we budgeted approximately $159.1 million, including TXOK capital projects, for our drilling, exploitation and operational expenditures. We also budgeted approximately $7.0 million in 2006 for our additional corporate and acquisition-related expenditures and approximately $1.6 million for information technology expenditures. We do not budget for property acquisitions as these transactions are opportunistic in nature. Our future earnings and cash flows are dependent upon our ability to manage our overall cost structure to a level that allows for profitable production. As a result of acquisitions closed during the nine months ended September 30, 2006, we expect our 2006 capital budget for drilling and exploitation to increase by approximately $40.0 million. Winchester's capital budget for the fourth quarter of 2006 is expected to increase our drilling, exploitation and operational budget by an additional $34.8 million.

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 additional wells and performing exploitation projects in existing wells to develop and identify additional reserves and by acquisitions. Our future growth will depend upon our ability to continue to add oil and natural gas reserves in excess of production at a reasonable cost. We will maintain our focus on the costs of adding reserves through development drilling, exploitation projects 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 initial public offering, or IPO, in February 2006, we amended our credit agreement with our banking syndicate. Our credit agreement provides for a borrowing base of $750.0 million with a current aggregate commitment of $500.0 million. As a result of our acquisition of Winchester on October 2, 2006 and the contribution of our assets in East Texas and Louisiana to EXCO Partners in exchange for $150.0 million of cash from EXCO Partners, our credit agreement was amended to reflect the contribution of those assets. This amendment reduced the borrowing base of our credit facility to $600.0 million with an aggregate commitment of $400.0 million. We believe we will have adequate unused borrowing capacity under our credit agreement, in addition to cash flow from operations, to fund capital development and working capital needs for the next 12 months. Funding for future acquisitions may require additional sources of financing, which may not be available.

On February 10, 2005, 1143928 Alberta Ltd., a wholly-owned subsidiary of NAL Oil & Gas Trust, purchased all of the issued and outstanding shares of common stock of Addison and two intercompany notes that Addison owed to one of our subsidiaries, Taurus Acquisition, Inc. (now known as ROJO Pipeline, Inc., or ROJO). The aggregate purchase price was Cdn. $551.3 million ($443.3 million) after adjustments as specified in the purchase agreement.

On August 12, 2005, our management formed a new entity, Holdings II, to consummate a purchase of all of the shares of capital stock of EXCO Holdings, our parent company at that time, hereinafter referred to as the Equity Buyout. On October 3, 2005, Holdings II purchased 100% of the

outstanding equity of EXCO Holdings for an aggregate purchase price of approximately $699.3 million, which resulted in a change of control at EXCO Holdings and a change in its board of directors. To fund this purchase, Holdings II incurred $350.0 million in indebtedness, including $0.7 million for working capital, under an interim bank loan and raised $183.1 million of equity financing from institutional and other investors. Current management and other stockholders of EXCO Holdings, who had an option to take cash or equity in Holdings II, exchanged EXCO Holdings capital stock for $166.9 million of Holdings II common stock. Promptly following the completion of these transactions, Holdings II merged with and into EXCO Holdings. This transaction resulted in a change in the valuation of our assets.

On September 27, 2005, TXOK, a wholly-owned subsidiary of Holdings II, our former parent company, acquired all of the issued and outstanding equity interests of ONEOK Energy for a purchase price of $633.0 million after contractual adjustments. On February 14, 2006, upon closing of our IPO, we acquired TXOK by redeeming its preferred stock and assuming its debt. The acquisition was accounted for using the purchase method of accounting in accordance with SFAS No. 141, "Accounting for Business Combinations." The purchase price was $665.1 million. The TXOK acquisition significantly increased our multi-year inventory of development drilling locations and exploitation projects, and strengthened our position in the East Texas and Oklahoma areas.

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

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

•: $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 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. EXCO Resources also became a guarantor under the TXOK credit facility and TXOK likewise became a guarantor under EXCO's credit agreement.

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 us of approximately $44.6 million. The net proceeds were used to reduce outstanding indebtedness under EXCO's credit agreement.

Critical accounting policies

We consider accounting policies related to estimates of Proved Reserves, accounting for derivatives, assessments of functional currencies, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as critical accounting policies.

As a result of our increased activities in acquisitions, such as TXOK, PGMT and the Winchester acquisition, we consider business combinations and purchase accounting as a significant accounting policy. We follow SFAS No. 141, to account for these transactions. The policy requires significant estimates to be made by management using information available at the time. Since the estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available. These policies are summarized in Management's Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2005.

Recent accounting pronouncements

In July 2006, the Financial Accounting Standards Board 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 Standard No. 109, "Accounting for Income Taxes", or SFAS No. 109. 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 are currently assessing the impact, if any, of FIN 48 on our financial statements.

In September 2006, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 157, "Fair Value Measurements," or SFAS No. 157 which defines fair value

and provides guidance for using fair value to measure assets and liabilities. SFAS No. 157 clarifies the principle that fair value should be based on the assumptions that market participants would use when pricing an asset or a liability and establishes a fair value hierarchy that prioritizes information used to develop those assumptions. Under SFAS No. 157, fair value measurements are to be separately disclosed by levels (i.e. levels 1, 2 and 3, as defined) within the fair value hierarchy and companies are required to provide enhanced disclosure regarding fair value amounts in the level 3 category (recurring fair value measurements using significant observable inputs), and a reconciliation of beginning and ending balances separately for each category of assets and liabilities. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of SFAS No. 157, if any, on our financial position, results of operations or cash flows.

Our results of operations

The following is a discussion of our financial condition and results of operations for the three and nine months ended September 30, 2005 and 2006.

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

•: the sale of Addison on February 10, 2005;
•: 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;
•: the acquisition of TXOK, which became a consolidated subsidiary on February 14, 2006;
•: the acquisition of PGMT, which became a consolidated subsidiary on April 28, 2006;
•: other property acquisitions and dispositions;
•: the IPO that closed on February 14, 2006;
•: fluctuations due to the use of mark-to-market accounting for our derivative financial instrument activities; and
•: significant fluctuations for oil and natural gas prices which impact our oil and natural gas reserves, revenues, our derivative financial instruments and the carrying costs of our oil and natural gas properties.

General

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

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

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

Marketing arrangements

We produce oil, natural gas and NGLs. We do not refine or process the oil we produce.

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

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

NGLs are not a significant component of our total revenues. When we do sell NGLs, they are sold under both short-term and long-term contracts. We sell the NGLs to refiners and processors in the vicinity of our producing properties. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Typically, the prices we receive for NGLs are based on the Oil Price Information Service (OPIS) index, less transportation and fractionating fees.

We may not be able to market all the oil, natural gas or NGLs we produce. If our oil, natural gas or NGLs can be marketed, we may not be able to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil, natural gas and NGLs contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

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

Revenues and production

The following tables present our oil and natural gas revenues (excluding the impact of derivative financial instruments), production and average unit sales price for the three and nine months ended September 30, 2005 and 2006. The tables also show the changes in these amounts between periods.

		Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
		2005		2006		2005-2006			2005		2006		2005-2006
		(Unaudited, in thousands)
Oil and natural gas revenues before derivative financial instruments:
Oil revenues:
U.S. (excluding Appalachia)		$	5,336	$	14,312	$	8,976		$	15,000	$	34,802	$	19,802
Appalachia			1,945		2,125		180			4,388		5,463		1,075

	Total	$	7,281	$	16,437	$	9,156		$	19,388	$	40,265	$	20,877

Natural gas revenues:
U.S. (excluding Appalachia)		$	15,592	$	41,909	$	26,317		$	39,642	$	108,334	$	68,692
Appalachia			28,898		26,544		(2,354	)		72,439		86,035		13,596

	Total	$	44,490	$	68,453	$	23,963		$	112,081	$	194,369	$	82,288

Total oil and natural gas revenues:
U.S. (excluding Appalachia)		$	20,928	$	56,221	$	35,293		$	54,642	$	143,136	$	88,494
Appalachia			30,843		28,669		(2,174	)		76,827		91,498		14,671

	Total	$	51,771	$	84,890	$	33,119		$	131,469	$	234,634	$	103,165

		Three months ended September 30,		Quarter to quarter change		Nine months ended September 30,		Period to period change
		2005	2006	2005-2006		2005	2006	2005-2006
		(Unaudited)
Production:
Oil (Mbbls):
U.S. (excluding Appalachia)		89	210	121		288	526	238
Appalachia		33	31	(2	)	84	85	1

	Total	122	241	119		372	611	239

Natural gas (Mmcf):
U.S. (excluding Appalachia)		2,133	6,764	4,631		6,404	17,157	10,753
Appalachia		2,982	3,696	714		8,906	10,480	1,574

	Total	5,115	10,460	5,345		15,310	27,637	12,327

Total production (Mmcfe):
U.S. (excluding Appalachia)		2,667	8,024	5,357		8,132	20,313	12,181
Appalachia		3,180	3,882	702		9,410	10,990	1,580

	Total	5,847	11,906	6,059		17,542	31,303	13,761

			Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
			2005		2006		2005-2006			2005		2006		2005-2006
			(Unaudited)
Average sales price (excluding derivative financial instrument activities):
Oil (per Bbl):
	U.S. (excluding Appalachia)		$	59.96	$	68.15	$	8.19		$	52.08	$	66.16	$	14.08
	Appalachia			58.94		68.55		9.61			52.24		64.27		12.03
	Total			59.68		68.20		8.52			52.12		65.90		13.78
Natural gas (per Mcf):
	U.S. (excluding Appalachia)		$	7.31	$	6.20	$	(1.11	)	$	6.19	$	6.31	$	0.12
	Appalachia			9.69		7.18		(2.51	)		8.13		8.21		0.08
		Total		8.70		6.54		(2.16	)		7.32		7.03		(0.29	)
Total oil and natural gas revenues (per Mcfe):
	U.S. (excluding Appalachia)		$	7.85	$	7.01	$	(0.84	)	$	6.72	$	7.05	$	0.33
	Appalachia			9.70		7.39		(2.31	)		8.16		8.33		0.17
		Total		8.85		7.13		(1.72	)		7.49		7.50		0.01

Our revenues from the sale of oil and natural gas, before the impacts of derivative financial instruments, for the three and nine months ended September 30, 2006 increased by $33.1 million and $103.2 million, respectively, or 64.0% and 78.5%, respectively, over the three and nine months ended September 30, 2005. For the three months ended September 30, 2006, compared with the three months ended September 30, 2005, higher production volumes increased total revenues $43.2 million while lower equivalent Mcf prices decreased revenues by $10.1 million. For the nine months ended September 30, 2006 compared with the same prior year period, higher volumes increased revenues by $103.2 million and higher prices per Mmcfe resulted in a de minimus increase in revenues. The increases in the September 30, 2006 production volumes are due primarily to:

•: the February 14, 2006 acquisition of TXOK which contributed 11.1 Bcfe to the nine months ended September 30, 2006;
•: new acquisitions in West Texas and East Texas, including new production from wells drilled since acquired, which added 0.4 Bcfe;
•: impact of North Coast property acquisitions completed in the third quarter of 2005 and the PGMT acquisition which closed on April 28, 2006; and
•: the addition of 266 new wells drilled and completed since September 30, 2005.

Partially offsetting the higher volumes and prices was a general decline in production from our existing oil producing properties.

In our U.S. (excluding Appalachia) business segment, our oil and natural gas production volumes for the nine months ended September 30, 2006 increased 12.2 Bcfe from the nine month ended September 30, 2005. The increases are attributable to 11.1 Bcfe of TXOK production, increases of approximately 1.0 Bcfe from development drilling and acquisitions in our East Texas locations and a 1.1 Bcfe increase in volumes from our April 2006 acquisition and subsequent development drilling in West Texas. These increases were partially offset by normal production declines.

In our Appalachia segment, oil and natural gas production volumes for the nine months ended September 30, 2006, increased approximately 1,580 Mmcfe from the comparable period last year. This increase is the result of additional natural gas production of 1,363 Mmcfe from producing property acquisitions which closed during the third quarter of 2005, development drilling since the date of acquisition and the addition of 690 Mmcfe from the acquisition of PGMT. These volumes were partially offset by natural gas production curtailments imposed upon us by natural gas pipelines and production

declines from our Knox trend wells. For the three months ended September 30, 2006, we experienced pipeline curtailments of approximately 3.0 Mmcf per day in Appalachia. During the fourth quarter, we expect some curtailment to continue. However, the curtailed volumes are expected to decline during the late fall and early winter.

The following tables present our derivative financial instrument activities and our other income for the three and nine months ended September 30, 2005 and 2006. The tables also show changes in these amounts between periods.

		Three months ended September 30,					Quarter to quarter change			Nine months ended September 30,					Period to period change
		2005			2006		2005-2006			2005			2006		2005-2006
		(Unaudited, in thousands)
Derivative financial instrument activities:
Cash settlements on derivative financial instruments		$	(6,167	)	$	8,722	$	14,889		$	(62,843	)	$	11,150	$	73,993
Non-cash change in fair value of derivative financial instruments		$	(101,338	)		91,039		192,377			(114,410	)		164,618		279,028

	Total derivative financial instrument activities	$	(107,505	)	$	99,761	$	207,266		$	(177,253	)	$	175,768	$	353,021

Other income, net:
Gain from foreign currency transactions		$	436		$	—	$	(436	)	$	516		$	—	$	(516	)
Interest, dividend and other, net			2,971			678		(2,293	)		6,531			3,572		(2,959	)

	Total other income, net	$	3,407		$	678	$	(2,729	)	$	7,047		$	3,572	$	(3,475	)

Our derivative financial instrument activities increased revenue by $99.8 million and $175.8 million, respectively, during the three and nine months ended September 30, 2006, and include payments received totaling $8.7 million and $11.2 million, respectively, to settle existing contracts for the three and nine months ended September 30, 2006. The nine months ended September 30, 2005 include payments made by EXCO totaling $52.6 million to terminate certain contracts. In January and March 2005, we entered into new derivative financial instrument contracts for increased volumes at higher underlying product prices. The remaining $10.2 million of cash settlements of derivative financial instruments during the nine months ended September 30, 2005 are a result of the significant increases in the NYMEX oil and natural gas prices that are used to settle our contracts over the oil and natural gas prices of our contracts.

For the three months ended September 30, 2005 and 2006, we recognized a decrease in revenue of $101.3 million and an increase in revenue of $91.0 million, respectively, from the change in the fair value of our derivative financial instruments. We expect that our revenues will continue to be significantly impacted in future periods by changes in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices and the volume of future oil and natural gas sales covered under our derivative financial instrument program. For the remainder of 2006 and calendar 2007, approximately two-thirds of our expected production is subject to derivative contracts.

Our other income decreased to $0.7 million for the three months ended September 30, 2006 from $3.4 million in the previous year's quarter. The decrease is primarily due to lower interest income in the three months ended September 30, 2006 as a result of reduced cash balances as compared to the three months ended September 30, 2005.

Other income for the nine months ended September 30, 2006 was $3.6 million compared with $7.0 million during the prior year period. The decrease reflects lower interest income of $3.7 million,

again due primarily to lower cash balances, which is partially offset by increased transportation revenue of $0.7 million.

Costs and expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production costs per Mcfe for the three and nine months ended September 30, 2005 and 2006. The 2006 data presented for the U.S. (excluding Appalachia) segment includes costs and expenses since the February 14, 2006 acquisition of TXOK, which became a consolidated subsidiary on that date. The tables also show the changes in these amounts between the periods.

		Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
		2005		2006		2005-2006			2005		2006		2005-2006
		(Unaudited, in thousands)
Oil and natural gas production costs:
Oil and natural gas operating costs:
U.S. (excluding Appalachia)		$	2,098	$	6,033	$	3,935		$	6,694	$	16,212	$	9,518
Appalachia			2,782		4,459		1,677			7,780		11,566		3,786

	Total	$	4,880	$	10,492	$	5,612		$	14,474	$	27,778	$	13,304

Production and ad valorem taxes:
U.S. (excluding Appalachia)		$	1,633	$	4,237	$	2,604		$	4,635	$	10,988	$	6,353
Appalachia			1,083		954		(129	)		2,870		3,176		306

	Total	$	2,716	$	5,191	$	2,475		$	7,505	$	14,164	$	6,659

Total oil and natural gas production costs:
U.S. (excluding Appalachia)		$	3,731	$	10,270	$	6,539		$	11,329	$	27,200	$	15,871
Appalachia			3,865		5,413		1,548			10,650		14,742		4,092

	Total	$	7,596	$	15,683	$	8,087		$	21,979	$	41,942	$	19,963

		Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
		2005		2006		2005-2006			2005		2006		2005-2006
		(Unaudited)
Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs:
U.S. (excluding Appalachia)		$	0.79	$	0.75	$	(0.04	)	$	0.82	$	0.80	$	(0.02	)
Appalachia			0.87		1.15		0.28			0.83		1.05		0.22
	Total		0.83		0.88		0.05			0.83		0.89		0.06
Production and ad valorem taxes:
U.S. (excluding Appalachia)		$	0.61	$	0.53	$	(0.08	)	$	0.57	$	0.54	$	(0.03	)
Appalachia			0.34		0.25		(0.09	)		0.30		0.29		(0.01	)
	Total		0.46		0.44		(0.02	)		0.43		0.45		0.02
Total oil and natural gas production costs:
U.S. (excluding Appalachia)		$	1.40	$	1.28	$	(0.12	)	$	1.39	$	1.34	$	(0.05	)
Appalachia			1.22		1.39		0.17			1.13		1.34		0.21
	Total		1.30		1.32		0.02			1.25		1.34		0.09

Our oil and natural gas production costs for the three and nine months ended September 30, 2006 increased $5.6 million and $13.3 million, respectively, or 115.0% and 91.9%, respectively, from the same periods in 2005. The increase in oil and natural gas operating costs was primarily attributable to:

•: the February 14, 2006 acquisition of TXOK which added $3.1 million and $8.0 million of operating costs for the three and nine months ended September 30, 2006, respectively;
•: impact of North Coast property acquisitions completed in the third quarter of 2005 and PGMT in 2006;
•: an increase in salaries and related benefits due to an increase in the number of field employees;
•: a general increase in the cost of goods and services used in our oil and natural gas operations during 2006; and
•: new wells added through our acquisition, development and exploitation capital program.

The oil and natural gas production cost per unit for the U.S. (excluding Appalachia) segment decreased from $0.79 and $0.82, respectively, per Mcfe for the three and nine months ended September 30, 2005 to $0.75 and $0.80, respectively, per Mcfe, or 5.1% and 2.4%, respectively, for the three and nine months ended September 30, 2006. The oil and natural gas production costs per unit for Appalachia increased from $0.87 to $1.15 for the three months ended September 30, 2005 and 2006, respectively. For the nine months ended September 30, 2006, the oil and natural gas production costs per Mcfe in the Appalachia segment increased to $1.05 per Mcfe from $0.83 per Mcfe for the nine months ended September 30, 2005, an increase of 26.5%. The per unit increases in the Appalachia business segment are due primarily to higher production costs from properties acquired from PGMT.

Production and ad valorem taxes for the three and nine months ended September 30, 2006 increased by $2.5 million and $6.7 million, respectively, or 91.1% and 88.7%, respectively, over the three and nine months ended September 30, 2005. The increases are due primarily to the production and ad valorem taxes attributable to the TXOK acquisition, which were $2.5 million and $5.6 million for the three and nine months ended September 30, 2006, respectively. Production taxes are set by the state and local governments and vary as to the tax rate and the value to which that rate is applied. Further, ad valorem taxes in Texas and other states are based partially on the value of oil and natural gas reserves, which have increased significantly in 2006 as compared with 2005 due to higher oil and natural gas prices. These taxes are generally based upon the price received for production.

Our depreciation, depletion and amortization costs for the three and nine months ended September 30, 2006 increased by $22.6 million and $56.8 million, or 257.3% and 232.1%, respectively, from the same periods in 2005. The primary reasons for these increases were from increases in oil and natural gas sales volumes and an increase in the per unit depletion rate. Oil and natural gas volumes increased 103.6% and 78.4% for the three and nine months ended September 30, 2006, respectively. The per unit depletion rate increased from $1.50 per Mcfe for the three months ended September 30, 2005 to $2.63 per Mcfe for the three months ended September 30, 2006 and from $1.40 per Mcfe for the nine months ended September 30, 2005 to $2.60 per Mcfe for the nine months ended September 30, 2006, respectively. The higher rate for the nine months ended September 30, 2006 reflects the impact of the stepped-up basis for our oil and natural gas properties from the Equity Buyout and the February 14, 2006 acquisition of TXOK. The nine months ended September 30, 2005 depreciation, depletion and amortization is based on lower predecessor basis for our properties, resulting in lower per unit rates.

The following table presents our general and administrative costs for the three and nine months ended September 30, 2005 and 2006. The table also shows the changes in these amounts between periods.

		Three months ended September 30,						Quarter to quarter change
		2005			2006			2005-2006
		(unaudited, in thousands)
General and administrative costs:
Gross general and administrative expense		$	5,267		$	11,228		$	5,961
Operator overhead charges			(403	)		(2,015	)		(1,612	)
Capitalized acquisition and exploitation charges			(453	)		(824	)		(371	)

	Net general and administrative expense	$	4,411		$	8,389		$	3,978

General and administrative expense per Mcfe		$	0.75		$	0.70		$	(0.05	)

		Nine months ended September 30,						Period to period change
		2005			2006			2005-2006
		(unaudited, in thousands)
General and administrative costs:
Gross general and administrative expense		$	18,140		$	28,222		$	10,082
Operator overhead charges			(1,284	)		(5,198	)		(3,914	)
Capitalized acquisition and exploitation charges			(1,187	)		(2,196	)		(1,009	)

	Net general and administrative expense	$	15,669		$	20,828		$	5,159

General and administrative expense per Mcfe		$	0.89		$	0.67		$	(0.22	)

Our general and administrative costs for the three and nine months ended September 30, 2006 increased by $4.0 million, or 90.1% and $5.2 million, or 32.9%, respectively, over the same periods in 2005. The increases for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005 were due primarily to:

•: increased personnel costs of $2.7 million from increased level of acquisition activity and the consolidation of TXOK and PGMT;
•: increased professional services of $1.6 million and contract labor costs reflecting work related to the implementation of Sarbanes-Oxley, expansion of our internal audit function, legal, external audit costs and other professional services related to the PGMT and Winchester acquisitions;
•: expensed stock-based compensation costs of $2.4 million;
•: increased occupancy costs of $1.3 million resulting from expansion of corporate facilities; and
•: increased franchise taxes and other increases attributable to our IPO of $0.5 million.

Partially offsetting the above increases in general and administrative costs were:

•: increased operator overhead recoveries of $3.9 million primarily resulting from the acquisition of TXOK.

The following table presents our interest expense for the three and nine months ended September 30, 2005 and 2006. The table also shows the changes in these amounts between periods.

		Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
		2005		2006		2005-2006			2005		2006		2005-2006
		(Unaudited, in thousands)
Interest expense:
7¹/4% senior notes due 2011		$	8,050	$	7,312	$	(738	)	$	24,158	$	21,973	$	(2,185	)
Credit agreement			94		5,906		5,812			436		11,367		10,931
Amortization and write-off of deferred financing costs			1,042		64		(978	)		1,908		6,729		4,821
Interim bank loan			—		—		—			—		1,216		1,216

	Total interest expense	$	9,186	$	13,282	$	4,096		$	26,502	$	41,285	$	14,783

Our interest expense for the three months ended September 30, 2006 increased $4.1 million from the same period in 2005. The increase is primarily due to interest expense associated with borrowings from our credit facility to finance property and corporate acquisitions. Interest expense for the nine months ended September 30, 2006 increased by $14.8 million from the same period in 2005. This increase was primarily due to borrowings under our credit facility, $1.2 million of interest expense attributable to an interim bank loan used to fund the Equity Buyout and $6.7 million of deferred loan costs written off as a result of the early pay off of the interim bank loan. The interim bank loan was paid in full on February 14, 2006. Our long-term debt balance under our credit agreement was $404.0 million at September 30, 2006 compared to $1,000 at September 30, 2005.

Income taxes

Our effective tax rate on income from continuing operations for the three and nine months ended September 30, 2006 was 38.3% and 38.9%, respectively. Our effective tax rate on losses from continuing operations for the three months ended September 30, 2005 approximates 39.7%, including a one time adjustment relating to foreign taxes from the sale of our Canadian subsidiary in the amount of $2.1 million. A substantial portion of our stock-based compensation included in our quarter ended September 30, 2006 results are in the form of incentive stock options which are not deductible for tax purposes until a disqualifying event occurs. The non-deductible portion of stock compensation increased our effective rate by approximately 0.2% during the three months ended September 30, 2006. 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 have recorded $0.8 million, the effect of the change in the tax rate on our existing deferred tax balances in the prior quarter.

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 before contractual adjustments was Cdn. $553.3 million (U.S. $445.1 million) less the payment of the outstanding balance under Addison's credit facility of Cdn. $90.1 million (U.S. $72.1 million) and other adjustments as specified in the purchase agreement. We have recognized a gain from the sale of Addison of U.S. $175.7 million before income tax expense of U.S. $49.3 million related to the gain.

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 nine months ended September 30, 2005 includes:

•: approximately $3.8 million in losses from derivative financial instrument 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 program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash 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. Our credit agreement, as amended, is a $1.25 billion facility with a $600.0 million borrowing base and a $400.0 million aggregate commitment. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreement is subject to restrictions imposed by our lenders. In addition, our indenture governing our senior notes contains restrictions on incurring indebtedness and pledging our assets.

On February 14, 2006, EXCO Resources completed its IPO of 50,000,000 shares of its common stock for aggregate net proceeds to EXCO Resources of $617.5 million after underwriters' discount. The net proceeds from the IPO, together with cash on hand 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 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 $172.9 million for the nine months ended September 30, 2006, which reflects the impact of the TXOK acquisition and collections of income tax refunds from Canada attributable to our sale of Addison. At September 30, 2006, our cash and cash equivalents balance was $22.7 million, a decrease of $204.3 million from December 31, 2005 primarily as a result of the repayment of indebtedness incurred in connection with the Equity Buyout, the acquisition of TXOK and our oil and natural gas acquisitions.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the nine months ended September 30, 2005 and 2006. The capital expenditures for the nine months ended September 30, 2006 include capital expenditures of TXOK and PGMT during the February 14, 2006 to September 30, 2006 period.

		Nine months ended September 30,
		2005		2006
		(Unaudited, in thousands)
Capital expenditures:
Property acquisitions		$	102,083	$	215,438
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
Lease purchases			—		2,926
Development capital expenditures			39,900		120,173
Other			5,884		6,735

	Total capital expenditures	$	147,867	$	533,537

During the nine months ended September 30, 2005, we completed seven oil and natural gas property acquisitions. Estimated total Proved Reserves at the date of acquisition, net to our interest, included approximately 60.4 Bcfe of natural gas. The total purchase price for the acquisitions was approximately $102.1 million. The acquisitions were funded with borrowings from our U.S. credit agreement and surplus cash.

At the beginning of 2006, we budgeted approximately $159.1 million, excluding acquisitions, for our development, exploitation and exploration activities in the United States, including TXOK capital projects. As of September 30, 2006, we were contractually obligated to spend $12.1 million for our development and exploitation activities for the remainder of 2006. As a result of acquisitions closed in April and May 2006, we expect our capital budget for drilling and exploitation to increase by more than $40.0 million in 2006.

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 $137.3 million, which was funded with indebtedness drawn under our credit agreement.

On April 28, 2006, we closed an acquisition and acquired 100% of the common stock of Power Gas Marketing & Transmission, Inc., or PGMT, for a net purchase price of $113.0 million (See "Notes to Condensed Consolidated Financial Statements—Note 15. Acquisitions and dispositions"). 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 our credit facility, 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 our 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 $49.1 million.

On October 2, 2006, we closed our acquisition of Winchester and its affiliated entities from Progress Energy, Inc. for $1.1 billion in cash, net of preliminary purchase price adjustments. The assets include 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, 16 inch pipeline. The acquisition was financed with a $750 million term loan facility and a new 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 our credit agreement. Concurrent with the closing of the purchase of Winchester, we contributed to EXCO Partners Operating Partnership, L.P., or EPOP, a wholly-owned subsidiary of EXCO Partners, all of our East Texas properties, with an estimated value of approximately $425.0 million, and related indebtedness of approximately $150.0 million. EPOP will not be a guarantor of our debt obligations nor will we guarantee the debt of EPOP.

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 during the remainder of 2006.

We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreement are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes, 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 7¹/4% senior notes, or senior notes, due January 15, 2011 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 7¹/4% senior notes due January 15, 2011 pursuant to Rule 144A at a price of 103.3% of the principal amount having the same terms and governed by the same indenture as the senior notes issued on January 20, 2004. Of the total proceeds of $103.3 million, approximately $98.8 million was used to repay substantially all of our outstanding indebtedness under the Canadian credit agreement, approximately $1.2 million was used for fees and expenses associated with the offering, with the remainder, approximately $3.3 million, available for general working capital purposes.

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 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.

Credit agreement

On March 17, 2006, EXCO Resources, Inc. and certain of its subsidiaries entered into an amended and restated credit agreement, or 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 the credit agreement maturity date to December 31, 2010. The borrowing base will be redetermined each November 1 and May 1, beginning November 1, 2006. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. Financial covenants under the amended credit agreement require that we:

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

Borrowings under our credit agreement were collateralized by a first lien mortgage providing a security interest in 90% of our oil and natural gas properties including TXOK and North Coast Energy, Inc. and their respective subsidiaries. Our borrowings were 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.

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 September 30, 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 September 30, 2006, we had $1,000 and $404.0 million respectively, of outstanding indebtedness under our credit agreement. As of September 30, 2006, we had $96.0 million available under our credit agreement based on the current aggregate commitment of $500.0 million.

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, the general partner of EXCO Partners and the partners of the general partner, all of which are subsidiaries of EXCO. are unrestricted subsidiaries under the 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 credit agreement and none of EXCO Partners or the other unrestricted subsidiaries have guaranteed the 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. 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 October 27, 2006, $254.0 million of indebtedness was outstanding under our credit agreement and we had $346.0 million of availability under our credit agreement. Our consolidated debt as of October 30, 2006, which includes debt incurred to acquire Winchester, our credit facility and 7¹/4% senior notes totals $2.0 billion. The debt incurred in the Winchester acquisition is more fully described below.

EXCO Partners Revolving Credit Facility

To finance the Winchester merger and the $150.0 million payment to EXCO Resources for its East Texas assets, EXCO Partners' wholly-owned subsidiary, EXCO Partners Operating Partnership, LP ("EPOP"), entered into a Senior Revolving Credit Agreement ("Revolving Credit Facility"), dated October 2, 2006, with a group of lenders lead by JPMorgan Chase Bank, N.A. The 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 borrowing base must be conforming by April 1, 2007. The 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. 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 ratio of (A) Consolidated Funded Indebtedness (as defined) as of the end of a fiscal quarter to (B) Consolidated EBITDAX (as defined) for such quarter, may not be greater than (i) 5.00 to 1.00 as of the end of December 31, 2006 (Consolidated EBITDAX for such quarter to be multiplied by four), (ii) 4.00 to 1.00 for the first or second quarter of 2007 (Consolidated EBITDAX calculated using a defined trailing period multiplied by a fraction) or (iii) 4.00 to 1.00 for any quarter ending on or after September 30, 2007 (with Consolidated EBITDAX calculated using the trailing four quarter period ending on such date). EPOP will not permit its ratio of Consolidated EBITDAX to Consolidated Interest Expenses (as defined) to be less than 2.50 to 1.00 for specified measurement periods. Finally, EPOP will not permit its ratio of net present value (calculated pursuant to the terms of the Revolving Credit Facility) to Consolidated Funding Indebtedness (as defined) to be less than (i) 1.15 to 1.00 determined as of December 31, 2006 or (ii)1.25 to 1.00 determined as of each succeeding June 30 and December 31. The Revolving Credit Facility contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The 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 Revolving Credit Facility. To the extent usage exceeds the

initial conforming borrowing base, the 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. The Revolving Credit Facility contains a pricing grid based on availability. Finally, as a condition precedent to the funding of the 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 is 7.16% per annum.

EXCO Partners Senior Term Credit Agreement

In connection with the Winchester merger and the EXCO Resources asset contribution, EPOP entered into a 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 Senior Term Credit Agreement is secured by a second priority lien on all of the properties securing the Revolving Credit Facility, including 100% of the stock of subsidiaries, and is guaranteed by all existing and future subsidiaries. Financial covenants governing the Senior Term Credit Agreement include the same net present value ratio contained in the Revolving Credit Facility, a leverage ratio computed similarly to the covenant contained in the Revolving Credit Facility that cannot exceed 5.50 to 1.00 for any stated period, and an interest coverage ratio that cannot be less than 2.00 to 1.00 for any applicable period. In addition, EPOP cannot make Capital Expenditures (as defined) exceeding $125.0 million in any fiscal year. The Senior Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The 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 Senior Term Credit Agreement matures five years from the closing date, amortizes at 1% per year, with a bullet payment at maturity. Upon an initial public offering by EXCO Partners, EPOP shall prepay the principal outstanding (plus accrued interest) under the Senior Term Credit Agreement at par plus the 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 Senior Term Credit Agreement) toward prepayment at par of the 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 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

the 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 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 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 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 Senior Term Credit Agreement.

Derivative financial instruments

We may 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 agreement. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. During the nine months ended September 30, 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 September 30, 2006, we had contracts in place for the volumes and prices shown in the table below, which includes contracts we entered into or assumed since September 30, 2006, including Winchester.

	Swaps
	NYMEX gas volume— Mmbtus	Weighted average contract price per Mmbtu		Basis protection volume— Mmbtus	Weighted average differential to NYMEX			NYMEX oil volume— Bbls	Weighted average contract price per Bbl
	(in thousands, except average contract prices)
Q4 2006	9,429	$	8.51	1,380	$	(0.32	)	173	$	71.02
2007	47,790		8.73	—		—		734		69.53
2008	43,140		8.62	—		—		327		62.67
2009	25,705		8.01	—		—		120		60.80
2010	6,985		6.63	—		—		108		59.85
2011	1,825		4.51	—		—		—		—
2012	1,830		4.51	—		—		—		—
2013	1,825		4.51	—		—		—		—

	Floor						Ceiling
	NYMEX gas volume— Mmbtus	Weighted average contract price per Mmbtu		Oil volume— Bbls	Weighted average contract price per Bbl		NYMEX gas volume— Mmbtus	Weighted average contract price per Mmbtu		Oil volume— Bbls	Weighted average contract price per Bbl
	(in thousands, except average contract prices)
Q4 2006	2,640	$	6.26	27	$	50.35	2,640	$	9.48	27	$	60.00

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at September 30, 2006:

	Less than one year			One to three years			Three to five years		More than five years		Total
	(in thousands)
Contractual obligations:
7¹/4% senior notes due 2011	$	—		$	—		$	444,720	$	—	$	444,720
Revolving credit agreement		—			—			404,000		—		404,000
Operating leases		4,345			7,615			2,739		4,691		19,390
Derivative financial instruments		(20,073	)		(36,033	)		10,707		10,779		(34,620	)
Drilling/work commitments		25,410			3,348			—		—		28,758

Total contractual cash obligations	$	9,682		$	(25,070	)	$	862,166	$	15,470	$	862,248

On October 2, 2006, our consolidated debt increased by $1.1 billion when we acquired Winchester.

Legal proceedings

payment of royalties. In a case styledThe 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 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 theTawney case. Plaintiffs are seeking common law and statutory compensatory and punitive damages, interest and costs and other remedies. The Company intends to vigorously defend this action. Because this action is in a very preliminary stage, the ultimate outcome of this litigation cannot be determined at this time. However, management does not expect the ultimate outcome of the lawsuit to have a material effect on the financial position, results of operations or cash flows of EXCO Resources.

Item 3. Quantitative and qualitative disclosures 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 derivative financial instrument activities as of September 30, 2006.

Natural gas:		Volume Mmbtus/bbls	Weighted average strike price		Weighted average differential to NYMEX			Fair value at September 30, 2006
		(in thousands, except prices)
Swaps:
	Remainder 2006	7,514	$	8.41				$	18,860
	2007	29,790		8.52					24,731
	2008	25,140		8.50					12,079
	2009	7,705		7.14					(4,120	)
	2010	6,985		6.63					(5,380	)
	2011	1,825		4.51					(4,169	)
	2012	1,830		4.51					(3,564	)
	2013	1,825		4.51					(3,046	)

		82,614

Basis Swaps:
	Remainder 2006	1,380			$	(0.32	)		210

Total natural gas									35,601

Oil:
Swaps:
	Remainder 2006	173		71.02					1,140
	2007	734		69.52					1,055
	2008	327		62.67					(1,832	)
	2009	120		60.80					(689	)
	2010	108		59.85					(518	)

		1,462

Floor:
	Remainder 2006	27		50.35					1

Ceiling:
	Remainder 2006	27		60.00					(138	)

Total oil									(981	)

Total oil and natural gas								$	34,620

At September 30, 2006, the average forward NYMEX oil prices per Bbl for the remainder of 2006 was $64.36 and $68.05 for 2007 and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2006 and for calendar 2007 were $5.72 and $7.67, respectively.

Realized gains or losses from the settlement of derivative financial instruments are recorded in our financial statements as increases or decreases in derivative financial instrument activities. For example, using the oil swaps in place at September 30, 2006, if the settlement price exceeded the actual weighted average strike price of $64.36, then a reduction in derivative financial instrument activities revenue would have been recorded for the difference between the settlement price and $64.36 multiplied by the hedged volume of 1,462 Mbbls. Conversely, if the settlement price was less than $64.36, then an increase in derivative financial instrument activities revenue would have been recorded for the difference between the settlement price and $64.36 multiplied by the hedged volume of 1,462 Mbbls. For example, for a hedged volume of 1,462 Mbbls, if the settlement price was $63.36, then derivative financial instrument activities revenue would have decreased by $1.5 million. Conversely, if the

settlement price was $65.36, derivative financial instrument activities revenue would have increased by $1.5 million.

Interest rate risk

At September 30, 2006, our exposure to interest rates related primarily to borrowings under our credit agreement. The interest rate is fixed at 7¹/4% on our $444.7 million in senior notes. As of September 30, 2006, we were not using any derivatives to manage interest rate risk. Interest is payable on aggregate principal amount in borrowings under our credit agreement based on a floating rate as more fully described in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources". At October 30, 2006, we had $1.6 billion in outstanding borrowings under the EXCO credit agreement and EPOP's credit agreements. The interest we pay on these borrowings is set periodically based upon market rates. A 1% change in interest rates would affect interest on these borrowings by approximately $15.5 million per year.

Item 4. Controls and procedures

Evaluation of disclosure controls and procedures

We maintain "disclosure controls and procedures," as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable assurance of achieving the desired control objectives and we necessarily are required to apply our judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures.

Our management, under the supervision and with the participation of our CEO and our CFO who is also our Chief Accounting Officer, collectively referred to as the disclosure committee, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 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.

Our management had previously 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.

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 the Company's 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

Other than the remedial actions taken to address the material weakness as noted above, there have been no changes during the quarter ended September 30, 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. 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.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

On October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styledPRC Holdings, LLC, et al. v. North Coast Energy, Inc. (Civil Action No. 06-C-80E) and is pending in the Circuit Court of Roane County, 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 styledThe 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 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 theTawney case. Plaintiffs are seeking common law and statutory compensatory and punitive damages, interest and costs and other remedies. The Company intends to vigorously defend this action. Because this action is in a very preliminary stage, the ultimate outcome of this litigation cannot be determined at this time. However, management does not expect the ultimate outcome of the lawsuit to have a material effect on the financial position, results of operations or cash flows of EXCO Resources.

Item 1A. Risk Factors

In connection with our acquisition of Winchester on October 2, 2006, we may face certain heightened or new risks as more fully described below, in addition to the other risks contained in Annual Report on Form 10-K for the year ended December 31, 2005. Many of the risks described in our Form 10-K apply to the business conducted by Winchester.

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

The acquisition of Winchester for $1.1 billion in cash, subject to post-closing purchase price adjustments, is the largest acquisition that we have completed to date. Proved Reserves acquired were approximately 209.3 Bcfe using the September 30, 2006 spot price. As a result of price increases in natural gas subsequent to September 30, 2006, the Proved Reserves from the Winchester acquisition would increase to 385.0 Bcfe using the October 30, 2006 spot prices for natural gas applied on a constant price basis. The Proved Reserves acquired represent approximately 29% of our pro forma Proved Reserves as of September 30, 2006. In addition, as of October 2, 2006, we added 549 gross (410.3 net) wells to our consolidated portfolio of wells, including approximately 445 gross operated wells, which materially increased the number of wells we currently operate. All of these factors present significant integration challenges for us. The magnitude of this acquisition could strain our managerial,

financial, accounting, technical, operational and administrative resources, disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards as well as our internal controls and procedures. In addition, we acquired a natural gas pipeline and a natural gas gathering system which transports a material amount of natural gas for third parties. We may not be successful in overcoming these risks or any other problems encountered in connection with this acquisition, all of which could negatively impact our results of operations and our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.

We 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 Revolving Credit Facility. The initial amount borrowed under this facility was $651.0 million at closing of the acquisition of Winchester. In connection with the acquisition and our asset contribution, EPOP also entered into the 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 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.

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.

Item 6. 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 on 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/A—Amendment No. 1 dated February 8, 2006 and 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 Form 8-K/A—Amendment No. 1 dated January 17, 2005 and filed on 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 Form 8-K/A—Amendment No. 1 dated February 10, 2005 and filed on 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 its Registration Statement on 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 the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1		EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO's Current Report on Form 8-K dated November 18, 2004 and filed November 24, 2004 and incorporated by reference herein.***
10.2		Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO's Form 8-K dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.
10.3		First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 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., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.5		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.6		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.
10.7		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.*
10.8		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.

10.9		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 February 21, 2006 and incorporated by reference herein.
10.10		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 May 10, 2006 and incorporated by reference herein.
10.11		Form of 7¹/4% Global Note Due 2011.**
10.12		EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.13		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.14		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.15		Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed October 7, 2005 and incorporated by reference herein.***
10.16		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.
10.17		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.
10.18		First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.19		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 on February 14, 2006 and incorporated by reference herein.

10.20		Credit Agreement for Senior Secured Revolving Credit Facility, dated as of September 27, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated February 8, 2006 and filed February 21, 2006 and incorporated by reference herein.
10.21		First Amendment to Revolving Credit Agreement, dated as of December 15, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined herein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated February 8, 2006 and filed February 21, 2006 and incorporated by reference herein.
10.22		Second Amendment to Revolving Credit Agreement, dated as of February 6, 2006, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated February 8, 2006 and filed February 21, 2006 and incorporated by reference herein.
10.23		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 February 21, 2006 and incorporated by reference herein.
10.24		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 March 23, 2006 and incorporated by reference herein.
10.25		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 March 17, 2006 and incorporated by reference herein.***
10.26		Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed March 17, 2006 and incorporated by reference herein.***
10.27		Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed March 17, 2006 and incorporated by reference herein.***
10.28		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 March 17, 2006 and incorporated by reference herein.***
10.29		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 July 25, 2006 and incorporated by reference herein.

10.30		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 October 4, 2006 and incorporated by reference herein.
10.31		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 July 24, 2006, and incorporated by reference herein
10.32		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 October 4, 2006 and incorporated by reference herein.
10.33		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 October 4, 2006 and incorporated by reference herein.
10.34		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 October 4, 2006 and incorporated by reference herein.
10.35		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 October 4, 2006 and incorporated by reference herein.
10.36		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 October 19, 2006 and incorporated by reference herein.
10.37		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 October 19, 2006 and incorporated by reference herein.
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 and 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 and Chief Financial Officer and Chief Accounting Officer of EXCO Resources, Inc., filed herewith.

*: Filed as an Exhibit to EXCO's Registration Statement on 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 its Registration Statement on Form S-4 filed April 20, 2004 and incorporated by reference herein.
***: These exhibits are management contracts.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed in its behalf by the undersigned thereunto duly authorized.

	EXCO RESOURCES, INC. (Registrant)
Date: November 2, 2006	By:	/s/ DOUGLAS H. MILLER Douglas H. Miller Chairman and Chief Executive Officer
	By:	/s/ J. DOUGLAS RAMSEY J. Douglas Ramsey, Ph.D. Vice President, Chief Financial Officer and Chief Accounting Officer

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 on 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/A—Amendment No. 1 dated February 8, 2006 and 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 Form 8-K/A—Amendment No. 1 dated January 17, 2005 and filed on 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 Form 8-K/A—Amendment No. 1 dated February 10, 2005 and filed on 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 its Registration Statement on 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 the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1		EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO's Current Report on Form 8-K dated November 18, 2004 and filed November 24, 2004 and incorporated by reference herein.***
10.2		Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO's Form 8-K dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.
10.3		First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 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., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.5		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.6		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.
10.7		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.*
10.8		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.

10.9		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 February 21, 2006 and incorporated by reference herein.
10.10		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 May 10, 2006 and incorporated by reference herein.
10.11		Form of 7¹/4% Global Note Due 2011.**
10.12		EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.13		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.14		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.15		Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and filed October 7, 2005 and incorporated by reference herein.***
10.16		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.
10.17		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.
10.18		First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO's Amendment No. 1 to the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.19		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 on February 14, 2006 and incorporated by reference herein.

10.20		Credit Agreement for Senior Secured Revolving Credit Facility, dated as of September 27, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated February 8, 2006 and filed February 21, 2006 and incorporated by reference herein.
10.21		First Amendment to Revolving Credit Agreement, dated as of December 15, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined herein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated February 8, 2006 and filed February 21, 2006 and incorporated by reference herein.
10.22		Second Amendment to Revolving Credit Agreement, dated as of February 6, 2006, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Form 8-K/A—Amendment No. 1 dated February 8, 2006 and filed February 21, 2006 and incorporated by reference herein.
10.23		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 February 21, 2006 and incorporated by reference herein.
10.24		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 March 23, 2006 and incorporated by reference herein.
10.25		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 March 17, 2006 and incorporated by reference herein.***
10.26		Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed March 17, 2006 and incorporated by reference herein.***
10.27		Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed March 17, 2006 and incorporated by reference herein.***
10.28		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 March 17, 2006 and incorporated by reference herein.***
10.29		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 July 25, 2006 and incorporated by reference herein.

10.30		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 October 4, 2006 and incorporated by reference herein.
10.31		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 July 24, 2006, and incorporated by reference herein
10.32		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 October 4, 2006 and incorporated by reference herein.
10.33		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 October 4, 2006 and incorporated by reference herein.
10.34		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 October 4, 2006 and incorporated by reference herein.
10.35		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 October 4, 2006 and incorporated by reference herein.
10.36		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 October 19, 2006 and incorporated by reference herein.
10.37		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 October 19, 2006 and incorporated by reference herein.
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 and 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 and Chief Financial Officer and Chief Accounting Officer of EXCO Resources, Inc., filed herewith.

*: Filed as an Exhibit to EXCO's Registration Statement on 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 its Registration Statement on Form S-4 filed April 20, 2004 and incorporated by reference herein.
***: These exhibits are management contracts.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Good

Exco Resources (EXCO) Inactive 10-Q2006 Q3 Quarterly report

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