PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands)

	December 31,			June 30,
	2005			2006
				(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	226,953		$	39,447
Accounts receivable:
Oil and natural gas sales	36,895			36,410
Joint interest	1,081			7,785
Canadian income tax receivable	18,483			—
Interest and other	12,189			2,027
Oil and natural gas derivatives	—			21,103
Related party	2,621			—
Deferred income taxes	29,968			35,784
Deferred costs of initial public offering	3,380			—
Other	10,955			7,089
Total current assets	342,525			149,645
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	53,121			134,310
Proved developed and undeveloped oil and natural gas properties	873,595			1,681,418
Accumulated depreciation, depletion and amortization	(13,281		)	(60,972		)
Oil and natural gas properties, net	913,435			1,754,756
Gas gathering, office and field equipment, net	33,271			57,641
Investment in TXOK Acquisition, Inc.	20,837			—
Oil and natural gas derivatives	—			8,707
Other assets	419			1,541
Goodwill	220,006			306,142
Total assets	$	1,530,493		$	2,278,432

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands)

	December 31,		June 30,
	2005		2006
			(Unaudited)

Liabilities and Shareholders' Equity
Current liabilities:
Interim bank loan	$	350,000	$	—
Accounts payable and accrued liabilities	25,182		41,797
Accrued interest payable	23,779		15,874
Revenues and royalties payable	11,266		31,385
Income taxes payable	901		113
Current portion of asset retirement obligations	1,408		1,407
Oil and natural gas derivatives	53,189		23,771
Total current liabilities	465,725		114,347
Long-term debt	1		324,000
71¤4% senior notes due 2011	461,801		460,340
Asset retirement obligations and other long-term liabilities	15,766		25,962
Deferred income taxes	134,912		189,029
Oil and natural gas derivatives	81,406		62,457
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 104,035 at December 31, 2005 and June 30, 2006, respectively	50		104
Additional paid-in capital	354,482		1,017,668
Retained earnings	16,350		84,525
Total shareholders' equity	370,882		1,102,297
Total liabilities and shareholders' equity	$	1,530,493	$	2,278,432

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands except per share amounts)

	Three months ended					Six months ended
	June 30,					June 30,
	2005			2006		2005			2006
	Predecessor			Successor		Predecessor			Successor
Revenues and other income:
Oil and natural gas	$	40,769		$	80,984	$	79,698		$	151,324
Derivative financial instruments	(12,358		)	35,232		(69,748		)	76,007
Other income	3,251			896		3,640			2,927
Total revenues and other income	31,662			117,112		13,590			230,258
Costs and expenses:
Oil and natural gas production	7,594			16,387		14,383			27,872
Depreciation, depletion and amortization	7,859			29,298		15,715			49,975
Accretion of discount on asset retirement obligations	203			382		406			684
General and administrative	6,054			6,530		11,258			12,439
Interest	8,565			11,660		17,316			28,005
Total costs and expenses	30,275			64,257		59,078			118,975
Equity in net income of TXOK Acquisition, Inc.	—			—		—			1,593
Income (loss) from continuing operations before income taxes	1,387			52,855		(45,488		)	112,876
Income tax expense (benefit)	(3,025		)	21,832		(21,232		)	44,701
Income (loss) from continuing operations	4,412			31,023		(24,256		)	68,175
Discontinued operations:
Loss from discontinued operations	—			—		(4,402		)	—
Gain on disposition of Addison Energy Inc.	1,631			—		175,717			—
Income tax expense	482			—		49,282			—
Income from discontinued operations	1,149			—		122,033			—
Net income	$	5,561		$	31,023	$	97,777		$	68,175
Earnings per share:
Basic
Net income (loss) from continuing operations	$	0.04		$	0.30	$	(0.21	)	$	0.74
Net income	$	0.05		$	0.30	$	0.84		$	0.74
Weighted average common shares outstanding	115,947			104,014		115,947			92,634
Diluted
Net income (loss) from continuing operations	$	0.04		$	0.29	$	(0.21	)	$	0.73
Net income	$	0.05		$	0.29	$	0.84		$	0.73
Weighted average common and common equivalent shares outstanding	115,947			105,270		115,947			94,020

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Three months ended						Six months ended
	June 30,						June 30,
	2005			2006			2005			2006
	Predecessor			Successor			Predecessor			Successor
Operating Activities:
Net income	$	5,561		$	31,023		$	97,777		$	68,175
Income from discontinued operations	(1,149		)	—			(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	—			(50		)	—			(50		)
Depreciation, depletion and amortization	7,859			29,298			15,715			49,975
Stock option compensation expense	—			1,131			—			1,729
Accretion of discount on asset retirement obligations	203			382			406			684
Non-cash change in fair value of derivatives	12,007			(30,009		)	13,072			(73,579		)
Deferred income taxes	(2,929		)	22,525			(27,256		)	44,701
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011	440			(683		)	884			5,194
Effect of changes in:
Accounts receivable	828			16,951			(8,595		)	64,372
Other current assets	(1,882		)	3,618			(562		)	1,679
Accounts payable and other current liabilities	19,882			5,608			16,727			(18,613		)
Net cash used in operating activities of discontinued operations	(9,535		)	—			(73,285		)	—
Net cash provided by (used in) operating activities	31,285			79,794			(83,689		)	142,674
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(22,135		)	(179,183		)	(55,088		)	(211,832		)
Advance 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		)	—			(61,776		)
Proceeds from disposition of property and equipment and other	3,330			1,217			7,294			609
Proceeds from sale of marketable securities	59			—			59			—
Advances/investments with affiliates	342			—			342			—
Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415 (discontinued operations)	(252		)	—			443,397			—
Net cash used in investing activities of discontinued operations	—			—			(442		)	—
Net cash provided by (used in) investing activities	(18,656		)	(239,742		)	395,562			(399,488		)
Financing Activities:
Borrowings under credit agreement	—			233,500			41,300			418,000
Payments on interim bank loan	—			—			—			(350,000		)
Payments on long-term debt	—			(31,096		)	(148,247		)	(615,847		)
Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition	—			(38,098		)	—			(38,098		)
Proceeds from issuance of common stock, net of underwriter commissions and initial public offering costs	—			28			—			656,305
Deferred financing costs and other	—			(361		)	—			(1,052		)
Net cash provided by financing activities of discontinued operations	—			—			59,601			—
Net cash provided by (used in) financing activities	—			163,973			(47,346		)	69,308
Net increase (decrease) in cash	12,629			4,025			264,527			(187,506		)
Cash at beginning of period	278,306			35,422			26,408			226,953
Cash at end of period	$	290,935		$	39,447		$	290,935		$	39,447

Supplemental Cash Flow Information:
Interest paid	$	—		$	3,537		$	16,695		$	29,971
Income taxes paid	$	835		$	—		$	38,125		$	—
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

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited, in thousands)

														Accumulated
	Class A			Class B			Notes			Additional				other			Total
	Common Stock			Common Stock			receivable -			paid-in		Retained		comprehensive			shareholders'
	Shares	Amount		Shares	Amount		officers			capital		earnings		income (loss)			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	—	—		—	—		281			—		—		—			281
Reclassification of foreign currency translation adjustment	—	—		—	—		—			—		—		(21,399		)	(21,399		)
Unrealized gain on equity investments	—	—		—	—		—			—		—		32			32
Net income	—	—		—	—		—			—		97,777		—			97,777
Balance at June 30, 2005	115,947	$	116	11,926	$	12	$	(1,292	)	$	173,804	$	107,936	$	—		$	280,576

															Accumulated
	Class A			Class B				Notes		Additional					other		Total
	Common Stock			Common Stock				Receivable -		paid-In			Retained		comprehensive		shareholders'
	Shares	Amount		Shares		Amount		Officers		capital			earnings		income (loss)		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	31	—		—		—		—		239			—		—		239
Initial public offering costs	—	—		—		—		—		(6,027		)	—		—		(6,027		)
Share-based compensation	—	—		—		—		—		2,214			—		—		2,214
Net income	—	—		—		—		—		—			68,175		—		68,175
Balance at June 30, 2006	104,035	$	104	$	—	$	—	$	—	$	1,017,668		$	84,525	$	—	$	1,102,297

See accompanying notes.

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2006
(Unaudited)

1. Organization and basis of presentation

EXCO Resources, Inc., a Texas corporation incorporated in 1955, or EXCO Resources, 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,” “we,” “us,” and “our” 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 periods 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 our parent 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 our parent for all periods. Accordingly, financial statements contain two separate and distinct bases of accounting which are defined below:

Predecessor — For the three and six months ended June 30, 2005, financial information presented in our condensed consolidated statements of operations and condensed consolidated statements of cash flows reflects the consolidated information of EXCO Resources and EXCO Holdings, our parent company until October 2, 2005. The condensed consolidated statements of changes in shareholders’ equity for the six months ended June 30, 2005 also reflects the consolidated activities of EXCO Resources and EXCO Holdings.

Successor — For the three and six months ended June 30, 2006, financial information presented in our condensed consolidated statements of operations, condensed consolidated statements of cash flows and the six months ended June 30, 2006 condensed consolidated statements of changes in shareholders’ equity reflects 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 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 is now a wholly-owned subsidiary which requires the use of the equity method of accounting for our investment in TXOK Acquisition, Inc. from October 7, 2005 until February 14, 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 June 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 June 30, 2006, results of operations and cash flows for the three and six months ended June 30, 2005 and 2006 and changes in shareholders’ equity for the six months ended June 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 six months ended June 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. 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.

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

2. Recent accounting pronouncement

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 SFAS No. 109 “Accounting for Income Taxes”. FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. FIN 48 is effective as of January 1, 2007. We are currently assessing the impact, if any, of FIN 48 on our financial statements.

3. Significant accounting policy

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 requires significant estimates to be made by management using information available at the time. Since these estimates require the use of significant judgement, actual results could vary as the estimates are subject to changes as new information becomes available.

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, EXCO Holdings owned all of the issued and outstanding common stock of TXOK and BP EXCO Holdings LP, an entity controlled by Mr. Boone Pickens, one of our directors, held all of the outstanding shares of TXOK preferred stock. On September 27, 2005, TXOK completed the acquisition of ONEOK Energy for an aggregate purchase price of approximately $642.9 million, or $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. Boone Pickens, one of our directors, 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 “TXOK acquisition”). 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 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 (see Note 14. “Acquisitions and dispositions”). 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, are 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.

	Six months ended
	June 30,
(in thousands except per share data, unaudited)	2005			2006
Revenues and other income	$	74,161		$	278,142
Income (loss) from continuing operations	$	(24,580	)	$	89,525
Net income	$	97,453		$	89,525
Basic earnings per share	$	0.84		$	0.97
Diluted earnings per share	$	0.84		$	0.95

Other acquisitions

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.

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. $443.4 million). Of this amount, Cdn. $90.1 million (U.S. $72.1 million) was used to repay in full all outstanding balances under Addison’s credit facility while Cdn. $56.2 million (U.S. $45.2 million) was withheld and 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 June 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, 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 six months ended June 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 June 30, 2005 and 2006 (in thousands):

	Six months ended
	June 30,
(Unaudited)	2005			2006
Asset retirement obligation at January 1	$	28,043		$	15,823
Activity during the six months ended June 30:
Acquisition of TXOK Acquisition, Inc.	—			8,203
Acquisition of Power Gas Marketing & Transmission, Inc.	—			1,527
Sales of Addison Energy Inc.	(14,797		)	—
Liabilities incurred during the period	200			531
Liabilities settled during the period	(966		)	—
Accretion of discount	406			684
Asset retirement obligations as of June 30	12,886			26,768
Less current portion	1,713			1,407
Long-term portion	$	11,173		$	25,361

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 June 30, 2006, $53.1 million and $134.3 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 June 30, 2006, due primarily to a decline of approximately 15.4% in NYMEX natural gas prices from March 31, 2006, our carrying costs of unamortized proved oil and natural gas properties, net of deferred taxes, exceeded the June 30, 2006 present value of future net revenues calculated on a constant price basis by $45.0 million, after tax. Subsequent to June 30, 2006, prices for oil and natural gas increased. As of August 9, 2006, the requirement to record a ceiling test write-down was eliminated as a result of these price increases. Accordingly, we have not recorded a ceiling test write-down as of June 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 impairment indicator arises. As a result of the potential ceiling test write-down described in Note 6 above, we performed a goodwill impairment test as of June 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 June 30, 2006, goodwill was $141.6 million and $164.5 million for our U.S. (excluding Appalachia) business segment and Appalachia segment, respectively. 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 June 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 six months ended June 30, 2005 and 2006 equals the net income divided by the weighted average common shares outstanding during the period. Diluted earnings per common share for the three and six months ended June 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 six months ended June 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 six months ended June 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. For the three months ended June 30, 2005, 8,801,351 potential common stock equivalents from the assumed conversion of stock options have been excluded from the diluted EPS calculation as they were deemed to be antidilutive.

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

	Three months ended June 30,				Six months ended June 30,
	2005		2006		2005			2006

Basic earnings per share:

Income (loss) from continuing operations	$	4,412	$	31,023	$	(24,256	)	$	68,175
Income from discontinued operations	1,149		—		122,033			—
Net income	$	5,561	$	31,023	$	97,777		$	68,175

Shares:
Weighted average number of common shares outstanding	115,947		104,014		115,947			92,634

Basic earnings (loss) per share:
Continuing operations	$	0.04	$	0.30	$	(0.21	)	$	0.74
Discontinued operations	0.01		—		1.05			—
Total basic earnings per share	$	0.05	$	0.30	$	0.84		$	0.74

Diluted earnings per share:

Income (loss) from continuing operations	$	4,412	$	31,023	$	(24,256	)	$	68,175
Income from discontinued operations	1,149		—		122,033			—
Net income	$	5,561	$	31,023	$	97,777		$	68,175

Shares:
Weighted average number of common shares outstanding	115,947		104,014		115,947			92,634
Diluted effect of stock options	—		1,256		—			1,386
Weighted average common shares and common stock equivalents	115,947		105,270		115,947			94,020

Diluted earnings (loss) per share:
Continuing operations	$	0.04	$	0.29	$	(0.21	)	$	0.73
Discontinued operations	0.01		—		1.05			—
Total diluted earnings per share	$	0.05	0.29		$	0.84		$	0.73

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 SFAS 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 six months ended June 30, 2006, total share-based compensation was $1.4 million and $2.2 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 June 30, 2006 were $0.2 million and $0.4 million for the six months ended June 30, 2006. Total share-based compensation to be recognized on unvested awards as of June 30, 2006 is $7.8 million over a weighted average period of 2.6 years.

During the six months ended June 30, 2006, options to purchase 714,900 shares were granted by EXCO under the 2005 Incentive Plan at prices ranging from $12.36 to $13.00 per share. 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 June 30, 2006, there were 5,026,925 and 4,377,325 shares available to be granted under the 2005 Incentive Plan, respectively.

Prior to October 3, 2005, as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation”, we elected to follow Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (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, that being the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have geographic operating segments in the United States and, until February 10, 2005, in Canada. Upon the acquisition of 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
(in thousands)	Appalachia)			Appalachia			Total

Three months ended June 30, 2005:
Revenues and other income:
Oil and natural gas	$	17,527		$	23,242		$	40,769
Derivative financial instruments	(1,258		)	(11,100		)	(12,358		)
Other income	2,917			334			3,251
Total revenues and other income	19,186			12,476			31,662

Costs and expenses:
Oil and natural gas production	4,121			3,473			7,594
Depreciation, depletion and amortization	3,823			4,036			7,859
Accretion of discount on asset retirement obligations	92			111			203
General and administrative	4,922			1,132			6,054
Interest	6,671			1,894			8,565
Total costs and expenses	19,629			10,646			30,275
Income before income taxes	(443		)	1,830			1,387
Income tax expense (benefit)	4,085			(7,110		)	(3,025		)
Income (loss) from continuing operations	(4,528		)	8,940			4,412
Discontinued operations:
Income from operations	1,631			—			1,631
Income tax expense	482			—			482
Net income from discontinued operations	1,149			—			1,149
Net income (loss)	$	(3,379	)	$	8,940		$	5,561
Goodwill at end of period	$	19,984		$	—		$	19,984
Total assets at end of period	$	537,674		$	332,824		$	870,498

	U.S. (excluding
(in thousands)	Appalachia)		Appalachia		Total

Three months ended June 30, 2006:
Revenues and other income:
Oil and natural gas	$	52,449	$	28,535	$	80,984
Derivative financial instruments	18,345		16,887		35,232
Other income	480		416		896
Total revenues and other income	71,274		45,838		117,112

Costs and expenses:
Oil and natural gas production	11,309		5,078		16,387
Depreciation, depletion and amortization	20,205		9,093		29,298
Accretion of discount on asset retirement obligations	221		161		382
General and administrative	5,082		1,448		6,530
Interest	4,706		6,954		11,660
Total costs and expenses	41,523		22,734		64,257
Income before income taxes	29,751		23,104		52,855
Income tax expense	12,767		9,065		21,832
Net income	$	16,984	$	14,039	$	31,023
Goodwill at end of period	$	141,673	$	164,469	$	306,142
Total assets at end of period	$	1,312,629	$	965,803	$	2,278,432

	U.S. (excluding
(in thousands)	Appalachia)			Appalachia			Total

Six months ended June 30, 2005:
Revenues and other income:
Oil and natural gas	$	33,713		$	45,985		$	79,698
Derivative financial instruments	(20,858		)	(48,890		)	(69,748		)
Other income	3,045			595			3,640
Total revenues and other income	15,900			(2,310		)	13,590

Costs and expenses:
Oil and natural gas production	7,598			6,785			14,383
Depreciation, depletion and amortization	7,581			8,134			15,715
Accretion of discount on asset retirement obligations	188			218			406
General and administrative	8,914			2,344			11,258
Interest	13,615			3,701			17,316
Total costs and expenses	37,896			21,182			59,078
Income before income taxes	(21,996		)	(23,492		)	(45,488		)
Income tax benefit	(3,744		)	(17,488		)	(21,232		)
Loss from continuing operations	(18,252		)	(6,004		)	(24,256		)
Discontinued operations:
Loss from 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)	$	103,781		$	(6,004	)	$	97,777
Goodwill at end of period	$	19,984		$	—		$	19,984
Total assets at end of period	$	537,674		$	332,824		$	870,498

	U.S. (excluding
(in thousands)	Appalachia)		Appalachia		Total

Six months ended June 30, 2006:
Revenues and other income:
Oil and natural gas	$	88,495	$	62,829	$	151,324
Derivative financial instruments	28,170		47,837		76,007
Other income	1,974		953		2,927
Total revenues and other income	118,639		111,619		230,258

Costs and expenses:
Oil and natural gas production	18,542		9,330		27,872
Depreciation, depletion and amortization	32,239		17,736		49,975
Accretion of discount on asset retirement obligations	381		303		684
General and administrative	9,786		2,653		12,439
Interest	14,853		13,152		28,005
Total costs and expenses	75,801		43,174		118,975
Equity in net income of TXOK Acquisition, Inc.	1,593		—		1,593
Income before income taxes	44,431		68,445		112,876
Income tax expense	18,083		26,618		44,701
Net income	26,348		41,827		68,175
Goodwill at end of period	$	141,673	$	164,469	$	306,142
Total assets at end of period	$	1,312,629	$	965,803	$	2,278,432

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. SFAS 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 June 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 June 30, 2006. We have the right to offset amounts we expect to receive or pay among our individual counterparties. As a result, we have offset amounts for financial statement presentation purposes. The following table sets forth our oil and natural gas derivatives as of June 30, 2006.

(in thousands, except prices and differentials)	Volume Mmbtu/Bbls	Weighted average strike price		Weighted average differential to NYMEX			Fair value at June 30, 2006 gain (loss)

Natural gas:
Swaps
Remainder of 2006	12,265	$	7.90				$	9,557
2007	29,790	8.52					(18,341		)
2008	25,140	8.51					(9,188		)
2009	7,705	7.14					(8,658		)
2010	6,985	6.63					(7,954		)
2011	1,825	4.51					(4,311		)
2012	1,830	4.51					(3,632		)
2013	1,825	4.51					(3,044		)
	87,365

Floor:
Remainder of 2006	2,760	6.15					918
	2,760

Ceiling:
Remainder of 2006	2,760	10.00					(1,033		)
	2,760

Basis protection swaps:
Remainder of 2006	2,760			$	(0.32	)	1,466
	2,760

Total natural gas							(44,220		)

Oil:
Swaps:
Remainder of 2006	347	70.92					(1,602		)
2007	734	69.53					(4,493		)
2008	327	62.67					(3,257		)
2009	120	60.80					(1,107		)
2010	108	59.85					(900		)
	1,636

Floor:
Remainder of 2006	54	50.35					0
	54

Ceiling:
Remainder of 2006	54	60.00					(839		)
	54

Total oil							(12,198		)

Total oil and natural gas							$	(56,418	)

At June 30, 2006, the average forward NYMEX oil prices per Bbl for the remainder of calendar 2006 and for 2007 were $75.54 and $75.99, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of calendar 2006 and for 2007 were $7.15 and $9.18, respectively.

13. Long-term debt and interim bank loan

Long-term debt is summarized as follows:

	December 31,		June 30,
(in thousands)	2005		2006

Short-term debt:
Interim bank loan	$	350,000	$	—
Long-term debt:
Borrowings under our credit agreement	$	1	$	324,000
7 1/4% senior notes due 2011	444,720		444,720
Unamortized premium on 7 1/4% senior notes due 2011	17,081		15,620
Total long-term debt	$	461,802	$	784,340

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 TXOK and North Coast Energy, Inc., or North Coast and PGMT. 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 June 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.

We typically elect to borrow funds using the LIBOR interest rate option described above. At December 31, 2005 and June 30, 2006, the six month LIBOR rates were 4.70% and 5.59% which would result in interest rates of approximately 5.95% and 6.59%, respectively, on any new indebtedness we may incur under the credit agreement. At December 31, 2005 and June 30, 2006, we had $1,000 and $324.0 million respectively, of outstanding indebtedness under our credit agreement. As of June 30, 2006, we had $176.0 million available under our credit agreement based on the current aggregate commitment of $500.0 million. Management believes its cash flows from operations will provide sufficient cash to service our debt.

the payment of dividends on our common stock. As of June 30, 2006, we were in compliance with our debt covenants.

7¼% senior notes due January 15, 2011

The estimated fair value of our 7 ¼% senior notes due January 15, 2011, or senior notes, at June 30, 2006 was $429.2 million as compared to the carrying amount of $460.3 million (including $15.6 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 with JP Morgan. 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. GAAP requires the acquisition by Holdings II to be accounted for as a purchase transaction in accordance with SFAS No. 141. In addition, GAAP requires the application of “push down accounting” in situations where the ownership of an entity has changed, meaning that the post transaction financial statements of the acquired entity (EXCO) reflect the new basis of accounting in accordance with SAB 54. In addition to the stepped-up basis resulting from the 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. Acquisitions and dispositions

On April 5, 2006 we announced that we closed the acquisition of a 50% interest in approximately 19,000 acres of leasehold interests and 38 producing wells in West Texas for $85.7 million, before contractual adjustments. We funded this purchase with indebtedness drawn under our credit agreement. Net production at the date of acquisition was approximately 4.4 Mmcfe per day. Our interest in the Proved Reserves was approximately 33.0 Bcfe (77% natural gas and 27% proved developed). EXCO and the seller will conduct a joint development program on the properties over the next several years with an estimated 70 wells to be drilled in 2006 and early 2007. It is estimated that in excess of 200 wells will be necessary to fully develop the acreage.

On April 28, 2006, EXCO announced that it closed the acquisition of 100% of the common stock of PGMT for $115.0 million, before contractual adjustments, including the repayment of debt and outstanding commodity hedges. We funded this purchase with indebtedness drawn under our credit agreement. PGMT is a private producer of oil and natural gas which owns and operates assets in the Appalachia region, particularly in Pennsylvania, Ohio, New York and West Virginia. Net production at the acquisition date totaled approximately 5.0 Mmcfe per day from 1,187 producing wells. The net Proved Reserves were estimated at 161.6 Bcfe (96% natural gas and 25% proved developed). The PGMT acreage held by production includes approximately 178,000 acres containing over 2,000 drilling locations, of which approximately 68% of such locations are proved. In addition to the oil and natural gas assets, we acquired 358 miles of gathering lines, ten compressor stations along those gathering lines, and other miscellaneous assets.

On May 25, 2006, we announced the acquisition of producing and undeveloped oil and natural gas properties in the Cotton Valley trend in East Texas from a privately held company. The properties were acquired for a purchase price of $51.6 million ($52.3 million after contractual adjustments), consisting of approximately 2,000 net acres of leasehold and estimated proved reserves of 28.3 Bcfe (99% natural gas and 51% proved developed). Net production at the date of acquisition from the wells acquired was approximately 4.3 Mmcfe per day. Also included in the purchase was approximately 10,500 net undeveloped acres in the general area of the production. EXCO will operate the properties and will own 100% of the working interest.

Transactions, other than the sale of Addison, that occurred during the three months ended June 30, 2005

During the six months ended June 30, 2005, we completed one oil and natural gas property acquisition. Estimated total Proved Reserves net to our interest from the acquisition included approximately 35 Mbbls of oil and 8.8 Bcf of natural gas. The total purchase price for the acquisition was approximately $17.9 million (approximately $17.7 million after contractual adjustments), funded with borrowings under our credit agreement and from surplus cash. In addition, we also acquired a small natural gas gathering system for $0.7 million as part of this acquisition.

During the first six months of 2005, we sold two oil and natural gas properties. As of January 1, 2005, estimated total Proved Reserves net to our interest from these properties included approximately 225 Mbbls of oil and NGLs and 2.4 Bcf of natural gas. The total sales proceeds we received were approximately $3.9 million.

15. Subsequent events

On July 24, 2006, we announced an agreement to acquire Winchester Energy Company, Ltd., or Winchester, and its affiliated entities from Progress Energy, Inc. for $1.2 billion in cash, subject to purchase price adjustments. The acquisition consists of producing and undeveloped natural gas properties with current production of approximately 75 Mmcfe per day from 588 producing wells, of which 89% are operated. The average acquired working interest is 87% with an average 68% net revenue interest. The properties are located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. Proved reserves to be acquired are approximately 400 Bcfe. The properties include approximately 775 drilling locations, 33% of which are proved, and 106,000 net acres of leasehold of which 63% is held by production. The acquisition also includes six gathering systems with 300 miles of pipe and a 54 mile, 16 inch pipeline with throughput of 115 Mmcf per day, 35% of which represents Winchester production. It is anticipated that this acquisition will close on October 2, 2006.

The acquisition will be financed with a $750 million term loan facility and a new revolving credit facility. We have formed a new subsidiary to purchase Winchester and its affiliates, and that subsidiary will be classified as an Unrestricted Subsidiary as defined in the indenture governing our senior notes. The subsidiary will not be a guarantor of EXCO debt obligations nor will EXCO guarantee the debt of the subsidiary. We currently intend to execute an equity offering by the subsidiary, through the sale of units representing limited partner interests, to repay this indebtedness.

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.

16. 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.

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

December 31, 2005

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiaries		Eliminations			Consolidated

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)

June 30, 2006

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiaries		Eliminations			Consolidated

Assets
Current assets:
Cash and cash equivalents	$	9,569		$	29,878		$	—	$	—		$	39,447
Other current assets	27,464			82,734			—		—			110,198
Total current assets	37,033			112,612			—		—			149,645
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	6,778			127,532			—		—			134,310
Proved developed and undeveloped oil and natural gas properties	109,846			1,571,572			—		—			1,681,418
Allowance for depreciation, depletion and amortization	(5,276		)	(55,696		)	—		—			(60,972		)
Oil and natural gas properties, net	111,348			1,643,408			—		—			1,754,756
Gas gathering, office and field equipment, net	1,701			55,940			—		—			57,641
Deferred financing costs	—			—			—		—			—
Oil and natural gas hedge derivatives	2,781			5,926			—		—			8,707
Goodwill	78,317			227,825			—		—			306,142
Investments in and advances to affiliates	1,638,245			52,877			—		(1,691,122		)	—
Other assets, net	1,054			487			—		—			1,541
Total assets	$	1,870,479		$	2,099,075		$	—	$	(1,691,122	)	$	2,278,432
							—
Liabilities and Shareholders' Equity
Current liabilities	$	45,006		$	69,337		$	—	$	4		$	114,347
Long-term debt	784,340			—			—		—			784,340
Deferred income taxes	38,232			150,797			—		—			189,029
Other liabilities	14,140			74,279			—		—			88,419
Payable to parent	(113,720		)	529,509			—		(415,789		)	—
Commitments and contingencies	—			—			—		—			—
Shareholders' equity	1,102,481			1,275,153			—		(1,275,337		)	1,102,297
Total liabilities and shareholders' equity	$	1,870,479		$	2,099,075		$	—	$	(1,691,122	)	$	2,278,432

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the three months ended June 30, 2005

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiary			Eliminations			Consolidated

Revenues and other income:
Oil and natural gas sales	$	7,380		$	33,389		$	—		$	—		$	40,769
Derivative financial instruments	(1,259		)	(11,099		)	—			—			(12,358		)
Other income (loss)	22,106			448			—			(19,303		)	3,251
Equity in earnings of subsidiaries	(2,655		)	—			—			2,655			—
Total revenues and other income	25,572			22,738			—			(16,648		)	31,662

Costs and expenses:
Oil and natural gas production	2,273			5,321			—			—			7,594
Depreciation, depletion and amortization	1,290			6,569			—			—			7,859
Accretion of discount on asset retirement obligations	78			125			—			—			203
General and administrative	4,923			1,131			—			—			6,054
Interest	8,565			19,303			—			(19,303		)	8,565
Total costs and expenses	17,129			32,449			—			(19,303		)	30,275
Income (loss) before income taxes	8,443			(9,711		)	—			2,655			1,387
Income tax expense (benefit)	4,071			(7,096		)	—			—			(3,025		)
Income (loss) from continuing operations	4,372			(2,615		)	—			2,655			4,412

Discontinued operations:
Income from operations	—			—			—			—			—
Gain on sale of Addison Energy Inc	1,631			—			—			—			1,631
Income tax expense	—			—			482			—			482
Net income (loss) from discontinued operations	1,631			—			(482		)	—			1,149
Net income (loss)	$	6,003		$	(2,615	)	$	(482	)	$	2,655		$	5,561

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the three months ended June 30, 2006

(In thousands)	EXCO Resources		Guarantor subsidiaries		Non- guarantor subsidiary		Eliminations			Consolidated

Revenues and other income:
Oil and natural gas sales	$	7,080	$	73,904	$	—	$	—		$	80,984
Derivative financial instruments	9,359		25,873		—		—			35,232
Other income (loss)	7,111		740		—		(6,955		)	896
Equity in earnings of subsidiaries	32,841		—		—		(32,841		)	—
Total revenues and other income	56,391		100,517		—		(39,796		)	117,112

Costs and expenses:
Oil and natural gas production	2,484		13,903		—		—			16,387
Depreciation, depletion and amortization	2,104		27,194		—		—			29,298
Accretion of discount on asset retirement obligations	28		354		—		—			382
General and administrative	4,796		1,734		—		—			6,530
Interest	11,661		6,954		—		(6,955		)	11,660
Total costs and expenses	21,073		50,139		—		(6,955		)	64,257
Income (loss) before income taxes	35,318		50,378		—		(32,841		)	52,855
Income tax expense	4,295		17,537		—		—			21,832
Income (loss) from continuing operations	31,023		32,841		—		(32,841		)	31,023

Discontinued operations:
Income from operations	—		—		—		—			—
Gain on sale of Addison Energy Inc.	—		—		—		—			—
Income tax expense (benefit)	—		—		—		—			—
Net income from discontinued operations	—		—		—		—			—
Net income (loss)	$	31,023	$	32,841	$	—	$	(32,841	)	$	31,023

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the six months ended June 30, 2005

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non- guarantor subsidiary			Eliminations			Consolidated

Revenues and other income:
Oil and natural gas sales	$	13,630		$	66,068		$	—		$	—		$	79,698
Derivative financial instruments	(20,859		)	(48,889		)	—			—			(69,748		)
Other income (loss)	24,125			727			—			(21,212		)	3,640
Equity in earnings of subsidiaries	(15,175		)	—			—			15,175			—
Total revenues and other income	1,721			17,906			—			(6,037		)	13,590

Costs and expenses:
Oil and natural gas production	4,544			9,841			—			(2		)	14,383
Depreciation, depletion and amortization	2,609			13,106			—			—			15,715
Accretion of discount on asset retirement obligations.	156			250			—			—			406
General and administrative	8,915			2,343			—			—			11,258
Interest	17,419			21,109			—			(21,212		)	17,316
Total costs and expenses	33,643			46,649			—			(21,214		)	59,078
Income (loss) before income taxes	(31,922		)	(28,743		)	—			15,177			(45,488		)
Income tax benefit	(3,744		)	(17,488		)	—			—			(21,232		)
Income (loss) from continuing operations	(28,178		)	(11,255		)	—			15,177			(24,256		)

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)	$	97,777		$	(11,255	)	$	(3,922	)	$	15,177		$	97,777

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the six months ended June 30, 2006

(In thousands)	EXCO Resources		Guarantor subsidiaries		Non- guarantor subsidiary		Eliminations			Consolidated

Revenues and other income:
Oil and natural gas sales	$	14,421	$	136,903	$	—	$	—		$	151,324
Derivative financial instruments	21,307		54,700		—		—			76,007
Other income (loss)	14,463		1,617		—		(13,153		)	2,927
Equity in earnings of subsidiaries	70,021		—		—		(70,021		)	—
Total revenues and other income	120,212		193,220		—		(83,174		)	230,258

Costs and expenses:
Oil and natural gas production	4,990		22,882		—		—			27,872
Depreciation, depletion and amortization	4,180		45,795		—		—			49,975
Accretion of discount on asset retirement obligations	36		648		—		—			684
General and administrative	8,915		3,524		—		—			12,439
Interest	27,330		13,828		—		(13,153		)	28,005
Total costs and expenses	45,451		86,677		—		(13,153		)	118,975
Equity in net income of TXOK Acquisition, Inc.	1,593		—		—		—			1,593
Income (loss) before income taxes	76,354		106,543		—		(70,021		)	112,876
Income tax expense	7,995		36,706		—		—			44,701
Income (loss) from continuing operations	68,359		69,837		—		(70,021		)	68,175

Discontinued operations:
Income from operations	—		—		—		—			—
Gain on sale of Addison Energy Inc.	—		—		—		—			—
Income tax expense (benefit)	—		—		—		—			—
Net income from discontinued operations	—		—		—		—			—
Net income (loss)	$	68,359	$	69,837	$	—	$	(70,021	)	$	68,175

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the three months ended June 30, 2005

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations		Consolidated

Operating Activities:
Net cash provided by operating activities	$	22,826		$	8,459		$	—	$	—	$	31,285
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	16,002			(38,137		)	—		—		(22,135		)
Proceeds from disposition of property and equipment	3,322			8			—		—		3,330
Proceeds from sale of marketable securities	59			—			—		—		59
Proceeds from sale of Addison Energy Inc., net of cash sold	(252		)	—			—		—		(252		)
Advances/investments with affiliates	(75,638		)	75,980			—		—		342
Net cash provided by (used in) investing activities	(56,507		)	37,851			—		—		(18,656		)
Financing Activities:
Proceeds from long-term debt	—			—			—		—		—
Payments on long-term debt	—			—			—		—		—
Deferred financing costs	—			—			—		—		—
Other financing activities	—			—			—		—		—
Net cash used in financing activities	—			—			—		—		—
Net increase in cash	(33,681		)	46,310			—		—		12,629
Cash at beginning of period	261,722			16,584			—		—		278,306
Cash at end of period	$	228,041		$	62,894		$	—	$	—	$	290,935

Supplemental Cash Flow Information:
Interest paid	$	—		$	—		$	—	$	—	$	—
Income taxes paid	$	235		$	600		$	—	$	—	$	835

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the three months ended June 30, 2006

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations		Consolidated

Operating Activities:
Net cash used in operating activities	$	11,442		$	68,352		$	—	$	—	$	79,794
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(14,276		)	(164,907		)	—		—		(179,183		)
Proceeds from disposition of property and equipment.	1,152			65			—		—		1,217
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired	—			(61,776		)	—		—		(61,776		)
Advances/investments with affiliates	(212,458		)	212,458			—		—		—
Net cash used in investing activities	(225,582		)	(14,160		)	—		—		(239,742		)
Financing Activities:
Proceeds from long-term debt	233,500			—			—		—		233,500
Payments on long-term debt	(18,000		)	(13,096		)	—		—		(31,096		)
Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition	—			(38,098		)	—		—		(38,098		)
Deferred financing costs	28			—			—		—		28
Other financing activities	(500		)	139			—		—		(361		)
Net cash provided by financing activities	215,028			(51,055		)	—		—		163,973
Net increase in cash	888			3,137			—		—		4,025
Cash at beginning of period	8,691			26,731			—		—		35,422
Cash at end of period	$	9,579		$	29,868		$	—	$	—	$	39,447

Supplemental Cash Flow Information:
Interest paid	$	3,537		$	—		$	—	$	—	$	3,537
Income taxes paid	$	—		$	—		$	—	$	—	$	—

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the six months ended June 30, 2005

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non-guarantor subsidiary			Eliminations		Consolidated

Operating Activities:
Net cash used in operating activities	$	(80,586	)	$	(3,103	)	$	—		$	—	$	(83,689	)
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(3,130		)	(51,958		)	—			—		(55,088		)
Proceeds from disposition of property and equipment	7,286			8			—			—		7,294
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
Advances/investments with affiliates	(75,638		)	75,980			—			—		342
Net cash used in investing activities of discontinued operations	(442		)	—			—			—		(442		)
Net cash provided by (used in) investing activities	381,933			24,030			(10,401		)	—		395,562
Financing Activities:
Proceeds from long-term debt	41,300			—			—			—		41,300
Payments on long-term debt	(148,247		)	—			—			—		(148,247		)
Net cash provided by financing activities of discontinued operations	59,601			—			—			—		59,601
Net cash used in financing activities	(47,346		)	—			—			—		(47,346		)
Net increase (decrease) in cash	254,001			20,927			(10,401		)	—		264,527
Cash at beginning of period	8,535			7,472			10,401			—		26,408
Cash at end of period	$	262,536		$	28,399		$	—		$	—	$	290,935

Supplemental Cash Flow Information:
Interest paid	$	16,695		$	—		$	—		$	—	$	16,695
Income taxes paid	$	36,960		$	1,165		$	—		$	—	$	38,125

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)

For the six months ended June 30, 2006

(In thousands)	EXCO Resources			Guarantor subsidiaries			Non-guarantor subsidiary		Eliminations		Consolidated

Operating Activities:
Net cash provided by operating activities	$	12,315		$	130,359		$	—	$	—	$	142,674
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(18,444		)	(193,388		)	—		—		(211,832		)
Proceeds from disposition of property and equipment	1,109			(500		)	—		—		609
Cash acquired in acquisition of TXOK Acquisition, Inc.	—			32,261			—		—		32,261
Advance to TXOK Acquisition, Inc. for preferred stock redemption	(158,750		)	—			—				(158,750		)
Advances/investments with affiliates	(138,711		)	138,711			—		—		—
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired	—			(61,776		)	—		—		(61,776		)
Net cash used in investing activities	(314,796		)	(84,692		)	—		—		(399,488		)
Financing Activities:
Proceeds from long-term debt	418,000			—			—		—		418,000
Payments on long-term debt	(602,751		)	(13,096		)	—		—		(615,847		)
Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition	—			(38,098		)	—		—		(38,098		)
Payments on interim bank loan	(350,000		)	—			—		—		(350,000		)
Proceeds from issuance of common stock, net of underwriters commissions and initial public offering costs	656,305			—			—		—		656,305
Deferred financing costs and other	(1,191		)	139			—		—		(1,052		)
Net cash provided by (used in) financing activities	120,363			(51,055		)	—		—		69,308
Net decrease in cash	(182,118		)	(5,388		)	—		—		(187,506		)
Cash at beginning of period	191,500			35,453			—		—		226,953
Cash at end of period	$	9,382		$	(30,065	)	$	—	$	—	$	39,447

Supplemental Cash Flow Information:
Interest paid	$	29,971		$	—		$	—	$	—	$	29,971
Income taxes paid	$	—		$	—		$	—	$	—	$	—

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;

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

· cash flow and liquidity;

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

· availability of drilling and production equipment;

· marketing of oil and natural gas;

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

· competition;

· general economic conditions;

· governmental regulations;

· receipt of amounts owed to us by purchasers of our production and counterparties to our 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. In April and May 2006, we spent in excess of $250.0 million on property and corporate acquisitions of oil and natural gas properties.

As oil and natural gas prices have increased, we have seen an increase in demand for drilling rigs, field supplies and other related field services. This has resulted in increases in the costs of these goods and services and some difficulty in timely scheduling of drilling rigs and other field services required to perform operations on our properties. To date, however, we have not encountered any significant operational problems or delays as a result of the difficulty in scheduling these services. 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 in April and May 2006, we expect our 2006 capital budget for drilling and exploitation to increase by approximately $59.7 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 to develop and identify additional reserves and by acquisitions. Our future growth will depend upon our ability to continue to add oil and natural gas reserves in excess of production at a reasonable cost. We will maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

We also face the challenge of financing future acquisitions. Following completion of our 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. At this point, 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, we consider business combinations and purchase accounting as a significant accounting policy. We follow SFAS No. 141, “Business Combinations” 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 judgement, 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 FASB issued Financial Interpretation No. 48 “Accounting for Uncertainty in Income Taxes”, or FIN 48.

FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109 “Accounting for Income Taxes”. FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. FIN 48 is effective as of January 1, 2007. We are currently assessing the impact, if any, of FIN 48 on our financial statements.

Our results of operations

The following is a discussion of our financial condition and results of operations for the three and six months ended June 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;

· 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, natural gas marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions. We also gather natural gas for other producers for which we are compensated.

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 six months ended June 30, 2005 and 2006. The tables also show the changes in these amounts between periods.

	Three months ended June 30,				Quarter to quarter change		Six months ended June 30,				Year to year change
(Unaudited, in thousands)	2005		2006		2005-2006		2005		2006		2005-2006

Oil and natural gas revenues before derivative financial instruments:
Oil revenues:
U.S. (excluding Appalachia)	$	4,838	$	12,829	$	7,991	$	9,664	$	20,490	$	10,826
Appalachia	1,335		2,006		671		2,443		3,338		895
Total	$	6,173	$	14,835	$	8,662	$	12,107	$	23,828	$	11,721
Natural gas revenues:
U.S. (excluding Appalachia)	$	12,689	$	39,620	$	26,931	$	24,050	$	68,005	$	43,955
Appalachia	21,907		26,529		4,622		43,541		59,491		15,950
Total	$	34,596	$	66,149	$	31,553	$	67,591	$	127,496	$	59,905
Total oil and natural gas revenues:
U.S. (excluding Appalachia)	$	17,527	$	52,449	$	34,922	$	33,714	$	88,495	$	54,781
Appalachia	23,242		28,535		5,293		45,984		62,829		16,845
Total	$	40,769	$	80,984	$	40,215	$	79,698	$	151,324	$	71,626

	Three months ended June 30,		Quarter to quarter change	Six months ended June 30,		Year to year change
(Unaudited)	2005	2006	2005-2006	2005	2006	2005-2006

Production:
Oil (Mbbls):
U.S. (excluding Appalachia)	97	191	94	199	316	117
Appalachia	27	31	4	51	54	3
Total	124	222	98	250	370	120
Natural gas (Mmcf):
U.S. (excluding Appalachia)	2,146	6,457	4,311	4,271	10,393	6,122
Appalachia	2,893	3,515	622	5,924	6,784	860
Total	5,039	9,972	4,933	10,195	17,177	6,982
Total production (Mmcfe):
U.S. (excluding Appalachia)	2,728	7,603	4,875	5,465	12,289	6,824
Appalachia	3,055	3,701	646	6,230	7,108	878
Total	5,783	11,304	5,521	11,695	19,397	7,702

	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Year to year change
(Unaudited)	2005		2006		2005-2006			2005		2006		2005-2006

Average sales price (excluding derivative financial instrument activities):
Oil (per Bbl):
U.S. (excluding Appalachia)	$	49.88	$	67.17	$	17.29		$	48.56	$	64.84	$	16.28
Appalachia	49.44		64.71		15.27			47.90		61.81		13.91
Total	49.78		66.82		17.04			48.43		64.40		15.97
Natural gas (per Mcf):
U.S. (excluding Appalachia)	$	5.91	$	6.14	$	0.23		$	5.63	$	6.54	$	0.91
Appalachia	7.57		7.55		(0.02		)	7.35		8.77		1.42
Total	6.87		6.63		(0.24		)	6.63		7.42		0.79
Total oil and natural gas revenues (per Mcfe):
U.S. (excluding Appalachia)	$	6.42	$	6.90	$	0.48		$	6.17	$	7.20	$	1.03
Appalachia	7.61		7.71		0.10			7.38		8.84		1.46
Total	7.05		7.16		0.11			6.81		7.80		0.99

Our revenues from the sale of oil and natural gas, before the impacts of derivative financial instruments, for the three and six months ended June 30, 2006 increased by $40.2 million and $71.6 million, respectively, or 98.6% and 89.9%, respectively, over the three and six months ended June 30, 2005. For the three months ended June 30, 2006, compared with the three months ended June 30, 2005, higher production volumes increased total revenues $39.5 million while higher equivalent Mcf prices increased revenues by $0.6 million. For the six months ended June 30, 2006 compared with the same prior year period, higher volumes and Mcf equivalent prices increased revenues by $60.1 million and $11.5 million, respectively. The increases in the June 30, 2006 production volumes are due primarily to:

· the February 14, 2006 acquisition of TXOK which contributed 6.6 Bcfe to the six months ended June 30, 2006;

· new acquisitions in West Texas and East Texas, which added 0.6 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 188 new wells drilled and completed since June 30, 2005.

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

In our Appalachia segment, oil and natural gas production volumes for the six months ended June 30, 2006, increased approximately 878 Mmcfe from the comparable period last year. This increase is the result of additional natural gas production of 812 Mmcfe from producing property acquisitions which closed during the third quarter of 2005 and the addition of 272 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. We currently anticipate pipeline curtailments of approximately 3.0 Mmcf per day in Appalachia for the third quarter of 2006.

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

(Unaudited, in thousands)	Three months ended June 30,					Quarter to quarter change			Six months ended June 30, 2005					Year to year change
	2005			2006		2005-2006			2005			2006		2005-2006

Derivative financial instrument activities:
Cash settlements on derivative financial instruments	$	(351	)	$	5,223	$	5,574		$	(56,676	)	$	2,428	$	59,104
Non-cash change in fair value of derivative financial instruments	$	(12,007	)	30,009		42,016			(13,072		)	73,579		86,651
Total derivative financial instrument activities	$	(12,358	)	$	35,232	$	47,590		$	(69,748	)	$	76,007	$	145,755

Other income, net:
Gain (loss) from foreign currency transactions	$	(105	)	$	—	$	105		$	80		$	—	$	(80	)
Interest, dividend and other, net	3,356			896		(2,460		)	3,560			2,927		(633		)
Total other income, net	$	3,251		$	896	$	(2,355	)	$	3,640		$	2,927	$	(713	)

Our derivative financial instrument activities increased revenue by $35.2 million and $76.0 million, respectively during the three and six months ended June 30, 2006, and include payments received totaling $2.4 million to settle existing contracts for the six months ended June 30, 2006. The six months ended June 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 $4.1 million of cash settlements of derivative financial instruments during the six months ended June 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 June 30, 2005 and 2006, we recognized a decrease to revenue of $12.0 million and an increase in revenue of $30.0 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 three and six months ended June 30, 2006, 69% of our total production, for each period, was subject to derivative contracts.

Our other income decreased to $0.9 million for the three months ended June 30, 2006 from $3.3 million in the previous year’s quarter. The decrease is primarily due to lower interest income in the three months ended June 30, 2006 as a result of reduced cash balances as compared to the three months ended June 30, 2005.

Other income for the six months ended June 30, 2006 was $2.9 million compared with $3.6 million during the prior year period. The decrease reflects lower interest income of $1.8 million, again due primarily to lower cash balances, which is partially offset by increased transportation revenue of $0.5 million.

Costs and expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production cost per Mcfe for the three and six months ended June 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 June 30,				Quarter to quarter change		Six months ended June 30, 2005				Year to year change
(Unaudited, in thousands)	2005		2006		2005-2006		2005		2006		2005-2006

Oil and natural gas production costs:
Oil and natural gas operating costs:
U.S. (excluding Appalachia)	$	2,613	$	7,502	$	4,889	$	4,596	$	11,541	$	6,945
Appalachia	2,563		4,111		1,548		4,998		7,107		2,109
Total	$	5,176	$	11,613	$	6,437	$	9,594	$	18,648	$	9,054
Production and ad valorem taxes:
U.S. (excluding Appalachia)	1,508		$	3,807	$	2,299	$	3,002	$	7,002	$	4,000
Appalachia	910		967		57		1,787		2,222		435
Total	$	2,418	$	4,774	$	2,356	$	4,789	$	9,224	$	4,435
Total oil and natural gas production costs:
U.S. (excluding Appalachia)	$	4,121	$	11,309	$	7,188	$	7,598	$	18,543	$	10,945
Appalachia	3,473		5,078		1,605		6,785		9,329		2,544
Total	$	7,594	$	16,387	$	8,793	$	14,383	$	27,872	$	13,489

	Three months ended June 30,				Quarter to quarter change			Six months ended June 30, 2005				Year to year change
(Unaudited)	2005		2006		2005-2006			2005		2006		2005-2006

Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs:
U.S. (excluding Appalachia)	$	0.96	$	0.99	$	0.03		$	0.84	$	0.94	$	0.10
Appalachia	0.84		1.11		0.27			0.80		1.00		0.20
Total	0.90		1.03		0.13			0.82		0.96		0.14
Production and ad valorem taxes:
U.S. (excluding Appalachia)	$	0.55	$	0.50	$	(0.05	)	$	0.55	$	0.57	$	0.02
Appalachia.	0.30		0.26		(0.04		)	0.29		0.31		0.02
Total	0.42		0.42		—			0.41		0.48		0.07
Total oil and natural gas production costs:
U.S. (excluding Appalachia)	$	1.51	$	1.49	$	(0.02	)	$	1.39	$	1.51	$	0.12
Appalachia	1.14		1.37		0.23			1.09		1.31		0.22
Total	1.31		1.45		0.14			1.23		1.44		0.21

Our oil and natural gas operating costs for the three and six months ended June 30, 2006 increased $6.4 million and $9.1 million, respectively, or 124.4% and 94.4%, 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 $1.7 million and $6.3 million of operating costs for the three and six months ended June 30, 2006, respectively;

· impact of North Coast property acquisitions completed in the third quarter of 2005;

· an increase in salaries and related benefits due to an increase in the number of field employees related to the additional properties at North Coast;

· 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 development and exploitation capital program.

The oil and natural gas operating cost per unit for the U.S. (excluding Appalachia) segment increased from $0.90 and $0.82, respectively, per Mcfe for the three and six months ended June 30, 2005 to $1.03 and $0.96, respectively, per Mcfe, or 14.4% and 17.1%, respectively, for the three and six months ended June 30, 2006 which reflects the general increase in the costs of goods and services used in our operations and an increase in workover activities in the segment. The oil and natural gas operating cost per unit for Appalachia increased from $0.84 to $1.11, respectively, per Mcfe for the three months ended June 30, 2005 and 2006. For the six months ended June 30, 2005, operating costs per unit for Appalachia were $0.80 per equivalent Mcf, or 25% lower than the six months ended June 30, 2006 rate of $1.00 per equivalent Mcf. Overall, oil and natural gas operating costs increased due to higher personnel related costs as discussed above, an increase in repair and maintenance costs and a general increase in the costs of goods

and services used in our operations.

Production and ad valorem taxes for the three and six months ended June 30, 2006 increased by $2.4 million and $4.4 million, respectively, or 97.4% and 92.6%, respectively, over the three and six months ended June 30, 2005. These increases are primarily attributable and correspond to the increase in oil and natural gas revenues resulting from increased sales volumes and higher oil and natural gas sales prices. 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 six months ended June 30, 2006 increased by $21.4 million and $34.3 million, or 272.8% and 218.0%, 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 95.5% and 65.9% for the three and six months ended June 30, 2006, respectively. The per unit depletion rate increased from $1.36 per Mcfe for the three months ended June 30, 2005 to $2.59 per Mcfe for the three months ended June 30, 2006 and from $1.34 per Mcfe for the six months ended June 30, 2005 to $2.58 per Mcfe for the six months ended June 30, 2006, respectively.

The higher rate for the six months ended June 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 six months ended June 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 six months ended June 30, 2005 and 2006. The table also shows the changes in these amounts between periods.

	Three months ended June 30,						Quarter to quarter change
(unaudited, in thousands)	2005			2006			2005-2006

General and administrative costs:
Gross general and administrative expense	$	6,886		$	9,319		$	2,433
Operator overhead charges	(458		)	(2,005		)	(1,547		)
Capitalized acquisition and exploitation charges	(374		)	(784		)	(410		)
Net general and administrative expense	$	6,054		$	6,530		$	476

General and administrative expense per Mcfe	$	1.05		$	0.58		$	0.47

	Six months ended June 30,						Quarter to quarter change
(unaudited, in thousands)	2005			2006			2005-2006

General and administrative costs:
Gross general and administrative expense	$	12,873		$	16,994		$	4,121
Operator overhead charges	(881		)	(3,183		)	(2,302		)
Capitalized acquisition and exploitation charges	(734		)	(1,372		)	(638		)
Net general and administrative expense	$	11,258		$	12,439		$	1,181

General and administrative expense per Mcfe	$	0.96		$	0.64		$	0.32

Our general and administrative costs for the three and six months ended June 30, 2006 increased by $0.5 million, or 7.9% and $1.2 million, or 10.5%, respectively, over the same periods in 2005. The increases for the six months ended June 30, 2006 compared to the six months ended June 30, 2005 were due primarily to:

· increased personnel costs of $2.8 million from increased level of acquisition activity and the consolidation of TXOK and PGMT;

· expensed stock-based compensation costs of $1.7 million; and

· increased occupancy costs of $0.3 million resulting from expansion of corporate facilities.

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

· decreased legal and other professional services costs for the six months ended June 30, 2006 versus the same period in 2005 of $1.6 million as a result of extraordinarily high legal costs in the 2005 period resulting from fees incurred to consider an alternative business structure for us following the sale of Addison; and

· increased operator overhead recoveries of $2.3 million primarily resulting from the acquisition of TXOK.

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

	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Year to year
(Unaudited, in thousands)	2005		2006		2005-2006			2005		2006		2005-2006

Interest expense:
7¼% senior notes due 2011.	$	8,156	$	7,325	$	(831	)	$	16,108	$	14,661	$	(1,447	)
Credit agreements	91		4,282		4,191			342		5,461		5,119
Amortization and write-off of deferred financing costs	318		53		(265		)	866		6,667		5,801
Interim bank loan	—		—		—			—		1,216		1,216
Total interest expense	$	8,565	$	11,660	$	3,095		$	17,316	$	28,005	$	10,689

Our interest expense for the three months ended June 30, 2006 increased $3.1 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 six months ended June 30, 2006 increased by $10.7 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 $324.0 million at June 30, 2006 compared to $1,000 at June 30, 2005.

Income taxes

Our effective tax rate on income from continuing operations for the three and six months ended June 30, 2006 was 41.3% and 39.6%, respectively. Our effective tax rate on losses from continuing operations for the three months ended June 30, 2005 approximates 218.1%, 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 June 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 0.4% during the three months ended June 30, 2006. This increase was partly offset by phased-in reduced tax rates in Ohio. Although we had an increased presence in Texas and Oklahoma where state income tax rates are lower than in our Appalachia region, our net income was higher in Appalachia which increased our effective state rate for the quarter. 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 the effect of the change in the tax rate on our existing deferred tax balances in the current quarter. During the three months ended June 30, 2006, we recorded deferred income taxes relating to the Texas margin tax in the amount of $0.8 million.

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 six months ended June 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.

Our liquidity, capital resources and capital commitments

General

Most of our growth has resulted from recent acquisitions and our development and exploitation program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash 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 is a $1.25 billion facility with a $750.0 million borrowing base and a $500.0 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 its common stock pursuant to an exercise by the underwriters of their over-allotment option for net proceeds to EXCO Resources of approximately $44.7 million. The net proceeds were used to reduce outstanding indebtedness under EXCO Resources’ credit agreement.

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 $142.7 million for the six months ended June 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 June 30, 2006, our cash and cash equivalents balance was $39.4 million, a decrease of $187.5 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 second quarter asset and corporate acquisitions. On July 17, 2006, we made an interest payment on our 7¼% senior notes in the amount of $16.1 million.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the six months ended June 30, 2005 and 2006. Our acquisition of TXOK did not result in any property acquisition expenditures as the acquisition was consummated by the redemption of TXOK’s preferred stock and for the assumption of TXOK’s debt. The capital expenditures for the six months ended June 30, 2006 include capital expenditures of TXOK during the February 14, 2006 to June 30, 2006 period.

	Six months ended
	June 30,
	2005		2006
	(Unaudited, in thousands)
Capital expenditures:
Property acquisitions (excluding TXOK Acquisition, Inc.)	$	20,275	$	137,016
Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired, excluding debt and derivative financial instruments assumed	—		61,776
Lease purchases	751		1,444
Development capital expenditures	28,615		73,730
Other	2,669		4,060
Total capital expenditures	$	52,310	$	278,026

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

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 June 30, 2006, we were contractually obligated to spend $18.4 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 $59.7 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 Note 14. “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 July 24, 2006, we announced an agreement to acquire Winchester and its affiliated entities from Progress Energy, Inc. for $1.2 billion in cash, subject to 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 is expected to close on or about October 2, 2006. The acquisition will be financed with a $750 million term loan facility and a new revolving credit facility. We have formed a new subsidiary to purchase Winchester and that subsidiary will be classified as an Unrestricted Subsidiary as defined under our indenture governing our senior notes and our credit agreement. Concurrent with the closing of the purchase of Winchester, we currently intend to contribute to our acquisition subsidiary substantially all of our East Texas properties, with an estimated value of approximately $500 million, and related indebtedness of approximately $200 million. The subsidiary will not be a guarantor of our debt obligations nor will we guarantee the debt of this subsidiary. We currently intend to execute an equity offering by the subsidiary, through the sale of units representing limited partner interests, to repay this indebtedness.

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.

We expect to utilize our current cash balance, cash flow from operations and available funds under our credit agreement to fund our acquisitions, capital expenditures and working capital. During the first quarter of 2005, we sold non-strategic oil and natural gas properties (excluding the sale of Addison) for net proceeds of approximately $3.9 million. We also plan on selling additional 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 and oil and natural gas prices. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may affect our production in future periods. 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.

7 1/4% 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.

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

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.

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 are 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. 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. 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) 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 June 30, 2006, the six month LIBOR rates were 4.70% and 5.59% which would result in interest rates of approximately 5.95% and 6.59%, respectively, on any new indebtedness we may incur under the credit agreement. At December 31, 2005 and June 30, 2006, we had $1,000 and $324.0 million respectively, of outstanding indebtedness under our credit agreement. As of June 30, 2006, we had $176.0 million available under our credit agreement based on the current aggregate commitment of $500.0 million. As of August 7, 2006, we had $354.0 million of outstanding indebtedness under our credit agreement and $146.0 million was available to be drawn for future capital spending, including acquisitions, or other liquidity needs, based on our current aggregate commitment of $500.0 million.

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 June 30, 2006, we were in compliance with the covenants contained in our 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 six months ended June 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 June 30, 2006, we had contracts in place for the volumes and prices shown in the table below, which includes contracts we entered into since June 30, 2006.

	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)
Q3 2006	7,189	$	7.50	1,380	$	(0.32	)	174	$	70.81
Q4 2006	7,514	8.25		1,380	(0.32		)	173	71.02
2007	29,790	8.52		—	—			734	69.53
2008	25,140	8.51		—	—			327	62.67
2009	7,705	7.14		—	—			120	60.80
2010	6,985	6.63		—	—			108	59.85
2011	1,825	4.51		—	—			—	—
2012	1,830	4.51		—	—			—	—
2013	1,825	4.51		—	—			—	—

Floor

Ceiling

Weighted

average

NYMEX gas

contract

Oil

contract

NYMEX gas

contract

Oil

contract

volume -

price per

volume -

price per

volume -

price per

volume -

price per

Mmbtus

Mmbtu

Bbls

Bbl

Mmbtus

Mmbtu

Bbls

Bbl

(in thousands, except average contract prices)

Q3 2006

465

6.15

50.35

465

10.00

60.00

Q4 2006

—

50.35

—

60.00

We occasionally enter into fixed-price physical delivery contracts as well as commodity price swap derivatives to manage price risk with regard to a portion of our oil and natural gas production.

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

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

	Less than one year			One to three years		Three to five years		More than five years		Total
	(in thousands)
Contractual Obligations:
7 1/4% senior notes due 2011	$	—		$	—	$	444,720	$	—	$	444,720
Revolving credit agreement	—			—		324,000		—		324,000
Operating leases	3,533			6,864		3,245		395		14,036
Derivative financial instruments	(8,467		)	35,279		18,619		10,987		56,418
Drilling/work commitments	25,023			6,657		—		—		31,680
Total contractual cash obligations	$	20,089		$	48,800	$	790,584	$	11,382	$	870,854

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 July 31, 2006.

	Volume Mmbtu/Bbls	Weighted average strike price		Weighted average differential to NYMEX			Fair value at July 31, 2006 gain (loss)
	(in thousands, except prices and differentials)
Natural gas:
Swaps
Remainder of 2006	12,726	$	7.97				$	(11,986	)
2007	29,790	8.52					(36,347		)
2008	25,140	8.51					(13,940		)
2009	7,705	7.14					(9,216		)
2010	6,985	6.63					(8,060		)
2011	1,825	4.51					(4,412		)
2012	1,830	4.51					(3,726		)
2013	1,825	4.51					(3,130		)
	87,826

Basis protection swaps:
Remainder of 2006	2,295			$	(0.32	)	1,489
	2,295


Total natural gas							(89,328		)

Oil:
Swaps:
Remainder of 2006	287	70.98					(1,547		)
2007	734	69.53					(6,033		)
2008	327	62.67					(4,134		)
2009	120	60.80					(1,419		)
2010	108	59.85					(1,137		)
	1,576

Floor:
Remainder of 2006	45	50.35					0
	45

Ceiling:
Remainder of 2006	45	60.00					(734		)
	45

Total oil							(15,004		)

Total oil and natural gas							$	(104,332	)

At July 31, 2006, the average forward NYMEX oil prices per Bbl for the remainder of 2006 was $76.45 and $78.18 for 2007 and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2006 and for calendar 2007 were $8.93 and $9.82, 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 June 30, 2006, if the settlement price exceeded the actual weighted average strike price of $67.21, then a reduction in derivative financial instrument activities revenue would have been recorded for the difference between the settlement price and $67.21 multiplied by the hedged volume of 1,635 Mbbls. Conversely, if the settlement price was less than $67.21, then an increase in derivative financial instrument activities revenue would have been recorded for the difference between the settlement price and $67.21 multiplied by the hedged volume of 1,635 Mbbls. For example, for a hedged volume of 1,635 Mbbls, if the settlement price was $66.21, then derivative financial instrument activities revenue would have decreased by $1.6 million. Conversely, if the settlement price was $68.21, derivative financial instrument activities revenue would have increased by $1.6 million.

Interest rate risk

At June 30, 2006, our exposure to interest rates related primarily to borrowings under our credit agreement. The interest rate is fixed at 7¼% on our $444.7 million in senior notes. As of June 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 August 7, 2006, we had $354.0 million in outstanding borrowings under our credit agreement. 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 $3.5 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 June 30, 2006.

Due to the material weakness described below, our CEO and CFO continue to conclude that our disclosure controls and procedures were not effective as of June 30, 2006. As noted below, we believe we have taken the necessary steps to address the matters related to the material weakness. However, before concluding that the material weakness has been remediated, management believes that the new internal controls should be implemented and operational for a sufficient period of time to demonstrate that the controls are operating effectively. We believe our consolidated financial statements included in this quarterly report on Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles.

Material weakness in internal control over financing reporting

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 we have taken the necessary steps to address the matters related to the material weakness described above. However, before concluding that the material weakness has been remediated, management believes that the new internal controls should be implemented and operational for a sufficient period of time to demonstrate that the controls are operating effectively.

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 in internal control over financial reporting during the quarter ended June 30, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 6. Exhibits

EXHIBIT NUMBER		Description Of Exhibit
3.1		Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K dated February 8, 2006, 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, 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, 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.

4.4		Form of 7¼% Global Note Due 2011.**

4.5		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 February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.

4.6		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 February 16, 2005 and incorporated by reference herein.

4.7		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 Amendment No. 1 to its Current Report on Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

4.8		Fourth Supplemental Indenture by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Form 8-K dated May 4, 2006, filed on May 10, 2006 and incorporated by reference herein.

10.1		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.

10.2		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.*

10.3		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.

10.4		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 Amendment No. 1 to its Current Report on Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein

10.5		Form of 7¼% Global Note Due 2011.**

10.6		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.

10.7		Fifth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA (successor by merger to Bank One, N.A. (Illinois), as Administrative Agent for itself and the Lenders defined therein, dated December 15, 2005, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.

10.8		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, filed February 14, 2006 and incorporated by reference herein.

10.9		Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO’s Amendment No. 1 to its Form 8-K, dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

10.10		Guarantee, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., ROJO Pipeline, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Pinestone Resources, L.L.C., as Guarantors, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined herein, filed as an Exhibit to EXCO’s Amendment No. 1 to its Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

10.11		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 Amendment No. 1 to its Form 8-K dated February 8, 2006, filed on February

		21, 2006 and incorporated by reference herein.

10.12		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 Amendment No. 1 to its Form 8-K dated February 8, 2006, Form 8-K filed on February 21, 2006 and incorporated by reference herein.

10.13		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 Amendment No. 1 to its Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

10.14		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 Amendment No. 1 to its Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

10.15		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, filed on March 23, 2006 and incorporated by reference herein.

10.16		EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***

10.17		Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***

10.18		Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***

10.19		Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***

10.20		Fourth Supplemental Indenture by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Form 8-K dated May 4, 2006, filed on May 10, 2006 and incorporated by reference herein.
10.21		Agreement and Plan of Merger, dated July 22, 2006, by and among Winchester Energy Company, Ltd., Progress Fuels Corporation, WGC Holdco, LLC, and Winchester Acquisition, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006, filed on July 24, 2006, and incorporated herein by reference.

10.22		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, filed on July 24, 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 Form S-4 filed March 25, 2004 and incorporated by reference herein.

** Filed as an Exhibit to EXCO’s Pre-effective Amendment No. 1 to the Form S-4 filed April 20, 2004 and incorporated by reference herein.

*** These exhibits are management contracts.

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

For the quarterly period ended June 30, 2006

OR

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

Texas		74-1492779
(State of incorporation)		(I.R.S. Employer Identification No.)

12377 Merit Drive
Suite 1700, LB 82
Dallas, Texas		75251
(Address of principal executive offices)		(Zip Code)

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Condensed consolidated balance sheets at December 31, 2005 and June 30, 2006
	Condensed consolidated statements of operations for the three and six months ended June 30, 2005 and 2006
	Condensed consolidated statements of cash flows for the three and six months ended June 30, 2005 and 2006
	Condensed consolidated statements of changes in shareholders’ equity for the six months ended June 30, 2005 and 2006
	Notes to condensed consolidated financial statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures about Market Risk
Item 4.	Controls and Procedures


Part II.	OTHER INFORMATION
Item 6.	Exhibits
	Signatures
	Index to exhibits

	EXCO RESOURCES, INC.
	(Registrant)

Date: August 9, 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

EXHIBIT NUMBER		Description Of Exhibit
3.1		Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K dated February 8, 2006, 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, 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, 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.

4.4		Form of 7¼% Global Note Due 2011.**

4.5		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 February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.

4.6		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 February 16, 2005 and incorporated by reference herein.

4.7		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 Amendment No. 1 to its Current Report on Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

4.8		Fourth Supplemental Indenture by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Form 8-K dated May 4, 2006, filed on May 10, 2006 and incorporated by reference herein.

10.1		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.

10.2		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.*

10.3		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.

10.4		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 Amendment No. 1 to its Current Report on Form 8-K dated February 8, 2006, filed on February 21, 2006 and incorporated by reference herein.

10.5		Form of 7¼% Global Note Due 2011.**

10.6		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.

		incorporated by reference herein.***

10.19		Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***

10.20		Fourth Supplemental Indenture by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Form 8-K dated May 4, 2006, filed on May 10, 2006 and incorporated by reference herein .

10.21		Agreement and Plan of Merger, dated July 22, 2006, by and among Winchester Energy Company, Ltd., Progress Fuels Corporation, WGC Holdco, LLC, and Winchester Acquisition, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006, filed on July 24, 2006, and incorporated herein by reference.

10.22		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, filed on July 24, 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.