EXCO RESOURCES INC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

		For the quarterly period ended March 31, 2005

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

		For the transition period from to

Commission File Number 0-9204

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Texas		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)

(214) 368-2084

(Registrant’s telephone number, including area code)

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

YES ý NO o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YES o NO ý

The number of shares of common stock, par value $0.01 per share, outstanding at April 30, 2005 was 1,000.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	December 31, 2004			March 31, 2005
				(Unaudited)

Assets
Current assets:
Cash and cash equivalents	$	26,408		$	278,306
Accounts receivable:
Oil and natural gas sales	32,752			17,708
Joint interest	4,539			1,714
Income taxes and other	1,630			12,457
Deferred tax asset	3,121			—
Oil and natural gas derivatives	273			—
Marketable securities	69			65
Other	7,056			2,948
Total current assets	75,848			313,198
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	22,199			20,396
Proved developed and undeveloped oil and natural gas properties	794,844			481,378
Accumulated depreciation, depletion and amortization	(60,449		)	(38,884		)
Oil and natural gas properties, net	756,594			462,890
Gas gathering, office and field equipment, net	27,281			28,557
Goodwill	51,416			19,984
Deferred tax asset	—			12,744
Deferred financing costs, net and other assets	10,884			9,956
Total assets	$	922,023		$	847,329

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	December 31, 2004			March 31, 2005
				(Unaudited)

Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable and accrued liabilities	$	42,871		$	23,954
Accrued interest payable	14,959			6,489
Revenues and royalties payable	8,641			7,264
Income taxes payable	8,665			20,478
Deferred income taxes	710			4,921
Current portion of asset retirement obligations	2,418			1,781
Oil and natural gas derivatives	27,431			16,961
Total current liabilities	105,695			81,848
Long-term debt	47,396			1
7¼% senior notes due 2011	452,953			452,852
Asset retirement obligations and other long-term liabilities	26,330			11,772
Deferred income taxes	59,102			—
Oil and natural gas derivatives	26,796			26,243
Commitments and contingencies	—			—
Shareholder’s equity:
Common stock, $.01 par value: Authorized shares-100,000; Issued and outstanding shares-1,000 at December 31, 2004 and March 31, 2005	1			1
Additional paid-in capital	—			—
Capital contributed by EXCO Holdings Inc.	172,045			172,045
Retained earnings	10,338			102,583
Accumulated other comprehensive income:
Foreign currency translation adjustments	21,384			—
Unrealized loss on equity investments	(17		)	(16		)
Total shareholder’s equity	203,751			274,613
Total liabilities and shareholder’s equity	$	922,023		$	847,329

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)

	Three Months Ended March 31,
	2004			2005

Revenues and other income:
Oil and natural gas	$	28,667		$	38,929
Commodity price risk management activities	(23,562		)	(57,390		)
Other income	466			382
Total revenues and other income	5,571			(18,079		)
Cost and expenses:
Oil and natural gas production	6,465			6,789
Depreciation, depletion and amortization	6,053			7,856
Accretion of discount on asset retirement obligations	198			203
General and administrative	3,246			5,168
Interest	7,609			8,751
Total cost and expenses	23,571			28,767
Loss from continuing operations before income taxes	(18,000		)	(46,846		)
Income tax benefit	(6,705		)	(18,207		)
Loss from continuing operations	(11,295		)	(28,639		)
Discontinued operations:
Income (loss) from operations	3,981			(4,402		)
Gain on disposition of Addison Energy Inc.	—			174,086
Income tax expense	1,752			48,800
Income from discontinued operations	2,229			120,884
Net income (loss)	$	(9,066	)	$	92,245

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Three Months Ended March 31,
	2004			2005
Operating Activities:
Net income (loss)	$	(9,066	)	$	92,245
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain on sale of Addison Energy Inc.	—			(174,086		)
Foreign currency transaction loss	—			3,461
Depreciation, depletion and amortization	10,756			10,181
Accretion of discount on asset retirement obligations	416			332
Non-cash change in fair value of derivatives	22,863			(10,994		)
Deferred income taxes	(7,254		)	(25,346		)
Amortization of deferred financing costs	2,139			520
Losses from sales of marketable securities	1			—
Effect of changes in:
Accounts receivable	4,043			(9,423		)
Other current assets	1,068			1,291
Accounts payable and other current liabilities	4,100			(3,460		)
Net cash provided by (used in) operating activities	29,066			(115,279		)
Investing Activities:
Acquisition of North Coast Energy, Inc. less cash acquired	(215,055		)	—
Additions to oil and natural gas properties, gathering systems and equipment	(27,548		)	(33,395		)
Proceeds from disposition of property and equipment	6,846			3,914
Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415	—			443,649
Advances/investments with affiliates	(13		)	50
Proceeds from sales of marketable securities	781			—
Other investing activities	(15		)	—
Net cash provided by (used in) investing activities	(235,004		)	414,218
Financing Activities:
Proceeds from long-term debt	357,101			100,901
Payments on long-term debt	(118,469		)	(148,247		)
Deferred financing costs	(11,219		)	305
Net cash provided by (used in) financing activities	227,413			(47,041		)
Net increase in cash	21,475			251,898
Cash at beginning of period	7,333			26,408
Effect of exchange rates on cash and cash equivalents	(161		)	—
Cash at end of period	$	28,647		$	278,306

Supplemental Cash Flow Information:
Interest paid	$	1,961		$	16,695
Income taxes paid	$	786		$	37,290

See accompanying notes.

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2005

(Unaudited)

1. Basis of Presentation

EXCO Resources, Inc., a Texas corporation, was formed in 1955. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States and, until February 10, 2005, in Canada. We also act as the operator of most of these properties and receive overhead reimbursement fees as a result.

The accompanying condensed consolidated balance sheets as of December 31, 2004 and March 31, 2005 and the results of operations, cash flows and comprehensive income for the three months ended March 31, 2004 and 2005 are for EXCO and its subsidiaries. All intercompany transactions have been eliminated. Our results of operations for the three months ended March 31, 2004 have been reclassified to reflect the results of our former Canadian subsidiary, Addison Energy Inc., (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 Securities and Exchange Commission. 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, 2004.

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

Stock Options

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

Certain of our employees have been granted stock options under our parent company’s (EXCO Holding’s Inc., or Holdings) 2004 Long-Term Incentive Plan (the Holdings Plan). The Holdings Plan provides for grants of stock options that can be exercised for Class A common shares of Holdings. The stock options vest upon the earlier of specified events or three years from the date of grant and expire ten years after the date of grant. Holdings has reserved 12,962,968 shares of its Class A common stock for issuance upon the exercise of stock options. As of March 31, 2005, options for 8,801,354 shares of common stock have been granted by Holdings.

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

Under the minimum value method as prescribed under SFAS No. 123, no compensation expense would have been incurred under SFAS No. 123 during the three months ended March 31, 2005 from the granting of these stock options and as such, no pro forma disclosure is required.

SFAS No. 123(R), “Share-Based Payment”, was issued December 16, 2004, and is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB No. 25 and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R)

will require all share-based payments to employees, including grants of employee stock options, to be recognized in our consolidated statements of operations based on their estimated fair values. Pro forma disclosure is no longer an alternative.

SFAS No. 123(R) must be adopted by us effective January 1, 2006 and permits public companies to adopt its requirements using one of two methods:

• A “modified prospective” method in which compensation cost is recognized based on the requirements of SFAS No. 123(R) for all share-based payments granted prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date.

• A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures.

As permitted by SFAS No. 123, we currently account for share-based payments to employees using the intrinsic value method prescribed by APB No. 25 and related interpretations. As such, we generally do not recognize compensation expense associated with employee stock options. Accordingly, the adoption of SFAS No. 123(R)’s fair value method could have a significant impact on our future results of operations, although it will have no impact on our overall financial position. We currently plan to adopt the provisions of SFAS No. 123(R), but we have not completed evaluating the impact the adoption of SFAS No. 123(R) will have on our future results of operations.

Foreign Currency Translation

In April 2004, Addison, our Canadian wholly-owned subsidiary, entered into a long-term note agreement with a U.S. subsidiary of EXCO in the amount of $98.8 million. Addison used the proceeds of this borrowing to repay virtually all of its then outstanding indebtedness under its Canadian credit agreement in April 2004. The Addison note, which was denominated in U.S. dollars was repaid in full on February 10, 2005 upon the sale of Addison (See “Note 2. Sale of Addison Energy Inc.”). Under the provisions of SFAS No. 52, “Foreign Currency Translation”, Addison was required to recognize any foreign transaction gains or losses in its statement of operations when translating this liability from U.S. dollars to Canadian dollars. Gain or loss recognized by Addison was not eliminated when preparing EXCO’s consolidated statement of operations. As a result, the loss from discontinued operations in the condensed consolidated statements of operations for the three months ended March 31, 2005 includes non-cash foreign currency transaction gains of $3.5 million.

2. Sale of Addison Energy Inc.

On January 17, 2005, our directors approved the Share and Debt Purchase Agreement (the Addison Purchase Agreement), dated effective January 12, 2005, among 1143928 Alberta Ltd., a corporation organized under the laws of the Province of Alberta (Purchaser) and a wholly-owner subsidiary of NAL Oil & Gas Trust, an Alberta trust, EXCO and our wholly-owned subsidiary, ROJO Pipeline, Inc. (ROJO), formerly known as Taurus Acquisition, Inc. (Taurus). The Addison Purchase Agreement provided that EXCO would sell to Purchaser all of the issued and outstanding shares of common stock of Addison, our wholly-owned subsidiary through which all of our Canadian operations were conducted. 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, before contractual adjustments, for the stock and the Addison Notes was Cdn. $553.3 million (U.S. $445.1 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 potential income taxes that we may owe resulting from the sale of the stock. We have recorded a receivable in the amount of Cdn. $14.6 million (U.S. $11.7 million) for our estimate of the excess of the amount withheld for Canadian income taxes from the sales proceeds and the estimated amount of Canadian income taxes that are actually owed on the gain from the sale. The purchase price is subject to further adjustment based upon, among other items, the final determination of Addison’s working capital balance as of February 1, 2005. This working capital balance adjustment has not yet occurred as of the filing of this quarterly report. We have, however, established a current liability in the amount of Cdn. $3.9 million, (U.S. $3.2 million) for our estimate of the working capital adjustment which reduced the gain that we recognized on the sale. The purchase price is also subject to additional adjustments based upon the outcome of Crown royalty and joint venture audits, if any, which may occur in the future which covers periods prior to February 1, 2005.

All severance payments paid or payable in respect of employees terminated up to May 31, 2005 will be borne by EXCO. If Purchaser or its affiliates makes an employment offer to a terminated employee and the employee accepts the offer, Purchaser is obligated to pay EXCO an amount equal to all severance payments paid to that employee. This obligation is 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 paid for severance payments made to Addison employees who were terminated at closing.

We have recognized a gain from the sale of Addison in the amount of U.S. $174.1 million before income tax expense of U.S. $49.6 million related to the gain. The cumulative adjustment resulting from the translation of Addison’s financial statements has been eliminated. These amounts were considered in the determination of the gain on the sale.

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

Cash	$	10,401
Other current assets	24,406
Oil and natural gas properties, net	315,144
Gas gathering, office and field equipment, net	267
Goodwill	31,432
Other assets	83
Total assets	381,733
Current liabilities	34,604
Long-term debt	12,896
Deferred income taxes	43,308
Other liabilities.	15,631
Total liabilities	106,439
Net investment in Addison	$	275,294

In accordance with the terms of the indenture governing our senior notes (see “Note 8. Issuance of Senior Notes and the Acquisition of North Coast Energy, Inc.”), at the time of the closing of the Addison disposition, the security interest of the holders of our senior notes in two-thirds of the common stock of Addison was released and a second lien security interest (behind the first lien security interest under our U.S. credit agreement) was effected in U.S. $120.6 million, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. An additional U.S. $75.8 million of proceeds from the Addison disposition were applied to temporarily pay down borrowings under our U.S. credit agreement to a nominal amount. The remaining Addison disposition proceeds of U.S. $130.3 million have been invested in short-term investments as permitted under our U.S. credit agreement and our senior notes. The net cash proceeds from the Addison disposition as determined under the indenture governing

our senior notes was U.S. $326.8 million and may be used only in accordance with the terms of the indenture. Section 4.07 of indenture provides that the net cash proceeds from an asset disposition must be used to permanently reduce debt, reinvest in our business or make an offer to the holders to repurchase their senior notes. We are evaluating a number of strategic alternatives to utilize the net cash proceeds from the sale of Addison. The strategic alternatives being evaluated include, among other things: (1) an issuance of EXCO Holdings’ equity securities; (2) a leveraged recapitalization of EXCO Holdings, which would include an equity buyout; (3) a spin-off of our Appalachian properties into a master limited partnership; (4) payment of a dividend to EXCO Holdings’ shareholders; or (5) no restructuring or recapitalization and retention of the cash from the sale of Addison to continue our acquisition and development program. There can be no assurance that any of these strategic alternatives, or any transaction, will be pursued or, if a transaction is pursued, that it will be consummated.

3. Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligations as of March 31, 2004 and 2005 (in thousands of dollars):

	Three Months Ended March 31,
	2004			2005
	(Unaudited)

Asset retirement obligation at January 1	$	17,742		$	28,043
Activity during the three months ended March 31:
Sale of Addison Energy Inc.	—			(14,796		)
Liabilities incurred during period	7,883			194
Liabilities settled during period	(128		)	(845		)
Accretion of discount	416			203
Effect of foreign currency conversions	(101		)	—
Asset retirement obligation as of March 31	25,812			12,799
Less current portion	1,325			1,781
Long-term portion	$	24,487		$	11,018

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

4. Oil and Natural Gas Properties

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

Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not Proved Reserves can be assigned to such properties. At December 31, 2004 and March 31, 2005, $22.2 million, of which $3.4 million was for Addison properties, and $20.4 million, respectively, in unproved oil and natural gas properties was 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.

	EXCO			North Coast			Total United States			Addison		Total
	(In thousands)
Three months ended March 31, 2004:
Revenues and other income:
Oil and natural gas	$	16,317		$	12,350		$	28,667		$	—	$	28,667
Commodity price risk management activities	(12,102		)	(11,460		)	(23,562		)	—		(23,562		)
Other income	322			144			466			—		466
Total revenues and other income	4,537			1,034			5,571			—		5,571

Cost and expenses:
Oil and natural gas production	4,601			1,864			6,465			—		6,465
Depreciation, depletion and amortization	3,530			2,523			6,053			—		6,053
Accretion of discount on asset retirement obligations	132			66			198			—		198
General and administrative	2,590			656			3,246			—		3,246
Interest	7,549			60			7,609			—		7,609
Total cost and expenses	18,402			5,169			23,571			—		23,571
Income (loss) from continuing operations before income taxes	(13,865		)	(4,135		)	(18,000		)	—		(18,000		)
Income tax expense (benefit)	(4,871		)	(1,834		)	(6,705		)	—		(6,705		)
Income (loss) from continuing operations	(8,994		)	(2,301		)	(11,295		)	—		(11,295		)
Discontinued operations:
Income from operations	—			—			—			3,981		3,981
Income tax expense	—			—			—			1,752		1,752
Income from discontinued operations	—			—			—			2,229		2,229
Net income (loss)	$	(8,994	)	$	(2,301	)	$	(11,295	)	$	2,229	$	(9,066	)
Total assets at end of period	$	242,010		$	241,634		$	483,644		$	286,624	$	770,268
Goodwill at end of period	$	23,831		$	—		$	23,831		$	28,854	$	52,685

	EXCO			North Coast			Total United States			Addison			Total
	(In thousands)
Three months ended March 31, 2005:
Revenues and other income:
Oil and natural gas	$	16,186		$	22,743		$	38,929		$	—		$	38,929
Commodity price risk management activities	(19,600		)	(37,790		)	(57,390		)	—			(57,390		)
Other income	225			157			382			—			382
Total revenues and other income	(3,189		)	(14,890		)	(18,079		)	—			(18,079		)

Cost and expenses:
Oil and natural gas production	3,477			3,312			6,789			—			6,789
Depreciation, depletion and amortization	3,758			4,098			7,856			—			7,856
Accretion of discount on asset retirement obligations	95			108			203			—			203
General and administrative	3,956			1,212			5,168			—			5,168
Interest	8,751			—			8,751			—			8,751
Total cost and expenses	20,037			8,730			28,767			—			28,767
Loss from continuing operations before income taxes	(23,226		)	(23,620		)	(46,846		)	—			(46,846		)
Income tax benefit	(7,830		)	(10,377		)	(18,207		)	—			(18,207		)
Loss from continuing operations	(15,396		)	(13,243		)	(28,639		)	—			(28,639		)
Discontinued operations:
Loss from discontinued operations	—			—			—			(4,402		)	(4,402		)
Gain on disposition of Addison Energy Inc.	—			—			—			174,086			174,086
Income tax expense	—			—			—			48,800			48,800
Income from discontinued operations	—			—			—			120,884			120,884
Net income (loss)	$	(15,396	)	$	(13,243	)	$	(28,639	)	$	120,884		$	92,245
Total assets at end of period	$	527,517		$	319,812		$	847,329		$	—		$	847,329
Goodwill at end of period	$	19,984		$	—		$	19,984		$	—		$	19,984

6. 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,” 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 commodity price risk management contracts upon 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 commodity price risk management contracts for increased volumes and with higher underlying product prices. The following table sets forth our oil and natural gas derivatives as of March 31, 2005. The fair values at March 31, 2005 are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at March 31, 2005. 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.

	Volume Mmbtus/Bbls	Weighted Average Strike Price per Mmbtu/Bbl		Weighted Average Differential to NYMEX			Fair Value at March 31, 2005
	(In thousands, except prices and differentials)
Natural Gas:
Swaps:
Remainder of 2005	11,413	$	6.89				$	(11,186	)
2006	13,323	6.78					(11,640		)
2007	11,680	6.47					(6,545		)
2008	2,745	4.55					(4,881		)
2009	1,825	4.51					(2,540		)
2010	1,825	4.51					(1,893		)
2011	1,825	4.51					(1,552		)
2012	1,830	4.51					(1,272		)
2013	1,825	4.51					(1,016		)
	48,291
Basis Protection Swaps:
Remainder of 2005	535			$	(0.75	)	36
	535
Floor Prices:
Remainder of 2005	798	4.25					1
Total Natural Gas	798						(42,488		)

Oil:
Swaps:
Remainder of 2005	165	52.84					(616		)
	165
Total Oil							(616		)
Total Oil and Natural Gas							$	(43,104	)

At March 31, 2005, the average forward NYMEX oil prices per Bbl for the remainder of calendar 2005 was $55.29 and the average forward NYMEX natural gas price per Mmbtu for the remainder of calendar 2005 and 2006 were $7.47 and $7.21, respectively.

7. Credit Agreements

U.S. Credit Agreement. On January 27, 2004, our U.S. credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the U.S. credit agreement maturity date to January 27, 2007. Upon the issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004, the U.S. credit agreement borrowing base was reduced to $95.0 million. (See “Note 8. Issuance of Senior Notes and the Acquisition of North Coast Energy, Inc.”). Effective June 28, 2004, the borrowing base was redetermined at $145.0 million. Effective October 8, 2004, the borrowing base was redetermined at $145.0 million. The borrowing base is currently being redetermined and management does not expect a decrease in the existing amount. The borrowing base will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At March 31, 2005, we

had $1,000 of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $144.7 million available for borrowing. Borrowings under our amended and restated U.S. credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast Energy, Inc. (North Coast). In addition, a first lien security interest was effected in $120.6 million of cash equivalents, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. At our election, interest on borrowings may be (i) the greater of the administrative agent’s prime rate or the federal funds effective rate plus 0.50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At March 31, 2005, the six month LIBOR rate was 3.40%, which would result in an interest rate of approximately 4.65% on any new indebtedness we may incur under the U.S. credit agreement.

Canadian Credit Agreement. On January 27, 2004, our Canadian credit agreement was amended and restated to provide for borrowings up to $189.4 million with a borrowing base of approximately $105.0 million (Cdn. $138.6 million using the exchange rate on January 26, 2004). The amendment also provided for an extension of the Canadian credit agreement maturity date to January 27, 2007. The issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004 did not impact the borrowing base under the Canadian credit agreement. (See “Note 8. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc.”). Effective June 28, 2004, the borrowing base was redetermined at $105.0 million (Cdn. $141.7 million using the exchange rate on June 25, 2004). Effective October 8, 2004, the borrowing base was redetermined at $105.0 million (Cdn. $132.4 million using the exchange rate on October 7, 2004). This facility was repaid in full and terminated on February 10, 2005 in conjunction with the sale of Addison.

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

• maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our U.S.credit agreement) of at least 1.0 to 1.0 at the end of any fiscal quarter;

• not permit our ratio of consolidated funded debt to consolidated EBITDA (as defined under our U.S. credit agreement) to be greater than (i) 4.35 to 1.00 at the end of each fiscal quarter ending on or before March 31, 2005 and (ii) 4.00 to 1.00 on June 30, 2005 and at the end of each fiscal quarter thereafter;

• not permit our ratio of consolidated funded debt (other than the senior notes) to consolidated EBITDA (as defined under our U.S. credit agreement) to be greater than (i) 3.25 to 1.0 at the end of each fiscal quarter ending prior to June 30, 2004 and (ii) 3.00 to 1.00 on June 30, 2004 and at the end of each fiscal quarter thereafter; and

• not permit our ratio of consolidated EBITDA to consolidated interest expense (as defined under our U.S. credit agreement) to be less than 2.5 to 1.0 at the end of each fiscal quarter.

Additionally, the U.S. 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 prohibits the payment of dividends on our common stock.

As of March 31, 2005, we were in compliance with the covenants contained in our U.S. credit agreement.

U.S. Senior Term Loan. On October 17, 2003, we entered into a $50.0 million senior term credit agreement. We borrowed all $50.0 million under the senior term credit agreement and we used the proceeds to repay a portion of our indebtedness under our U.S. credit agreement. The U.S. senior term loan was paid in full on January 27, 2004 from the proceeds of the $350 million 7¼% senior notes issued on January 20, 2004. See “Note 8. Issuance of Senior Notes and the Acquisition of North Coast Energy, Inc.”

Dividend Restrictions. We have not paid any cash dividends on our common stock, and do not anticipate

paying cash dividends on our common stock in the foreseeable future. In addition, our U.S. credit agreement currently prohibits us from paying dividends on our common stock. Even if our U.S. credit agreement permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

8. Issuance of Senior Notes and the Acquisition of North Coast Energy, Inc.

We acquired all of the outstanding common stock, options and warrants of North Coast Energy, Inc. (North Coast) pursuant to a tender offer and merger on January 27, 2004 for a purchase price of $167.8 million and we assumed $57.0 million of North Coast’s outstanding indebtedness. As a result, on January 27, 2004, North Coast became a wholly-owned subsidiary and established a new core operating area for us in the Appalachian Basin. We have accounted for the North Coast acquisition using the purchase method of accounting and have consolidated its operations effective January 27, 2004.

On January 20, 2004, we completed the private placement of $350.0 million aggregate principal amount of 7¼% senior notes due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 100% of the principal amount. The net proceeds of the offering were used to acquire North Coast, pay down debt under our credit facilities and North Coast’s credit facility, repay our senior term loan in full and pay fees and expenses associated with those transactions.

On April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of 7¼% senior notes due 2011 pursuant to Rule 144A, having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued on April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. The net proceeds of the April 13, 2004 offering were used to repay substantially all of our outstanding indebtedness under our Canadian credit agreement and pay fees and expenses associated therewith.

On May 28, 2004, we concluded an exchange offer of $450.0 million aggregate principal amount of our 7¼% senior notes due 2011, which were privately placed in January and April 2004, for $450.0 million aggregate principal amount of our 7¼% senior notes due 2011 that have been registered under the Securities Act. Holders of all but $300,000 of the senior notes elected to accept our exchange offer.

Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. We made interest payments on July 15, 2004 and January 18, 2005 in the amounts of $15.9 million and $16.3 million, respectively. 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 notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the notes. If a change of control occurs, subject to certain conditions, we must offer holders of the notes an opportunity to sell us their notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

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

• incur or guarantee additional debt and issue certain types of preferred stock;

• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;

• make investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

• create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

• consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.

The estimated fair value of our 7¼% senior notes due 2011 was $459.0 million as compared to the carrying amount of $452.9 million (including $2.9 million of unamortized premium) at March 31, 2005. The fair value of the senior notes is estimated based on quoted market prices for the senior notes.

Concurrent with the issuance of the senior notes, we wrote-off $938,000 of costs incurred in January 2004 to secure bridge loan financing which was not utilized upon issuance of the senior notes and deferred financing costs of approximately $726,000 related to the senior term loan, which was retired with the proceeds of the senior notes. These amounts are reflected in the Condensed Consolidated Statement of Operations as interest expense.

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

Purchase price calculations:
Payments for tendered shares including options and warrants	$	167,781
Assumption of debt including interest	57,149
Merger related costs	155
Total North Coast acquisition costs (before cash acquired)	$	225,085

Allocation of purchase price:
Oil and natural gas properties - proved	$	192,035
Oil and natural gas properties - unproved	7,258
Gas gathering assets and other equipment	21,454
Cash	10,429
Other assets	412
Deferred income tax asset	942
Other current assets	11,080
Accounts payable and accrued expenses	(10,340		)
Asset retirement obligations	(5,639		)
Liabilities from commodity price risk management activities	(2,546		)
Total allocation	$	225,085

The following table reflecting the pro forma results of operations for the three months ended March 31, 2004 has been derived from our unaudited consolidated statement of operations for the three months ended March 31, 2004 and North Coast’s unaudited consolidated financial statement for the 26 day period from January 1 to January 26, 2004. The pro forma results of operations give effect to the following events as if each occurred on

January 1, 2004.

• Our acquisition of North Coast for a purchase price of approximately $225.1 million. The North Coast acquisition was accounted for using the purchase method of accounting in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations.” Accordingly, EXCO’s historical financial statements reflect the allocation of the purchase price to the underlying assets and liabilities based upon their estimated fair values. For tax purposes we also received a step up in tax basis equal to the purchase price.

• Adjustments to conform North Coast’s historical accounting policies related to oil and natural gas properties from successful efforts to full cost accounting.

• The issuance of $350.0 million in senior notes.

• The assumption of North Coast’s debt and repayment of our and North Coast’s credit facilities.

• The payment of our related fees and expenses.

During North Coast’s 26-day period from January 1, 2004 to January 26, 2004, there were $11.9 million in investment banking fees, employee bonus and severance payments and other costs incurred in connection with the merger with EXCO that have been recognized as an increase in net loss in the following table.

	Three Months Ended March 31, 2004
	(In thousands, unaudited)

Revenues and other income	$	12,281
Net loss	(18,138		)

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

9. Acquisitions and Dispositions

Transactions, other than the sale of Addison, that occurred during the three months ended March 31, 2005

During the three months ended March 31, 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 U.S. credit agreement and from surplus cash. In addition, we also acquired a small natural gas gathering system for $700,000 as part of this acquisition.

During the first three 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. During the first three months of 2004 and 2005, revenues, oil and natural gas production costs and depletion expense related to these properties were not significant.

Transactions, other than the acquisition of North Coast, that occurred during the three months ended March 31, 2004

During the three months ended March 31, 2004, we completed one natural gas property acquisition in the United States. Estimated total proved reserves net to our interest from this acquisition included approximately 2.9 Bcf of natural gas. The purchase price for the acquisition was approximately $3.3 million funded from surplus cash.

During the three months ended March 31, 2004, we completed three sales of oil and natural gas properties in the United States. As of January 1, 2004, estimated total proved reserves, net to our interest from these properties included approximately 92.6 Mbbls of oil and NGLs and 4.9 Bcf of natural gas. The total sales proceeds we received were approximately $6.6 million. During the first three months of 2004, we recorded revenue of approximately $297,000, oil and natural gas production costs of $92,000 and depletion expense of $65,000 on these properties through the date of their respective dispositions.

10. 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 unsecured 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 senior notes were also secured by a second-priority security interest in 100% of the capital stock of ROJO Pipeline, Inc., (formerly Taurus Acquisition, Inc.), which was the payee on two intercompany promissory notes made by Addison. These notes were sold to the purchaser in the Addison sale transaction. As required by the indenture governing the senior notes, a second-priority security interest was established through a pledge of two-thirds of the net cash proceeds from the sale of the Addison stock. The remaining net cash proceeds not pledged under the indenture are restricted as to their use in accordance with the indenture.

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.

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. As of January 27, 2004, North Coast Energy, Inc. and North Coast Energy Eastern, Inc. became guarantors of our senior notes. As of December 21, 2004, Pinestone Resources, LLC became a guarantor of our senior notes.

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEETS (Unaudited)

December 31, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	8,535		$	7,472		$	10,401		$	—		$	26,408
Other current assets	12,132			12,902			24,406			—			49,440
Total current assets	20,667			20,374			34,807			—			75,848
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	783			18,046			3,370			—			22,199
Proved developed and undeveloped oil and natural gas properties	70,569			383,759			340,516			—			794,844
Allowance for depreciation, depletion and amortization	(9,592		)	(22,115		)	(28,742		)	—			(60,449		)
Oil and natural gas properties, net	61,760			379,690			315,144			—			756,594
Gas gathering, office and field equipment, net	1,935			25,079			267			—			27,281
Goodwill	19,984			—			31,432			—			51,416
Investments in and advances to affiliates	658,198			—			—			(658,198		)	—
Other assets, net	10,779			22			83			—			10,884
Total assets	$	773,323		$	425,165		$	381,733		$	(658,198	)	$	922,023

Liabilities and Shareholder’s Equity
Current liabilities	$	60,807		$	10,284		$	34,604		$	—		$	105,695
Long-term debt	487,453			—			12,896			—			500,349
Deferred income taxes	7,448			8,346			43,308			—			59,102
Other liabilities	30,532			6,963			15,631			—			53,126
Payable to parent	(16,668		)	286,500			191,702			(461,534		)	—
Commitments and contingencies	—			—			—			—			—
Shareholder’s equity	203,751			113,072			83,592			(196,664		)	203,751
Total liabilities and shareholder’s equity	$	773,323		$	425,165		$	381,733		$	(658,198	)	$	922,023

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEETS (Unaudited)

March 31, 2005

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	261,721		$	16,585		$	—	$	—		$	278,306
Other current assets	22,812			12,080			—		—			34,892
Total current assets	284,533			28,665			—		—			313,198
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	—			20,396			—		—			20,396
Proved developed and undeveloped oil and natural gas properties	65,609			415,769			—		—			481,378
Allowance for depreciation, depletion and amortization	(10,861		)	(28,023		)	—		—			(38,884		)
Oil and natural gas properties, net	54,748			408,142			—		—			462,890
Gas gathering, office and field equipment, net	2,033			26,524			—		—			28,557
Goodwill	19,984			—			—		—			19,984
Investments in and advances to affiliates	427,584			—			—		(427,584		)	—
Deferred tax asset	1,426			11,318			—		—			12,744
Other assets, net	9,934			22			—		—			9,956
Total assets	$	800,242		$	474,671		$	—	$	(427,584	)	$	847,329

Liabilities and Shareholder’s Equity
Current liabilities	$	50,967		$	30,881		$	—	$	—		$	81,848
Long-term debt	452,853			—			—		—			452,853
Other liabilities	21,809			16,206			—		—			38,015
Payable to parent	—			322,996			—		(322,996		)	—
Commitments and contingencies	—			—			—		—			—
Shareholder’s equity	274,613			104,588			—		(104,588		)	274,613
Total liabilities and shareholder’s equity	$	800,242		$	474,671		$	—	$	(427,584	)	$	847,329

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Three Months Ended March 31, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues and other income:
Oil and natural gas sales	$	10,595		$	18,072		$	—	$	—		$	28,667
Commodity price risk management activities	(12,102		)	(11,460		)	—		—			(23,562		)
Other income (loss)	1,036			144			—		(714		)	466
Equity in earnings of subsidiaries	2,379			—			—		(2,379		)	—
Total revenues and other income	1,908			6,756			—		(3,093		)	5,571

Costs and expenses:
Oil and natural gas production	3,630			2,835			—		—			6,465
Depreciation, depletion and amortization	1,975			4,078			—		—			6,053
Accretion of discount on asset retirement obligations	101			97			—		—			198
General and administrative	2,590			656			—					3,246
Interest	7,549			774			—		(714		)	7,609
Total costs and expenses	15,845			8,440			—		(714		)	23,571
Income (loss) from continuing operations before income taxes	(13,937		)	(1,684		)	—		(2,379		)	(18,000		)
Income tax expense (benefit)	(4,871		)	(1,834		)	—		—			(6,705		)
Income (loss) from continuing operations	(9,066		)	150			—		(2,379		)	(11,295		)
Discontinued operations:
Income from operations	—			—			3,981		—			3,981
Income tax expense	—			—			1,752		—			1,752
Income from discontinued operations	—			—			2,229		—			2,229
Net income (loss)	$	(9,066	)	$	150		$	2,229	$	(2,379	)	$	(9,066	)

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Three Months Ended March 31, 2005

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues and other income:
Oil and natural gas sales	$	6,250		$	32,679		$	—		$	—		$	38,929
Commodity price risk management activities	(19,600		)	(37,790		)	—			—			(57,390		)
Other income	2,012			280			—			(1,910		)	382
Equity in earnings of subsidiaries	(11,724		)	—			—			11,724			—
Total revenues and other income	(23,062		)	(4,831		)	—			9,814			(18,079		)

Costs and expenses:
Oil and natural gas production	2,271			4,518			—			—			6,789
Depreciation, depletion and amortization	1,319			6,537			—			—			7,856
Accretion of discount on asset retirement obligations	80			123			—			—			203
General and administrative	3,955			1,213			—			—			5,168
Interest	8,854			1,807			—			(1,910		)	8,751
Total costs and expenses	16,479			14,198			—			(1,910		)	28,767
Income (loss) from continuing operations before income taxes	(39,541		)	(19,029		)	—			11,724			(46,846		)
Income tax benefit	(7,830		)	(10,377		)	—			—			(18,207		)
Income (loss) from continuing operations	(31,711		)	(8,652		)	—			11,724			(28,639		)
Discontinued operations:
Loss from operations	—			—			(4,402		)	—			(4,402		)
Gain on disposition of Addison Energy Inc.	174,086			—			—			—			174,086
Income tax expense	50,130			—			(1,330		)	—			48,800
Income from discontinued operations	123,956			—			(3,072		)	—			120,884
Net income (loss)	$	92,245		$	(8,652	)	$	(3,072	)	$	11,724		$	92,245

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

For the Three Months Ended March 31, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by operating activities	$	1,375		$	14,012		$	13,679		$	—	$	29,066
Investing Activities:
Acquisition of North Coast Energy, Inc. less cash acquired	(225,484		)	10,429			—			—		(215,055		)
Additions to oil and natural gas properties, gathering systems and equipment	(4,387		)	(6,292		)	(16,869		)	—		(27,548		)
Proceeds from disposition of property and equipment	6,846			—			—			—		6,846
Proceeds from sales of marketable securities	781			—			—			—		781
Advances/investments with affiliates	(7,376		)	(8,584		)	15,947			—		(13		)
Other investing activities	—			—			(15		)	—		(15		)
Net cash used in investing activities	(229,620		)	(4,447		)	(937		)	—		(235,004		)
Financing Activities:
Proceeds from long-term debt	357,101			—			—			—		357,101
Payments on long-term debt	(106,570		)	—			(11,899		)	—		(118,469		)
Deferred financing costs	(11,213		)	—			(6		)	—		(11,219		)
Net cash provided by (used in) financing activities	239,318			—			(11,905		)	—		227,413
Net increase in cash	11,073			9,565			837			—		21,475
Cash at beginning of period	3,372			—			3,961			—		7,333
Effect of exchange rates on cash and cash equivalents	—			—			(161		)	—		(161		)
Cash at end of period	$	14,445		$	9,565		$	4,637		$	—	$	28,647

Supplemental Cash Flow Information:
Interest paid	$	513		$	92		$	1,356		$	—	$	1,961
Income taxes paid	$	—		$	—		$	786		$	—	$	786

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

For the Three Months Ended March 31, 2005

	Resources			Guarantor Subsidiaries				Non-Guarantor Subsidiaries				Eliminations			Consolidated
	(In thousands)
Operating Activities:
Net cash used by operating activities	$	(84,545	)	$	(11,576		)	$	(19,158		)	$	—		$	(115,279		)
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(19,130		)	(13,821			)	(444			)	—			(33,395			)
Proceeds from disposition of property and equipment	3,914			—				—				—			3,914
Proceeds from sale of Addison Energy Inc., net of cash sold	445,064			—				(1,415			)	—			443,649
Advances/investments with affiliates	14,526			34,509				(48,985			)	—			50
Net cash provided by (used in) investing activities	444,374			20,688				(50,844			)	—			414,218
Financing Activities:
Proceeds from long-term debt	41,300			—				59,601				—			100,901
Payments on long-term debt	(148,247		)	—				—				—			(148,247			)
Deferred financing costs	305			—				—				—			305
Other financing activities	—			—				—				—			—
Net cash provided by (used in) financing activities	(106,642		)	—				59,601				—			(47,041			)
Net increase (decrease) in cash	253,187			9,112				(10,401			)	—			251,898
Cash at beginning of period	8,535			7,472				10,401				—			26,408
Cash at end of period	$	261,722		$		16,584		$		—		$		—	$		278,306

Supplemental Cash Flow Information:
Interest paid	$	16,695		$		—		$		—		$		—	$		16,695
Income taxes paid	$	37,025		$		265		$		—		$		—	$		37,290

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

Forward-Looking Statements

The statements contained in this quarterly report regarding our future financial and operating performance and results, business strategy, market prices, future commodity price risk management activities, plans and forecasts and other statements that are not historical facts are forward-looking statements, as defined in Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words “may,” “will,” “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. 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:

• estimates of reserves;

• market factors, including demand for our production;

• market prices, including regional basis differentials, of oil and natural gas;

• results of future drilling and acquisitions;

• marketing and commodity price risk management activities;

• future production and costs;

• our ability to arrange financing;

• our ability to service our indebtedness; and

• other factors described in this quarterly report and in our other SEC filings.

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, 2004.

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 energy company engaged in the acquisition, exploration, development and exploitation of oil and natural gas properties in the United States and, until February 10, 2005, Canada. Our strategy is to grow primarily through the acquisition of proved oil and natural gas reserves and, to the extent possible, through the exploitation and development of these properties. We expect to continue to use debt, primarily under our credit agreement, to make future acquisitions. We also expect to continue to enter into new derivative financial instruments to reduce our exposure to changes in the prices of oil and natural gas. For the three year period ended December 31, 2004, we have spent in excess of $433.0 million on property and corporate acquisitions. We spent an additional $17.5 million on property acquisitions during the first three months of 2005.

On January 27, 2004, we acquired all of the outstanding common stock of North Coast for a purchase price of approximately $225.1 million, including the assumption of $57.0 million in outstanding bank debt. We funded the acquisition of North Coast through the issuance of $350.0 million in 7¼% senior unsecured notes on January 20, 2004. On April 13, 2004 we issued an additional $100.0 million in 7¼% senior unsecured notes, of which approximately $98.8 million was used to repay substantially all of the indebtedness outstanding under our Canadian credit facility.

On February 10, 2005, 1143928 Alberta Ltd., a wholly-owned subsidiary of NAL Oil & Gas Trust, an Alberta trust, purchased all of the issued and outstanding shares of common stock of Addison, our wholly-owned subsidiary through which all of our Canadian operations were conducted, and two intercompany notes that Addison owed to our wholly-owned subsidiary, ROJO Pipeline, Inc. (ROJO), formerly known as Taurus Acquisition, Inc. The aggregate purchase price 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. See “Note 2. Sale of Addison Energy Inc.” to the Condensed Consolidated Financial Statements for additional information.

Critical Accounting Policies

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

We prepared our consolidated financial statements for inclusion in this report in accordance with accounting principles that are generally accepted in the United States, or GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.

Estimates of Proved Reserves

The Proved Reserves data included in our Annual Report on Form 10-K for the year ended December 31, 2004 was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

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

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

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

Accounting for Derivatives

We engage in commodity price risk management activities to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition activities. In connection with the incurrence of debt related to our acquisition activities, our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve a more predictable cash flow to fund our development and acquisition activities. These derivatives are not held for trading purposes.

Currently, we do not designate derivative transactions as hedges for financial accounting purposes; accordingly, changes in the fair value of derivative financial instruments, including interest rate swaps, are recognized currently in our statement of operations. We do continue to designate derivative financial instruments as hedges for income tax purposes.

Assessments of Functional Currencies

We determine the functional currencies of our subsidiaries by assessing the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. We determined that the Canadian dollar was the functional currency of our international operations in Canada. Our assessment of functional currencies can have a significant impact on our periodic results of operations and on our financial position.

Effective April 13, 2004, Addison entered into a long-term note agreement with Taurus in the amount of $98.8 million. Addison used the proceeds of this borrowing to repay virtually all of its outstanding indebtedness under its Canadian credit agreement in April 2004. The indebtedness, which was repayable in U.S. dollars, was repaid in full on February 10, 2005 upon the sale of Addison. Under the provisions of SFAS No. 52—“Foreign Currency Translation”, Addison was required to recognize a foreign currency transaction gain or loss when translating this liability from U.S. dollars to Canadian dollars currently in its statement of operations. Gain or loss recognized by Addison was not eliminated when preparing EXCO’s consolidated statement of operations.

Deferred Tax Asset Valuations

We periodically assess the probability of recovering recorded deferred tax assets based on our assessment of future earnings outlooks by tax jurisdiction. These estimates are inherently imprecise because we make many assumptions in the assessment process. At December 31, 2004 and March 31, 2005, we have provided for a valuation allowance in the amount of $2.6 million that is related to net operating loss carryforwards that are expected to expire without utilization.

Accounting for Oil and Natural Gas Properties

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

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

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

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

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

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

Goodwill

As a result of a change in control, the going private transaction that occurred on July 29, 2003 was accounted for using the purchase method of accounting pursuant to SFAS No. 141, “Accounting for Business Combinations.” As a result, EXCO Holdings’ cost of acquiring EXCO was allocated to the assets and liabilities acquired based upon estimated fair values. Under applicable generally accepted accounting principles, the new basis of accounting for EXCO Holdings was “pushed down” to the subsidiary company, EXCO. Therefore, EXCO’s financial position and operating results subsequent to July 28, 2003 reflect a new basis of accounting and are not comparable to prior periods. In addition, tax basis carried over from the formerly public company as a result of the merger. The going private purchase price was allocated to the assets acquired and liabilities assumed according to their estimated fair values. The purchase price allocation resulted in $51.1 million of goodwill being recorded, $24.2 million in the United States EXCO geographic operating segment and $26.9 million in the Canadian geographic operating segment. The goodwill amount related to the Canadian geographic operating segment has been removed from the condensed Consolidated Balance sheet at March 31, 2005, as a result of the sale of Addison

on February 10, 2005. Changes in the balance of goodwill in the EXCO geographic operating segment from the date of acquisition to December 31, 2004 were the result of sales of oil and natural gas properties (based upon the relative fair value of our oil and natural gas properties prior to and after the sales) and the sale of a bankruptcy claim related to Enron Corp. In a recent letter to oil and natural gas companies, the SEC has provided guidance concerning the treatment of goodwill in situations when a company sells less than 25% of its proved oil and natural gas reserves in a cost pool. The guidance indicates that such dispositions may trigger a need to evaluate goodwill for impairment under SFAS No. 142. As a result of this guidance, beginning January 1, 2005, we no longer reduce the balance of goodwill for property dispositions of less than 25% of our oil and natural gas reserves unless there is an indication that our goodwill is impaired as a result of the sale.

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

Asset Retirement Obligations

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted the new rules on asset retirement obligations on January 1, 2003.

Accounting for Income Taxes

Income taxes are provided based upon the liability method of accounting. Deferred taxes are recorded to reflect the tax benefit and consequences of future years’ differences between the tax basis of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. Prior to the disposition of Addison on February 10, 2005, we considered Addison’s earnings to be permanently reinvested for use in those operations and, consequently, deferred federal income taxes, net of applicable foreign tax credits, had not been provided on the undistributed earnings of Addison that were reinvested. As a result of the sale of Addison, we provided for deferred federal income taxes in the fourth quarter of 2004 on the undistributed earnings of Addison.

Recent Accounting Pronouncements

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

SFAS No. 123(R) becomes effective for us on January 1, 2006 and permits public companies to adopt its requirements using one of two methods:

• A “modified prospective” method in which compensation cost is recognized based on the requirements of SFAS No. 123 (R) for all share-based payments granted prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date.

interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures.

As permitted by SFAS No. 123, we currently account for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. As such, we generally do not recognize compensation expense associated with employee stock options. Accordingly, the adoption of SFAS No. 123(R)’s fair value method could have a significant impact on our future results of operations, although it will have no impact on our overall financial position. We currently plan to adopt the provisions of SFAS No. 123(R), but we have not completed evaluating the impact the adoption of SFAS No. 123(R) will have on our future results of operations.

Our Results of Operations

The following is a discussion of our financial condition and results of operations for the three months ended March 31, 2004 and 2005.

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

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

• the sale of Addison on February 10, 2005;

• property acquisitions and, to a lesser degree, property dispositions that have occurred during the periods presented;

• significant changes in the amount of our long-term debt including the issuance of our senior notes on January 20, 2004 in the amount of $350.0 million and on April 13, 2004 in the amount of $103.3 million (including applicable premium); and

• significant fluctuations in the prices received for oil and natural gas sales.

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.

United States

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

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

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

We sell our NGLs 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.

Canada

Prior to February 10, 2005, the majority of our Canadian oil was ultimately sold to Plains Marketing Canada, L.P. at market sensitive prices less applicable tariffs, trucking and quality adjustments. Our Canadian natural gas was sold to various purchasers at market sensitive prices. Our NGLs were sold primarily to two different buyers under contracts which provided for index pricing less transportation and fractionation fees.

As a result of the sale of Addison on February 10, 2005, we no longer have operations in Canada. (See “Note 2. Sale of Addison Energy Inc.” included in “Item 1. Financial Statements”). As a result, we have treated Addison’s operating results as discontinued operations on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2004 and 2005.

Revenues and Production

The following tables present our oil and natural gas revenues (before commodity price risk management activities), production and average unit sales price for the three months ended March 31, 2004 and 2005. The tables also show the changes in these amounts between periods. For purposes of these tables, EXCO includes all of our

U.S. oil and natural gas properties other than those properties owned by North Coast. The 2004 data presented for North Coast only reflects revenues and production since the date of our acquisition of North Coast (January 27, 2004).

	Three months ended March 31,				Quarter to quarter change
	2004		2005		2004-2005
	(Unaudited, in thousands)
Oil and natural gas revenues before commodity price risk management activities:
Oil revenues:
EXCO	$	5,638	$	4,825	$	(813	)
North Coast	618		1,108		490
Total	$	6,256	$	5,933	$	(323	)
Natural gas revenues:
EXCO	$	10,281	$	11,180	$	899
North Coast	11,732		21,634		9,902
Total	$	22,013	$	32,814	$	10,801
Natural gas liquids revenues:
EXCO	$	398	$	182	$	(216	)
North Coast	—		—		—
Total	$	398	$	182	$	(216	)
Total oil and natural gas revenues:
EXCO	$	16,317	$	16,187	$	(130	)
North Coast	12,350		22,742		10,392
Total	$	28,667	$	38,929	$	10,262

	Three months ended March 31,		Quarter to quarter change
	2004	2005	2004-2005
	(Unaudited)

Production:
Oil (Mbbls):
EXCO	169	102	(67	)
North Coast	20	24	4
Total	189	126	(63	)
Natural gas (Mmcf):
EXCO	2,088	2,089	1
North Coast	2,009	3,031	1,022
Total	4,097	5,120	1,023
Natural gas liquids (Mbbls):
EXCO	15	6	(9	)
North Coast	—	—	—
Total	15	6	(9	)
Total production (Mmcfe):
EXCO	3,191	2,737	(454	)
North Coast	2,129	3,175	1,046
Total	5,320	5,912	592

	Three months ended March 31,				Quarter to quarter change
	2004		2005		2004-2005
	(Unaudited)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl):
EXCO	$	33.35	$	47.30	$	13.95
North Coast	31.59		46.17		14.58
Total	33.16		47.09		13.93
Natural gas (per Mcf):
EXCO	$	4.92	$	5.35	$	0.43
North Coast	5.84		7.14		1.30
Total	5.37		6.41		1.04
Natural gas liquids (per Bbl):
EXCO	$	26.53	$	30.17	$	3.64
North Coast	—		—		—
Total	26.53		30.17		3.64
Total production (per Mcfe):
EXCO	$	5.11	$	5.91	$	0.80
North Coast	5.81		7.16		1.35
Total	5.39		6.58		1.19

Our revenues from the sale of oil, natural gas and NGLs, before cash settlements of derivative financial instruments, for the three months ended March 31, 2005 increased by $10.3 million, or 36% over the three months ended March 31, 2004 primarily due to an increase of $1.19 per equivalent Mcf in our average sales price which increased revenues by $6.3 million. We also had an 11% increase in oil and natural gas production volumes on an equivalent basis. This increase in production volumes is due primarily to:

• having an additional 26 days of production from North Coast, which was acquired on January 27, 2004; and

• property acquisitions, including EXCO’s Oak Hill Field (acquired in July 2004) and Minden Field properties (acquired on January 21, 2005) and North Coast’s Pinestone properties (acquired in November and December 2004).

Oil production and oil revenues for EXCO declined during the three months ended March 31, 2005 compared to the same period in 2004 due to property sales in 2004 and 2005 and a general decline in production from our oil producing properties. The decline in production volumes was partially offset by an increase in EXCO’s average oil price received of $13.95 per barrel.

At North Coast, oil and natural gas production volumes for the three months ended March 31, 2005, increased approximately 1.0 Bcf from the comparable period last year. This increase is the result of having 26 additional days of production in the 2005 period. Additionally, there was approximately 329,000 Mcfe of production attributable to the Pinestone properties which were acquired in the fourth quarter of 2004. These volumes offset oil and natural gas production curtailments imposed upon us by natural gas pipelines and declines in oil and natural gas production from other North Coast properties.

The following table presents our commodity price risk management activities and our other income (expense) for the three months ended March 31, 2004 and 2005. The table also shows changes in these amounts between periods.

	Three months ended March 31,						Quarter to quarter change
	2004			2005			2004-2005
	(Unaudited, in thousands)
Commodity price risk management activities:
Cash settlements on derivative financial instruments	$	(3,366	)	$	(56,325	)	$	(52,959	)
Non-cash change in fair value of derivative financial instruments	(20,196		)	(1,065		)	19,131
Total commodity price risk management activities	$	(23,562	)	$	(57,390	)	$	(33,828	)

	Three months ended March 31,				Quarter to quarter change
	2004		2005		2004-2005
	(Unaudited, in thousands)
Other income, net:
Gain from foreign currency transactions	$	161	$	185	$	24
Interest, dividend and other, net	305		197		(108		)
Total other income, net	$	466	$	382	$	(84	)

Our commodity price risk management activities reduced revenue by $57.4 million during the three months ended March 31, 2005, which includes payments totaling $52.6 million made in January and March 2005 (which are included as cash settlements on derivative financial instruments) to the counterparties of certain of our existing contracts to terminate these contracts. In January and March 2005, we entered into new commodity price risk management contracts for increased volumes at higher underlying product prices. The remaining $3.7 million of cash settlements of derivative financial instruments during the three months ended March 31, 2005, are a result of

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 months ended March 31, 2004 and 2005. The 2004 data presented for North Coast only reflects costs and expenses since the date of our acquisition of North Coast. The table also shows the changes in these amounts between the periods.

	Three months ended March 31,				Quarter to quarter change
	2004		2005		2004-2005
	(Unaudited, in thousands)
Oil and natural gas production costs:
Oil and natural gas operating costs:
EXCO	$	3,520	$	1,983	$	(1,537	)
North Coast	1,346		2,435		1,089
Total	$	4,866	$	4,418	$	(448	)
Production and ad valorem taxes:
EXCO	$	1,081	$	1,494	$	413
North Coast	518		877		359
Total	$	1,599	$	2,371	$	772
Total oil and natural gas production costs:
EXCO	$	4,601	$	3,477	$	(1,124	)
North Coast	1,864		3,312		1,448
Total	$	6,465	$	6,789	$	324

	Three months ended March 31,				Quarter to quarter change
	2004		2005		2004-2005
	(Unaudited)
Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs:
EXCO	$	1.10	$	0.72	$	(0.38	)
North Coast	0.64		0.77		0.13
Total	0.90		0.75		(0.15		)
Production and ad valorem taxes:
EXCO	$	0.34	$	0.55	$	0.21
North Coast	0.24		0.28		0.04
Total	0.30		0.40		0.10
Total oil and natural gas production costs:
EXCO	$	1.44	$	1.27	$	(0.17	)
North Coast	0.88		1.05		0.17
Total	1.20		1.15		(0.05		)

Our oil and natural gas operating costs for the three months ended March 31, 2005 decreased $448,000, or 9%, from the same period in 2004. The primary reason for the decrease in oil and natural gas operating costs was the sale by EXCO during 2004 and 2005 of oil and natural gas properties with high operating costs. This decrease was partially offset by:

• an additional 26 days of operating costs resulting from our acquisition of North Coast on January 27, 2004;

The following table presents our general and administrative costs for the three months ended March 31, 2004 and 2005. The table also shows the changes in these amounts between periods.

	Three months ended March 31,						Quarter to quarter change
	2004			2005			2004-2005
	(Unaudited, in thousands, except per unit and employee count)
General and administrative costs:
Gross G&A expense	$	4,095		$	5,951		$	1,856
Operator overhead charges	(595		)	(423		)	172
Capitalized acquisition and exploitation charges	(254		)	(360		)	(106		)
Net G&A expense	$	3,246		$	5,168		$	1,922

General and administrative expense per Mcfe	$	0.61		$	0.87		$	0.26
Total number of employees at end of period	240			238			(2		)

Our general and administrative costs for the three months ended March 31, 2005 increased by $1.9 million, or 59%, over the same period in 2004 and was primarily attributable to:

• an increase of $1.0 million in our legal, accounting and travel expenses resulting primarily from:

• costs incurred of approximately $207,000 for the sale of Addison;

• costs incurred of approximately $272,000 to comply with the provisions of the Sarbanes-Oxley Act;

• costs incurred of approximately $281,000 in evaluating the tax and legal implications of the various strategic alternatives we are evaluating in light of the recent sale of Addison; and

• an increase in legal expenses of approximately $115,000.

• an increase of $327,000 in salaries and related benefits of which $81,000 is the result of an additional 26 days of expenses resulting from our acquisition of North Coast on January 27, 2004. The remaining increase in salaries and related benefits is the result of an increase in the number of administrative employees and a general increase in salaries after the first quarter of 2004;

• an increase of $172,000 resulting from a reduction in overhead reimbursements received as a result of EXCO property sales during 2004 and 2005; and

• an increase of approximately $354,000 resulting primarily from increased franchise taxes ($172,000), increased bad debt expense ($100,000) and other items ($69,000).

The following table presents our interest expense for the three months ended March 31, 2004 and 2005. The table also shows the changes in these amounts between periods.

	Three months ended March 31,				Quarter to quarter change
	2004		2005		2004-2005
	(Unaudited, in thousands)
Interest expense:
7¹/₄% senior notes due 2011	$	4,934	$	7,952	$	3,018
U.S. credit agreement	178		251		73
$50 million senior term loan	222		—		(222		)
Amortization and write-off of deferred					—
financing costs	2,142		548		(1,594		)
Interest rate swaps	133		—		(133		)
Total interest expense	$	7,609	$	8,751	$	1,142

Our interest expense for the three months ended March 31, 2005 increased $1.1 million from the same period in 2004. The increase is primarily due to the issuance on January 20, 2004 of $350.0 million aggregate principal amount and on April 13, 2004 of $100.0 million aggregate principal amount of 71/4% senior notes due 2011. Amortization of deferred financing costs in 2004 includes approximately $1.7 million in costs relating to the senior term loan that was repaid in full in January 2004 and fees incurred on a bridge facility related to the North Coast acquisition. No funds were borrowed under the bridge facility. Our long-term debt balance under our U.S. credit agreement was $1,000 at March 31, 2005 compared to $47.4 million at December 31, 2004.

Our effective tax rate on losses from continuing operations for the three months ended March 31, 2005 approximates 39%. Our effective tax rate on losses from continuing operations for the three months ended March 31, 2004 approximates 37%. The increase in the effective tax rate is a result of higher state taxes in the states in which North Coast operates than the states in which EXCO operates.

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 Taurus. 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. $174.1 million before income tax expense of U.S. $49.6 million related to the gain. The income tax is composed of:

	Three Months Ended March 31, 2004
	(In thousands, unaudited)
U.S. income tax before foreign tax credits	$	49,557
Canadian income tax on the gain	33,456
U.S. foreign tax credit	(33,439		)
Total income tax on gain	$	49,574

Income taxes from discontinued operations for the three months ended March 31, 2005 reflects the income tax on the gain of $49.6 million as discussed above, an income tax benefit of $1.3 million from Addison’s operations during the period January 1, 2005 to February 10, 2005, and approximately $500,000 of Canadian income taxes withheld on interest paid by Addison in 2005 on the intercompany notes.

The loss from discontinued operations of $4.4 million before the gain on the sale of Addison and income taxes from discontinued operations for the three months ended March 31, 2005 includes:

• approximately $3.8 million in losses from commodity price risk management activities, and

• approximately $2.7 million in severance for employees not hired by the purchaser and management retention bonus payments to certain Addison employees that were accelerated as a result of the sale.

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 and the sale or issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreement is subject to restrictions imposed by our lenders. In addition, our indenture governing our senior notes contains restrictions on incurring indebtedness and pledging our assets.

On February 10, 2005, we sold Addison for approximately $445.1 million before contractual adjustments. The net cash proceeds may only be utilized by us in accordance with the terms of the indenture governing the senior notes and our U.S. credit facility. In addition, $120.6 million of these proceeds are pledged as collateral under the U.S. credit facility and the senior notes.

We are evaluating a number of strategic alternatives in light of the recent sale of Addison. The strategic alternatives being evaluated include, among other things: (1) an issuance of EXCO Holdings’ equity securities; (2) a leveraged recapitalization of EXCO Holdings, which would include an equity buyout; (3) a spin-off of EXCO’s Appalachian properties into a master limited partnership; (4) payment of a dividend to EXCO Holdings’ shareholders; or (5) no restructuring or recapitalization and retention of the cash from the sale of Addison to continue EXCO’s acquisition and development program. EXCO cautions, however, that no assurance can be given that any of these strategic alternatives, or any transaction, will be pursued or, if a transaction is pursued, that it will be consummated.

On January 20, 2004, we issued $350.0 million aggregate principal amount of 7¼% senior notes due January 15, 2011. Additionally, on April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of our 7¼% senior notes due January 15, 2011 having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. We used approximately $98.8 million of the proceeds from the April 2004 offering to repay substantially all of the indebtedness outstanding under our Canadian credit agreement.

We had negative operating cash flow after changes in working capital of approximately $115.3 million for the three months ended March 31, 2005. This was primarily the result of $67.6 million paid in January and March 2005 to terminate certain of our commodity price risk management contracts, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production, and approximately $49.6 million in U.S. and Canadian taxes incurred on the gain from the sale of Addison. These payments were funded by cash received from the sale of Addison. At March 31, 2005, our cash and cash equivalents balance was $278.3 million, an increase of $251.9 million from December 31, 2004 primarily as a result of the sale of Addison on February 10, 2005. On January 18, 2005, we made an interest payment on our 7¼% senior notes in the amount of $16.3 million. Our working capital at March 31, 2005 increased to $231.4 million from a working capital deficit of $29.8 million at December 31, 2004 primarily as a result of the sale of Addison. See “—Commodity Price Risk Management Activities” below for a discussion of various transactions completed during the three months ended March 31, 2005 with respect to our derivative contracts.

Acquisitions and Capital Expenditures

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

The following table presents our capital expenditures for the three months ended March 31, 2004 and 2005:

	Three months ended March 31,
	2004			2005
	(Unaudited, in thousands)
Capital expenditures:
Property acquisitions	$		3,270	$	17,479
Acquisition of North Coast Energy, Inc., net of cash acquired	215,055			—
Development capital expenditures	3,811			14,464
Other	3,598			3,453
Total capital expenditures	$	225,734		$		35,396

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, include approximately 35 Mbbls of oil and 8.8 Bcf of natural gas. We funded the acquisition with $13.3 million in borrowings under our U.S. credit agreement and from surplus cash. The properties acquired consist 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 $700,000.

For the year 2005, we have budgeted approximately $55.9 million for our development, exploitation and exploration activities in the United States. As of March 31, 2005, we were contractually obligated to spend $3.9 million for our development and exploitation activities.

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 2005.

We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our U.S. credit facility 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. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. We have experienced increased costs for tubular goods and for certain services during 2004 and 2005. Further, we have encountered difficulties in contracting for drilling rigs and other services due to high demand. Currently, we do not believe that these conditions have had a significant impact upon our capital expenditures programs or our results of operations. If the conditions continue, however, projects may be delayed due to lack of services or materials or we may have to delay projects to stay within our capital budget.

71/4% Senior Notes Due January 15, 2011

On January 20, 2004, we issued $350.0 million principal amount of our 71/4% senior notes 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 $103.25 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 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 $300,000 of the senior notes accepted our offer. The exchange offer was closed on June 1, 2004.

U.S. Credit Agreement

On January 27, 2004, our U.S. credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the U.S. credit agreement maturity date to January 27, 2007. Upon the issuance of the $100.0 million in additional 71/4%

senior notes on April 13, 2004, the U.S. credit agreement borrowing base was reduced to $95.0 million. Effective June 28, 2004, the borrowing base was redetermined at $145.0 million. Effective October 8, 2004, the borrowing base was redetermined at $145.0 million. The borrowing base is currently being redetermined and management does not expect a decrease in the existing amount. The borrowing base will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At March 31, 2005, we had $1,000 of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $144.7 million available for borrowing. Borrowings under our amended and restated U.S. credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. In addition, a first lien security interest was effected in $120.6 million of cash equivalents, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. At our election, interest on borrowings may be (i) the greater of the administrative agent’s prime rate or the federal funds effective rate plus 0.50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At March 31, 2005, the six month LIBOR rate was 3.40%, which would result in an interest rate of approximately 4.65% on any new indebtedness we may incur under the U.S. credit agreement.

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

• maintain a ratio of our consolidated current assets to consolidated current liabilities (as defined under our U.S. credit agreement) of at least 1.0 to 1.0 at the end of any fiscal quarter;

• not permit our ratio of consolidated EBITDA to consolidated interest expense (as defined under our U.S. credit agreement) to be less than 2.5 to 1.0 at the end of each fiscal quarter.

Additionally, the U.S. 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 March 31, 2005, we were in compliance with the covenants contained in our U.S. credit agreement.

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

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

Derivative Financial Instruments

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

Commodity Price Risk Management Activities

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

Our objective in entering into commodity price risk management contracts is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our U.S. credit agreement. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. During the three months ended March 31, 2005, we closed several of our commodity price risk management contracts upon the payment of $67.6 million to our counterparties, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production. We also entered into new commodity price risk management contracts at higher prices. As of April 30, 2005, we had contracts in place for the volumes and prices shown in the table below:

		Swaps						Floors
		Gas - Mmmbtus	Average contract- $/Mmbtu		Oil-Mbbls	Average contract- $/Bbl		Gas - Mmmbtus	Average contract- $/Mmbtu
Remainder of Q2	2005	2,532	$	6.76	37	$	52.84	177	$	4.25
Q3	2005	3,818	$	6.84	55	$	52.84	267	$	4.25
Q4	2005	3,818	$	7.08	55	$	52.84	267	$	4.25
	2006	13,323	$	6.78	—	—		—	—
	2007	11,680	$	6.47	—	—		—	—
	2008	2,745	$	4.55	—	—		—	—
	2009	1,825	$	4.51	—	—		—	—
	2010	1,825	$	4.51	—	—		—	—
	2011	1,825	$	4.51	—	—		—	—
	2012	1,830	$	4.51	—	—		—	—
	2013	1,825	$	4.51	—	—		—	—

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 March 31, 2005 with set and determinable payments. We also have a $275,000 letter of credit that has been issued to a service provider which will expire in 2005 and is currently being canceled as a result of the sale of Addison.

	Payments Due by Period
	2005		2006-2007		2008-2009		2010 and thereafter		Total
	(In thousands)
Contractual Obligations
Long-term debt - senior notes (1)	$	—	$	—	$	—	$	450,000	$	450,000
Long-term debt - credit agreement (2)	—		1		—		—		1
Derivative financial instruments (3)	11,865		18,186		7,421		5,732		43,204
Operating leases	1,630		2,921		1,549		830		6,930
Drilling/work commitments	3,905		—		—		—		3,905
Bonus retention program for employee stockholders	1,080		2,520		—		—		3,600
Total contractual cash obligations	$	18,480	$	23,628	$	8,970	$	456,562	$	507,640

(1) Our senior notes are due on January 15, 2011. The annual interest obligation on our senior notes is $32.6 million.

(2) Our U.S. bank credit facility is due on January 27, 2007.

(3) Derivative financial instruments represent net liabilities for oil and natural gas commodity derivatives that were valued as of March 31, 2005. The ultimate settlement amounts of our derivative financial instruments are unknown because they are subject to continuing market risk. See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” and “Note 6. Derivative Financial Instruments” to our Condensed Consolidated Financial Statements included in
“Item 1. Financial Statements” for additional information regarding our derivative financial instruments.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

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

Commodity Price Risk

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

The following table sets forth our oil and natural gas hedging activities as of April 30, 2005.

	Volume Mmbtus/ Bbls	Weighted Average Strike Price Per Mmbtu/Bbl		Weighted Average Differential to NYMEX			Fair Value at April 30, 2005
	(In thousands, except prices and differentials)
Natural Gas:
Swaps:
Remainder of 2005	10,168	$	6.91				$		(672	)
2006	13,323	6.78					(6,077			)
2007	11,680	6.47					(4,183			)
2008	2,745	4.55					(4,558			)
2009	1,825	4.51					(2,362			)
2010	1,825	4.51					(1,832			)
2011	1,825	4.51					(1,494			)
2012	1,830	4.51					(1,216			)
2013	1,825	4.51					(961			)
	47,046

Basis Protection Swaps:
Remainder of 2005	460			$	(0.75	)	(14			)
	460
Floor Prices:
Remainder of 2005	667	4.25					2
	667
Total Natural Gas							(23,367			)

Oil:
Swaps:
Remainder of 2005	147	52.84					76
	147
Total Oil							76
Total Oil and Natural Gas							$	(23,291		)

Total Mark to Market Position							$	(23,291		)

At April 30, 2005, the average forward NYMEX oil prices per Bbl for the remainder of 2005 was $52.62 and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2005 and for calendar 2006 were $6.98 and $7.25, respectively.

Realized gains or losses from the settlement of derivative financial instruments are recorded in our financial statements as increases or decreases in commodity price risk management activities. For example, using the oil swaps in place at April 30, 2005, if the settlement price exceeded the actual weighted average strike price of $52.84, then a reduction in commodity price risk management activities revenue would have been recorded for the difference between the settlement price and $52.84 multiplied by the hedged volume of 184,000 Bbls. Conversely, if the settlement price was less than $52.84, then an increase in commodity price risk management activities revenue would have been recorded for the difference between the settlement price and $52.84 multiplied by the hedged volume of 184,000 Bbls. For example, for a hedged volume of 184,000 Bbls, if the settlement price was $53.84, then commodity price risk management activities revenue would have decreased by $184,000. Conversely, if the settlement price was $51.84, commodity price risk management activities revenue would have increased by $184,000.

Interest Rate Risk

At April 30, 2005, our exposure to interest rates related primarily to borrowings under our U.S. credit agreement and interest earned on short-term investments. The interest rate is fixed at 71/4% on our $450.0 million in senior notes. As of March 31, 2005, we were not using any derivatives to manage interest rate risk. Interest is payable on borrowings under our U.S. 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 March 31, 2005, we had $1,000 in outstanding borrowings under our U.S. credit agreement. The interest we pay on these borrowings is set periodically based upon market rates. A 1% change in the market value would not have a significant effect on interest on these borrowings.`

Marketable Securities Risk

As a result of our sale of Addison, we have a substantial cash position as of March 31, 2005. In addition, we only have a nominal amount of indebtedness outstanding under our U.S. credit facility. In compliance with the indenture governing our senior notes, we have invested our cash in short-term commercial paper having an average maturity of 30 days or in overnight funds at JPMorgan Securities Inc. The commercial paper is issued by issuers having a credit rating of A1/P1 or better. Our principal risks with respect to these investments are interest rate risk and default risk. At March 31, 2005, we had approximately $246.5 million of such cash equivalent investments. A 1% change in market value would affect interest on these investments by approximately $2.5 million per year.

Equity Price Risk

Our investments in marketable equity securities are recorded at market value. We consider these investments to be “available for sale”, which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investments is “other than temporary”. At March 31, 2005, the market value of our investments in marketable securities was $64,000. A temporary change in value of 10% would result in a $6,400 change in the market value and a corresponding adjustment to other comprehensive income of $6,400. An “other than temporary” decline in value of 10% would result in a $6,400 reduction in the market value and a corresponding non-cash pre-tax impairment expense of $6,400. As of March 31, 2005, we were not using any derivatives to manage equity price risk.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our senior management, including our Chief Executive Officer (CEO), our Chief Financial Officer (CFO) and our Chief Accounting Officer (CAO), collectively referred to as the disclosure committee, of the effectiveness and the design and operation of our disclosure controls and procedures (as defined in Rules 13a – 15(e) and 15d – 15(e) under the Securities Exchange Act of 1934, as amended). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to management, including the CEO, CFO and CAO, to allow timely decisions regarding required disclosures.

Based upon this evaluation, our CEO, CFO and CAO concluded that, as of the end of the period covered by this report, as a result of the material weakness identified as of December 31, 2004 and discussed below, our disclosure controls and procedures were not effective. Due to the material weakness discussed below, in preparing our financial statements as of and for the three month period ended March 31, 2005, we performed additional procedures relating to the tax provision designed to ensure that such financial statements were fairly presented in all material respects in accordance with generally accepted accounting principles.

PART II—OTHER INFORMATION

Item 6. Exhibits

EXHIBIT NUMBER		Description Of Exhibit
3.1		Second Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

3.2		Bylaws of EXCO Resources, Inc., as amended, filed as an Exhibit to EXCO’s Annual Report on Form 10-K filed March 31, 2005 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		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*

4.6		Registration Rights Agreement by and among EXCO Resources, Inc., certain domestic subsidiaries of EXCO Resources, Inc., as guarantors, and Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc, dated April 1, 2004.**

4.7		Pledge Agreement by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, dated January 20, 2004.*

4.8		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.

4.9		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.

10.1		Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003, filed as an Exhibit to EXCO’s Form 8-K filed March 12, 2003 and incorporated by reference herein.

10.2		Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein.*

10.3		First Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**

10.4		Second Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**

10.5		Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein.*

10.6		First Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**

10.7		Second Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**

10.8		Amended and Restated Agreement and Plan of Merger among NCE Acquisition, Inc., EXCO Resources, Inc., North Coast Energy, Inc. and Nuon Energy & Water Investments, Inc., dated as of December 4, 2003, filed as exhibit (d)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.

10.9		Escrow Agreement among Nuon Energy & Water Investments, Inc., EXCO Resources, Inc. and Citibank, N.A., dated as of December 9, 2003.*

10.10		Unconditional Guaranty Agreement by and between EXCO Resources, Inc. and n.v. NUON, dated as of December 9, 2003.*

10.11		Commitment Letter among Credit Suisse First Boston Bank One, NA, Banc One Capital Markets, Inc. and EXCO Resources, Inc., dated November 25, 2003, filed as exhibit (b)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.

10.12		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*

10.13		Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*

10.14		Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, Canada Branch, as agent.*

10.15		Second Restated Unlimited Guaranty dated as of January 27, 2004, by EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Taurus Acquisition, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*

10.16		Amended and Restated Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*

10.17		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, as Agent.*

10.18		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, as Agent.*

10.19		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Holdings Inc. in favor of Bank One, NA, as Agent.*

10.20		Amended and Restated Subsidiary Guaranty dated as of January 27, 2004, by Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*

10.21		Third Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated June 28, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.

10.22		Third Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated June 28, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.

10.23		EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein. ***

10.24		First Amendment to the EXCO Holdings Inc. 2004 Long-term Incentive Plan, filed as an Exhibit to EXCO’s Form 8-K dated November 18, 2004 and filed November 24, 2004 and incorporated by reference herein.***

10.25		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.26		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.27		EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO’s Form 8-K dated November 18, 2004 and filed November 24, 2004 and incorporated by reference herein.***

10.28		EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.29		Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.30		Unlimited Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, Canada Branch, as Agent, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.31		Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, as Agent, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.32		Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO’s Form 8-K dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.

10.33		First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

10.34		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

10.35		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

10.36		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.

10.37		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*

10.38		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed herewith as exhibit 4.3.

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

10.40		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*

31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.

31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.

Index to Exhibits

EXHIBIT NUMBER		Description Of Exhibit
3.1		Second Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

3.2		Bylaws of EXCO Resources, Inc., as amended, filed as an Exhibit to EXCO’s Annual Report on Form 10-K filed March 31, 2005 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		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*

4.6		Registration Rights Agreement by and among EXCO Resources, Inc., certain domestic subsidiaries of EXCO Resources, Inc., as guarantors, and Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc, dated April 1, 2004.**

4.7		Pledge Agreement by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, dated January 20, 2004.*

4.8		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.

4.9		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.

10.1		Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003, filed as an Exhibit to EXCO’s Form 8-K filed March 12, 2003 and incorporated by reference herein.

10.2		Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein.*

10.3		First Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**

10.4		Second Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.**

10.5		Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein.*

10.6		First Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**

10.7		Second Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.**

10.8		Amended and Restated Agreement and Plan of Merger among NCE Acquisition, Inc., EXCO Resources, Inc., North Coast Energy, Inc. and Nuon Energy & Water Investments, Inc., dated as of December 4, 2003, filed as exhibit (d)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.

10.9		Escrow Agreement among Nuon Energy & Water Investments, Inc., EXCO Resources, Inc. and Citibank, N.A., dated as of December 9, 2003.*

10.10		Unconditional Guaranty Agreement by and between EXCO Resources, Inc. and n.v. NUON, dated as of December 9, 2003.*

10.11		Commitment Letter among Credit Suisse First Boston Bank One, NA, Banc One Capital Markets, Inc. and EXCO Resources, Inc., dated November 25, 2003, filed as exhibit (b)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein.

10.12		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*

10.13		Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*

10.14		Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, Canada Branch, as agent.*

10.15		Second Restated Unlimited Guaranty dated as of January 27, 2004, by EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Taurus Acquisition, Inc. in favor of Bank One, NA, Canada Branch, as Agent.*

10.16		Amended and Restated Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*

10.17		Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, as Agent.*

10.18		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, as Agent.*

10.19		Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Holdings Inc. in favor of Bank One, NA, as Agent.*

10.20		Amended and Restated Subsidiary Guaranty dated as of January 27, 2004, by Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.*

10.21		Third Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated June 28, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.

10.22		Third Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated June 28, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.

10.23		EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein. ***

10.24		First Amendment to the EXCO Holdings Inc. 2004 Long-term Incentive Plan, filed as an Exhibit to EXCO’s Form 8-K dated November 18, 2004 and filed November 24, 2004 and incorporated by reference herein.***

10.25		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.26		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.27		EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO’s Form 8-K dated November 18, 2004 and filed November 24, 2004 and incorporated by reference herein.***

10.28		EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.29		Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO’s Form 10-Q for the Quarter ended June 30, 2004 filed August 13, 2004 and incorporated by reference herein.***

10.30		Unlimited Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, Canada Branch, as Agent, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.31		Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, as Agent, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.32		Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO’s Form 8-K dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.

10.33		First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

10.34		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

10.35		Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.

10.36		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.

10.37		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*

10.38		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed herewith as exhibit 4.3.

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

10.40		Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.*

31.1		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.

31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.

31.3		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting Officer of EXCO Resources, Inc., filed herewith.

32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets at December 31, 2004 and March 31, 2005
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2004 and 2005
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2005
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2004 and 2005
	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 Disclosure About Market Risk
Item 4.	Controls and Procedures

PART II.	OTHER INFORMATION
Item 6.	Exhibits

Signatures
Index to Exhibits

	Three Months Ended March 31,
	2004			2005

Net income (loss)	$	(9,066	)	$	92,245
Other comprehensive income (loss):
Reclassification of foreign currency translation adjustment	(1,023		)	(21,384		)
Unrealized gain on equity investments	28			1
Total comprehensive income (loss)	$	(10,061	)	$	70,862

	EXCO RESOURCES, INC. (Registrant)


Date: May 20, 2005	By:	/s/ DOUGLAS H. MILLER
		Douglas H. Miller
		Chairman and Chief Executive Officer


	By:	/s/ J. DOUGLAS RAMSEY
		J. Douglas Ramsey
		Vice President and Chief Financial Officer


	By:	/s/ J. DAVID CHOISSER
		J. David Choisser
		Vice President and Chief Accounting Officer