Exco Resources 10Q/A 2005 Q3 Quarterly report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

Amendment No. 1

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

For the quarterly period ended September 30, 2005

OR

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

For the transition period from to

Commission File Number 0-9204

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Texas		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

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

YES o NO ý

The number of shares of common stock, par value $0.01 per share, outstanding at October 31, 2005 was 1,000.

The Form 10-Q (Form 10-Q) of EXCO Resources, Inc. for the nine months ended September 30, 2005 is being amended to (i) amend and restate Part I. Item 1. Financial Statements (Unaudited) to reclassify a tax benefit attributable to clarifications of the American Jobs Creation Act of 2004 in respect of an extraordinary dividend received from Addison Energy Inc., our former wholly-owned Canadian subsidiary, from discontinued operations to current taxes from continuing operations for the nine month period ended September 30, 2005, to reclassify a Canadian tax rate reduction benefit recognized in the nine month period ended September 30, 2004 from discontinued to continuing operations, to insert additional disclosures concerning income taxes, to insert revised disclosure related to the acquisition of our parent, EXCO Holdings Inc., and to insert conforming disclosure included elsewhere in the Form 10-Q as well as to correct certain minor drafting and other typographical errors, (ii) amend and restate Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations to reflect the same changes described in clause (i) above and to correct a numerical error as well as certain minor drafting and other typographical errors, (iii) amend and restate Part I. Item 4 Controls and Procedures to update our disclosure in light of this restatement, and (iv) amend and restate Part II. Item 6. Exhibits to (x) update the certifications of certain executive officers as of the date of this amendment, (y) incorporate by reference certain exhibits filed with the Form 10-Q and (z) file Exhibit 10.28, which was inadvertently omitted from the exhibits filed with the Form 10-Q. The Form 10-Q is hereby amended and restated in its entirety (other than exhibits previously filed with the Form 10-Q) as follows:

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets at December 31, 2004 and September 30, 2005
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2004 and 2005
	Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2004 and 2005
	Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 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

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	December 31,			September 30,
	2004			2005
				(Unaudited)

Assets
Current assets:
Cash and cash equivalents	$	26,408		$	236,371
Accounts receivable:
Oil and natural gas sales	32,752			26,883
Joint interest	4,539			1,221
Income taxes and other	1,630			15,355
Related parties	—			805
Deferred tax asset	3,121			39,492
Oil and natural gas derivatives	273			—
Marketable securities	69			—
Other	7,056			4,475
Total current assets	75,848			324,602
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	22,199			22,026
Proved developed and undeveloped oil and natural gas properties	794,844			554,568
Accumulated depreciation, depletion and amortization	(60,449		)	(54,067		)
Oil and natural gas properties, net	756,594			522,527
Gas gathering, office and field equipment, net	27,281			30,733
Deferred tax asset	—			3,471
Goodwill	51,416			19,984
Deferred financing costs, net and other assets	10,884			9,147
Total assets	$	922,023		$	910,464

See accompanying notes.

	December 31,			September 30,
	2004			2005
				(Unaudited)

Liabilities and Shareholder’s Equity
Current liabilities:
Accounts payable and accrued liabilities	$	42,871		$	20,809
Accrued interest payable	14,959			6,980
Revenues and royalties payable	8,641			8,039
Income taxes payable	8,665			18,993
Deferred income taxes	710			—
Current portion of asset retirement obligations	2,418			1,713
Oil and natural gas derivatives	27,431			78,769
Total current liabilities	105,695			135,303
Long-term debt	47,396			1
7¼% senior notes due 2011	452,953			452,643
Asset retirement obligations and other long-term liabilities	26,330			14,222
Deferred income taxes	59,102			—
Oil and natural gas derivatives	26,796			77,780
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 September 30, 2005	1			1
Additional paid-in capital	—			—
Capital contributed by EXCO Holdings Inc.	172,045			172,045
Retained earnings	10,338			58,469
Accumulated other comprehensive income:
Foreign currency translation adjustments	21,384			—
Unrealized loss on equity investments	(17		)	—
Total shareholder’s equity	203,751			230,515
Total liabilities and shareholder’s equity	$	922,023		$	910,464

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2005			2004			2005
							(As Restated)			(As Restated)

Revenues and other income:
Oil and natural gas	$	35,249		$	51,771		$	100,120		$	131,469
Commodity price risk management activities	(29,916		)	(107,505		)	(69,195		)	(177,253		)
Interest and other income (loss)	(62		)	3,401			887			7,025
Total revenues and other income (loss)	5,271			(52,333		)	31,812			(38,759		)
Costs and expenses:
Oil and natural gas production	7,453			7,596			21,121			21,979
Depreciation, depletion and amortization	7,772			8,775			20,960			24,490
Accretion of discount on asset retirement obligations	199			207			607			612
General and administrative	3,640			4,396			11,275			15,570
Interest	8,888			9,186			25,487			26,502
Total costs and expenses	27,952			30,160			79,450			89,153
Loss from continuing operations before income taxes	(22,681		)	(82,493		)	(47,638		)	(127,912		)
Income tax benefit	(3,365		)	(32,778		)	(12,818		)	(54,010		)
Loss from continuing operations	(19,316		)	(49,715		)	(34,820		)	(73,902		)
Discontinued operations:
Income (loss) from operations	10,673			—			24,882			(4,402		)
Gain on disposition of Addison Energy Inc.	—			—			—			175,717
Income tax expense	2,447			—			7,462			49,282
Income from discontinued operations	8,226			—			17,420			122,033
Net income (loss)	$	(11,090	)	$	(49,715	)	$	(17,400	)	$	48,131

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited, in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2005			2004			2005
Operating Activities:
Net income (loss)	$	(11,090	)	$	(49,715	)	$	(17,400	)	$	48,131
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Gain on sale of Addison Energy Inc.	—			—			—			(175,717		)
Gain on sale of other assets	—			(373		)	—			(373		)
Foreign currency transaction (gain)/loss	(5,604		)	—			(5,827		)	3,461
Depreciation, depletion and amortization	12,427			8,775			35,518			26,815
Accretion of discount on asset retirement obligations	423			207			1,259			742
Non-cash change in fair value of derivatives	28,430			101,338			60,353			102,351
Deferred income taxes	(1,872		)	(32,211		)	(11,123		)	(60,486		)
Amortization of deferred financing costs	473			430			3,429			1,387
Proceeds from sale of Enron claim	—			—			4,750			—
Other operating activities	(15		)	—			(14		)	3
Effect of changes in:
Accounts receivable	(1,124		)	(14,863		)	(1,520		)	(21,761		)
Other current assets	349			281			381			(497		)
Accounts payable and other current liabilities	2,557			(11,027		)	18,606			(5,103		)
Net cash provided by (used in) operating activities	24,954			2,842			88,412			(81,047		)
Investing Activities:
Acquisition of North Coast Energy, Inc., less cash acquired	—			—			(215,133		)	—
Additions to oil and natural gas properties, gathering systems and equipment	(81,968		)	(96,094		)	(144,140		)	(151,626		)
Proceeds from disposition of oil and natural gas properties	9,606			38,089			23,418			45,383
Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415	—			—			—			443,397
Proceeds from disposition of non-oil and natural gas properties	—			627			—			627
Advances/investments with affiliates	16			(28		)	76			211
Proceeds from sales of marketable securities	515			—			1,296			59
Other investing activities	538			—			423			—
Net cash provided by (used in) investing activities	(71,293		)	(57,406		)	(334,060		)	338,051
Financing Activities:
Proceeds from long-term debt	51,258			—			511,609			100,901
Payments on long-term debt	(22,653		)	—			(232,216		)	(148,247		)
Deferred financing costs and other financing activities	54			—			(13,128		)	305
Net cash provided by (used in) financing activities	28,659			—			266,265			(47,041		)
Net increase (decrease) in cash	(17,680		)	(54,564		)	20,617			209,963
Effect of exchange rates on cash and cash equivalents	562			—			(2,246		)	—
Cash at beginning of period	42,822			290,935			7,333			26,408
Cash at end of period	$	25,704		$	236,371		$	25,704		$	236,371

Supplemental Cash Flow Information:
Interest paid	$	284		$	16,313		$	18,654		$	33,099
Income taxes paid	$	771		$	88		$	3,464		$	38,213

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2005			2004				2005

Net income (loss)	$	(11,090	)	$	(49,715	)	$		(17,400	)	$	48,131
Other comprehensive income (loss):
Reclassification of foreign currency translation adjustment	8,220			—			5,467				—
Unrealized gain on equity investments	28			—			26				—
Total comprehensive income (loss)	$	(2,842	)	$	(49,715	)	$	(11,907		)	$	48,131

See accompanying notes.

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

(Unaudited)

1. Basis of Presentation

EXCO Resources, Inc., a Texas corporation (EXCO) and a wholly-owned subsidiary of EXCO Holdings Inc. (Holdings), 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. On October 3, 2005, Holdings was acquired in a business combination which will be accounted for as a purchase (Equity Buyout), see “Note 10. Equity Buyout, ONEOK Energy Acquisition and Other Transactions”. As a result, EXCO became a wholly-owned subsidiary of EXCO Holdings II, Inc. (Holdings II) which has since been merged with and into Holdings.

The accompanying condensed consolidated balance sheets as of December 31, 2004 and September 30, 2005 and the results of operations, cash flows and comprehensive income for the three and nine months ended September 30, 2004 and 2005 are for EXCO and its subsidiaries. All intercompany transactions have been eliminated. Our results of operations for the three and nine months ended September 30, 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 (SEC). We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. You should read these unaudited interim financial statements in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 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” (SFAS No. 123) 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 the 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 stock 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 September 30, 2005, options to purchase 8,671,906 shares of Holdings’ common stock were outstanding.

Effective with the grant of the Holdings’ stock options on June 3 and June 4, 2004, we 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 and nine month periods ended September 30, 2004 and 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 accounted for share-based payments to employees using the intrinsic value method prescribed by APB No. 25 and related interpretations. As such, we generally did not recognize compensation expense associated with employee stock options. However, as a result of the change of control of Holdings that occurred on October 3, 2005, all of the outstanding stock options under the Holdings Plan were cashed out which will result in a charge to stock option compensation expense during the fourth quarter of 2005. For additional information, see “Note 10. Equity Buyout, ONEOK Energy Acquisition and Other Transactions.”

Recent Accounting Pronouncements

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

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

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 statements of operations. As a result, the loss from discontinued operations in the condensed consolidated statements of operations for the nine months ended September 30, 2005 includes non-cash foreign currency transaction losses 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-owned subsidiary of NAL Oil & Gas Trust, an Alberta trust, EXCO and our wholly-owned subsidiary, Taurus Acquisition, Inc. (Taurus), now known as ROJO Pipeline, Inc. 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, after contractual adjustments, including the working capital balance adjustment that occurred on October 11, 2005, for the stock and the Addison Notes was Cdn. $551.3 million (U.S. $443.3 million). Of this amount, Cdn. $90.1 million (U.S. $72.1 million) was used to repay in full all outstanding balances under Addison’s credit facility while Cdn. $56.2 million (U.S. $45.2 million) was withheld and remitted to the Canadian government for 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. $12.1 million) for our estimate of the excess of the amount withheld for Canadian income taxes from the sales proceeds over the estimated amount of Canadian income taxes that are actually owed on the gain from the sale. A working capital balance adjustment occurred on October 11, 2005 which resulted in us paying Cdn. $1.6 million (U.S. $1.1 million) to the Purchaser. We had provided for this adjustment during the second quarter 2005. 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 for periods prior to February 1, 2005.

In the nine months ended September 30, 2004, we have recognized a deferred tax benefit of $909,000 related to Canadian legislation which was enacted in May 2004 to phase in reduced income tax rates and allow for deductibility of crown royalties. SFAS No. 109 and EITF 93-13 require that the tax effect of a change in enacted tax rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.

All severance payments paid or payable in respect of employees terminated up to May 31, 2005 were borne by EXCO. If Purchaser or its affiliates makes an employment offer to a terminated employee and the employee accepts the offer, Purchaser is obligated to pay EXCO an amount equal to 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. There were no additional employee terminations between closing and May 31, 2005.

We have recognized a gain from the sale of Addison in the amount of U.S. $175.7 million before income tax expense of U.S. $50.1 million related to the gain. The cumulative adjustment resulting from the foreign currency 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 7¼% senior notes due 2011 (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 of cash equivalents, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. An additional U.S. $75.8 million of proceeds from the Addison disposition were applied to temporarily pay down borrowings under our U.S. credit agreement to a nominal amount. The remaining Addison disposition proceeds of U.S. $130.3 million were invested in short-term investments as permitted under our U.S. credit agreement and our senior notes. The net cash proceeds from the Addison disposition as determined under the indenture governing our senior notes was U.S. $326.8 million and may be used only in accordance with the terms of the indenture. Section 4.07 of the indenture governing our senior notes 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. See “Note 7. Credit Agreements,” “Note 8. Issuance of Senior Notes and the Acquisition of North Coast Energy, Inc.” and "Note 10. Equity Buyout, ONEOK Energy Acquisition and Other Transactions" for information concerning an offer made to repurchase up to $120.6 million in senior notes in accordance with Section 4.07 of the indenture.

3. Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligations as of September 30, 2004 and 2005 (in thousands of dollars):

	Nine Months Ended
	September 30,
	2004			2005
	(Unaudited)

Asset retirement obligation at January 1	$	17,742		$	28,043
Activity during the nine months ended September 30:
Sale of Addison Energy Inc.	—			(14,796		)
Liabilities incurred during period	9,472			1,686
Liabilities settled during period	(2,449		)	(1,275		)
Accretion of discount	1,258			612
Effect of foreign currency conversions	404			—
Asset retirement obligation as of September 30	26,427			14,270
Less current portion	1,325			1,713
Long-term portion	$	25,102		$	12,557

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, $22.2 million in unproved oil and natural gas properties, of which $3.4 million was for Addison properties, and at September 30, 2005, $22.0 million in unproved oil and natural gas properties were excluded from our full cost pool in calculating our depreciation, depletion and amortization. We assess our unproved oil and natural gas properties for impairment on a quarterly basis.

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

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

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

The calculation of the ceiling test is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the

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

In September 2004, the SEC released Staff Accounting Bulletin (SAB) No. 106 concerning the application of SFAS No. 143 by oil and natural gas producing companies following the full cost method of accounting. In SAB No. 106, the SEC addressed the impact of SFAS No. 143 on the ceiling test calculation and on the calculation of depreciation, depletion and amortization. Our adoption of SAB No. 106 effective January 1, 2005 did not have a significant impact upon our ceiling test calculation or on our calculation of depreciation, depletion and amortization.

5. Segment Information

The only industry segment in which we operate is the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. Our operating segments are EXCO and North Coast in the United States and, until February 10, 2005, Addison in Canada. The following tables provide our interim operating segment data.

							Total
				North			United			Discontinued
	EXCO			Coast			States			Operations			Total
	(In thousands)
Three months ended September 30, 2004:
Revenues and other income:
Oil and natural gas	$	16,614		$	18,635		$	35,249		$	—		$	35,249
Commodity price risk management activities	(13,226		)	(16,690		)	(29,916		)	—			(29,916		)
Other income (expense)	(235		)	173			(62		)	—			(62		)
Total revenues and other income	3,153			2,118			5,271			—			5,271

Costs and expenses:
Oil and natural gas production	4,295			3,158			7,453			—			7,453
Depreciation, depletion and amortization	3,783			3,989			7,772			—			7,772
Accretion of discount on asset retirement obligations	97			102			199			—			199
General and administrative	2,741			899			3,640			—			3,640
Interest	8,862			26			8,888			—			8,888
Total costs and expenses	19,778			8,174			27,952			—			27,952
Loss from continuing operations before income taxes	(16,625		)	(6,056		)	(22,681		)	—			(22,681		)
Income tax benefit	(714		)	(2,651		)	(3,365		)	—			(3,365		)
Loss from continuing operations	(15,911		)	(3,405		)	(19,316		)	—			(19,316		)
Discontinued operations:
Income from operations	1,791			—			1,791			8,882			10,673
Income tax expense	—			—			—			2,447		��	2,447
Income from discontinued operations	1,791			—			1,791			6,435			8,226
Net income (loss)	$	(14,120	)	$	(3,405	)	$	(17,525	)	$	6,435		$	(11,090	)
Total assets at end of period	$	253,596		$	250,942		$	504,538		$	352,275		$	856,813
Goodwill at end of period	$	21,558		$	—		$	21,558		$	29,952		$	51,510

							Total
				North			United			Discontinued
	EXCO			Coast			States			Operations		Total
	(In thousands)
Three months ended September 30, 2005:
Revenues and other income:
Oil and natural gas	$	20,928		$	30,843		$	51,771		$	—	$	51,771
Commodity price risk management activities	(35,848		)	(71,657		)	(107,505		)	—		(107,505		)
Interest and other income	2,733			668			3,401			—		3,401
Total revenues and other income (loss)	(12,187		)	(40,146		)	(52,333		)	—		(52,333		)

Costs and expenses:
Oil and natural gas production	3,731			3,865			7,596			—		7,596
Depreciation, depletion and amortization	3,696			5,079			8,775			—		8,775
Accretion of discount on asset retirement obligations	88			119			207			—		207
General and administrative	2,891			1,505			4,396			—		4,396
Interest	9,186			—			9,186			—		9,186
Total costs and expenses	19,592			10,568			30,160			—		30,160
Loss from continuing operations before income taxes	(31,779		)	(50,714		)	(82,493		)	—		(82,493		)
Income tax benefit	(10,506		)	(22,272		)	(32,778		)	—		(32,778		)
Loss from continuing operations	(21,273		)	(28,442		)	(49,715		)	—		(49,715		)
Discontinued operations:
Income from discontinued operations	—			—			—			—		—
Gain on disposition of Addison Energy Inc.	—			—			—			—		—
Income tax benefit	—			—			—			—		—
Income from discontinued operations	—			—			—			—		—
Net loss	$	(21,273	)	$	(28,442	)	$	(49,715	)	$	—	$	(49,715	)
Total assets at end of period	$	463,849		$	446,615		$	910,464		$	—	$	910,464
Goodwill at end of period	$	19,984		$	—		$	19,984		$	—	$	19,984

							Total
				North			United			Discontinued
	EXCO			Coast			States			Operations			Total
	(In thousands)
										(As Restated)			(As Restated)
Nine months ended September 30, 2004:
Revenues and other income:
Oil and natural gas	$	49,555		$	50,565		$	100,120		$	—		$	100,120
Commodity price risk management activities	(36,155		)	(33,040		)	(69,195		)	—			(69,195		)
Other income	430			457			887			—			887
Total revenues and other income	13,830			17,982			31,812			—			31,812

Costs and expenses:
Oil and natural gas production	13,002			8,119			21,121			—			21,121
Depreciation, depletion and amortization	10,718			10,242			20,960			—			20,960
Accretion of discount on asset retirement obligations	338			269			607			—			607
General and administrative	8,561			2,714			11,275			—			11,275
Interest	25,307			180			25,487			—			25,487
Total costs and expenses	57,926			21,524			79,450			—			79,450
Loss from continuing operations before income taxes	(44,096		)	(3,542		)	(47,638		)	—			(47,638		)
Income tax benefit	(9,459		)	(2,450		)	(11,909		)	(909		)	(12,818		)
Income (loss) from continuing operations	(34,637		)	(1,092		)	(35,729		)	909			(34,820		)
Discontinued operations:
Income from operations	3,323			—			3,323			21,559			24,882
Income tax expense	—			—			—			7,462			7,462
Income from discontinued operations	3,323			—			3,323			14,097			17,420
Net income (loss)	$	(31,314	)	$	(1,092	)	$	(32,406	)	$	15,006		$	(17,400	)
Total assets at end of period	$	253,596		$	250,942		$	504,538		$	352,275		$	856,813
Goodwill at end of period	$	21,558		$	—		$	21,558		$	29,952		$	51,510

							Total
				North			United			Discontinued
	EXCO			Coast			States			Operations			Total
	(In thousands)
	(As Restated)						(As Restated)			(As Restated)			(As Restated)
Nine months ended September 30, 2005:
Revenues and other income:
Oil and natural gas	$	54,642		$	76,827		$	131,469		$	—		$	131,469
Commodity price risk management activities	(56,704		)	(120,549		)	(177,253		)	—			(177,253		)
Interest and other income	5,762			1,263			7,025			—			7,025
Total revenues and other income (loss)	3,700			(42,459		)	(38,759		)	—			(38,759		)

Costs and expenses:
Oil and natural gas production	11,329			10,650			21,979			—			21,979
Depreciation, depletion and amortization	11,277			13,213			24,490			—			24,490
Accretion of discount on asset retirement obligations	275			337			612			—			612
General and administrative	11,721			3,849			15,570			—			15,570
Interest	26,502			—			26,502			—			26,502
Total costs and expenses	61,104			28,049			89,153			—			89,153
Loss from continuing operations before income taxes	(57,404		)	(70,508		)	(127,912		)	—			(127,912		)
Income tax benefit	(14,249		)	(39,761		)	(54,010		)	—			(54,010		)
Loss from continuing operations	(43,155		)	(30,747		)	(73,902		)	—			(73,902		)
Discontinued operations:
Loss from discontinued operations	—			—			—			(4,402		)	(4,402		)
Gain on disposition of Addison Energy Inc.	—			—			—			175,717			175,717
Income tax expense	—			—			—			49,282			49,282
Income from discontinued operations	—			—			—			122,033			122,033
Net income (loss)	$	(43,155	)	$	(30,747	)	$	(73,902	)	$	122,033		$	48,131
Total assets at end of period	$	463,849		$	446,615		$	910,464		$	—		$	910,464
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 September 30, 2005. The fair values at September 30, 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 September 30, 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.

		Weighted Average		Weighted Average			Fair Value at
	Volume	Strike Price per		Differential to			September 30,
	Mmbtus/Bbls	Mmbtu/Bbl		NYMEX			2005
	(In thousands, except prices and differentials)
Natural Gas:
Swaps:
Remainder of 2005	3,818	$	7.08				$	(26,187	)
2006	14,418	6.93					(66,769		)
2007	12,410	6.58					(37,195		)
2008	9,150	7.52					(9,016		)
2009	1,825	4.51					(4,973		)
2010	1,825	4.51					(3,801		)
2011	1,825	4.51					(3,201		)
2012	1,830	4.51					(2,820		)
2013	1,825	4.51					(2,508		)
	48,926						(156,470		)
Basis Protection Swaps:
Remainder of 2005	226			$	(0.57	)	547
	226						547
Floor Prices:
Remainder of 2005	267	4.25					—
	267						—
Total Natural Gas							(155,923		)

Oil:
Swaps:
Remainder of 2005	55	52.84					(743		)
2006	237	67.04					72
2007	201	64.99					36
2008	183	63.00					9
Total Oil	676						(626		)
Total Oil and Natural Gas							$	(156,549	)

At September 30, 2005, the average forward NYMEX oil prices per Bbl for the remainder of calendar 2005 and for 2006 were $66.62 and $66.72, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of calendar 2005 and for 2006 were $14.07 and $11.46, respectively.

7. Credit Agreements

At September 30, 2005, we had $1,000 of outstanding indebtedness. Pursuant to an interim bank loan (Interim Bank Loan) incurred by Holdings II in connection with the Equity Buyout on October 3, 2005, total advances under our U.S. credit agreement cannot exceed $10.0 million until the Interim Bank Loan is repaid in full. Borrowings under our amended and restated U.S. credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast 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. This security interest was released in conjunction with the commencement of the senior notes purchase offer on November 2, 2005 related to the sale of Addison (Addison senior notes purchase offer). 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 September 30, 2005, the six month LIBOR rate was 4.23%, which would result in an interest rate of approximately 5.48% on any new indebtedness we may incur under the U.S. credit agreement.

Because the Equity Buyout constituted a change of control under the indenture governing our senior notes, on November 2, 2005 we also commenced an offer to purchase the senior notes at a price of 101% of the principal amount of senior notes. The change of control offer will be funded with cash on hand, funds held by the indenture trustee after the expiration of the Addison senior notes purchase offer, and funds to be provided under a new credit facility. The Addison senior notes purchase offer expires on December 2, 2005 and the change of control purchase offer expires on December 9, 2005.

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 senior notes on April 13, 2004 did not impact the borrowing base under the Canadian credit agreement. (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 $105.0 million (Cdn. $141.7 million using the exchange rate on June 25, 2004). Effective October 8, 2004, the borrowing base was reaffirmed 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 September 30, 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 $350.0 million 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. In addition, our U.S. credit agreement and the indenture governing our senior notes (see “Note 8. Issuance of Senior Notes and the Acquisition of North Coast Energy, Inc.”) currently prohibit us from paying dividends on our common stock. Even if our U.S. credit agreement and the indenture governing our senior notes permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.

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 pursuant to a tender offer and merger on January 27, 2004 for a purchase price of $167.8 million and we assumed $57.1 million of North Coast’s outstanding indebtedness. As a result, on January 27, 2004, North Coast became a wholly-owned subsidiary and established a new core operating area for us in the Appalachian Basin. We have accounted for the North Coast acquisition using the purchase method of accounting and have consolidated its operations effective January 27, 2004.

On January 20, 2004, we completed the private placement of $350.0 million aggregate principal amount of senior notes 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.

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 statements of operations as interest expense.

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

On May 28, 2004, we concluded an exchange offer of $450.0 million aggregate principal amount of our senior notes, which were privately placed in January and April 2004, for $450.0 million aggregate principal amount of our senior notes that have been registered under the Securities Act. Holders of all but $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, January 18, 2005 and July 15, 2005 in the amounts of $15.9 million, $16.3 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. As a result of the Equity Buyout, on October 3, 2005 a change of control purchase offer was commenced on November 2, 2005 and will expire on December 9, 2005. On November 2, 2005, we also commenced the Addison senior notes purchase offer to the holders of our senior notes to purchase their senior notes at 100% of the principal amount of the senior notes plus accrued and unpaid interest. The Addison sale senior notes purchase offer will expire on December 2, 2005. See “Note 10. Equity Buyout, ONEOK Energy Acquisition and Other Transactions” for additional information about this offer.

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

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

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

• make investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

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

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

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

The estimated fair value of our senior notes was $468.0 million as compared to the carrying amount of $452.6 million (including $2.6 million of unamortized premium) at September 30, 2005. The fair value of the senior notes is estimated based on quoted market prices for the senior notes.

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 nine months ended September 30, 2004 has been derived from our unaudited consolidated statement of operations for the nine months ended September 30, 2004 and North Coast’s unaudited consolidated financial statement of operations for the 26 day period from January 1 to January 26, 2004. The pro forma results of operations give effect to the following events as if each occurred on January 1, 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 SFAS 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 acquisition of North Coast by EXCO that have been recognized as an increase in net loss in the following table.

	Nine Months
	Ended
	September 30, 2004
	(Unaudited, in thousands)

Revenues and other income	$	38,522
Net loss from continuing operations	$	(37,668	)
Net loss	$	(19,339	)

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 nine months ended September 30, 2005

During the nine months ended September 30, 2005, we completed seven oil and natural gas property acquisitions. Estimated total Proved Reserves net to our interest from the acquisitions included approximately 0.1 Mmbbls of oil and 59.8 Bcf of natural gas. The total purchase price for the acquisitions was approximately $102.3 million, funded with borrowings under our U.S. credit agreement and from surplus cash. In addition, we acquired a small natural gas gathering system for $700,000 as part of one of the acquisitions.

During the nine months ended September 30, 2005, we completed seven sales of oil and natural gas properties. As of January 1, 2005, estimated total Proved Reserves net to our interest from these properties included approximately 0.3 Mmbbls of oil and NGLs and 18.4 Bcf of natural gas. The total sales proceeds we received were approximately $45.4 million. During the nine months ended September 30, 2004, we recorded revenue of approximately $5.0 million and oil and natural gas production costs of approximately $913,000 on these properties. During the nine months ended September 30, 2005, we recorded revenues of approximately $3.7 million and oil and natural gas production costs of approximately $1.2 million on these properties through the date of their respective dispositions.

Transactions, other than the acquisition of North Coast, that occurred during the nine months ended September 30, 2004

During the nine months ended September 30, 2004, we completed four oil and natural gas property acquisitions in the United States. Estimated total Proved Reserves net to our interest from these acquisitions included approximately 0.3 Mmbbls of oil and NGLs and 25.0 Bcf of natural gas. The purchase price for the acquisitions was approximately $44.7 million funded from surplus cash.

During the nine months ended September 30, 2004, we completed 18 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 4.1 Mmbbls of oil and NGLs and 14.4 Bcf of natural gas. The total sales proceeds we received were approximately $23.4 million. During the first nine months of 2004, we recorded revenue of approximately $5.3 million and oil and natural gas production costs of $2.0 million on these properties through the date of their respective dispositions.

10. Equity Buyout, ONEOK Energy Acquisition and Other Transactions

Equity Buyout

On October 3, 2005, Holdings II completed the purchase of all of the outstanding shares of capital stock of Holdings for an aggregate purchase price of approximately $700.0 million. Holdings II was a Delaware corporation controlled by a group of investors led by Douglas H. Miller, the Chairman and Chief Executive Officer of Holdings and EXCO. The Equity Buyout was funded by a combination of (i) $350.0 million under the Interim Bank Loan, (ii) approximately $183.1 million from the issuance of Holdings II common stock to new private equity investors and EXCO employees and (iii) the exchange of Holdings Class A and Class B common stock valued at approximately $166.9 million for Holdings II common stock. Holdings’ majority stockholder sold all of its shares for cash.

Promptly following the consummation of the Equity Buyout, Holdings II merged with and into Holdings (Holdings II Merger). As a result of the Holdings II Merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of Holdings common stock. In addition, all shares of Holdings Class A and Class B common stock held by Holdings II were cancelled in connection with the Holdings II Merger. The Equity Buyout will be accounted for as a purchase pursuant to SFAS No. 141, “Business Combinations.”

GAAP requires the application of “push down accounting” in situations where the ownership of an entity has changed. Holdings II is deemed to be the accounting acquirer of Holdings. The assets and liabilities of Holdings II will be recorded at their fair value and, under SAB No. 54, that fair value will be pushed down to us. Accordingly, the financial statements for periods subsequent to October 2, 2005, will reflect Holdings' (as successor by merger to Holdings II) stepped-up basis resulting from the acquisition which has been pushed down to us. The aggregate purchase price will be allocated to the underlying assets and liabilities based upon the estimated values at October 3, 2005 (date of acquisition and merger). Carryover basis applies for tax purposes.

The table below shows the estimated preliminary allocation of the pushed down acquisition cost. The amounts are based upon estimated fair value information available as of September 30, 2005 and will be adjusted to reflect values at the acquisition date (in thousands):

Acquisition cost calculations:
Payments for shares including options	$	504,216
Exchange of Holdings II shares for EXCO Holdings shares	166,884
Assumption of 7¼% senior notes ($452,643 aggregate book value plus $15,357 premium to fair value)	468,000
Assumption of long-term debt	1
Less cash assumed of $236,371, less the payment of $10,834 of cash compensation related to the Equity Buyout	(225,537		)
Total acquisition cost to be pushed down	$	913,564

Allocation of acquisition cost:
Oil and natural gas properties-proved	$	852,196
Oil and natural gas properties-unproved	58,573
Total oil and natural gas properties	910,769
Gas gathering assets and other equipment	33,246
Other assets, reflecting the reduction of deferred debt issuance costs of $8,862 to zero	285
Goodwill	249,363
Other current assets	88,231
Accounts payable and accrued expenses	(135,303		)
Asset retirement obligations and other long-term liabilities	(15,243		)
Oil and natural gas derivative liabilities	(77,780		)
Deferred income taxes	(140,004		)
Total allocation	$	913,564

We have revised our estimates of the acquisition cost and the allocation of the cost in these financial statements.

Pursuant to the Holdings II Merger, the indebtedness incurred by Holdings II to fund the Equity Buyout was assumed by Holdings. The indebtedness is not guaranteed by us, or secured by our assets. However, if the Interim Bank Loan is not repaid by July 3, 2006, EXCO has agreed to redeem, in accordance with the terms of the indenture governing the senior notes, all of the senior notes by that date and to guarantee the indebtedness outstanding under the Interim Bank Loan.

As a result of the Equity Buyout and the push down accounting described above, we will be recording stock based and other compensation expense for the following items during the fourth quarter of 2005:

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

• the holders of the Class A shares were to receive the first $175.0 million in proceeds, and

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

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

• A charge of $17.8 million for payments made to holders of options to purchase Class A shares of Holdings less options held by the ESPP. This amount was paid to option holders at the time of the Equity Buyout by Holdings to purchase all stock options outstanding at that time. The amount represents the cumulative difference between the $5.197 per share purchase price for the Equity Buyout for the Class A shares and the exercise price of outstanding stock options times the number of stock options outstanding.

• A charge of $8.3 million for payments made to our employees who were participants in the Employee

Stock Participation Plan (ESPP). This amount was paid at the time of the Equity Buyout and was based upon shares of Holdings Class A and Class B stock that were reserved, but unissued, and options granted to the ESPP under the Holdings Plan. All employees on the date of the Equity Buyout who were not direct owners of Holdings Class A or Class B stock received payments under the ESPP. For financial accounting purposes, the ESPP was considered to be a “variable” plan since vesting was contingent upon a change of control and a recipient had to be employed at the date of the change of control to receive a payment. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.

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

• Holdings II adopted the 2005 Long-Term Incentive Plan (the 2005 Incentive Plan) which provides for the granting of options to purchase up to 10,000,000 shares of Holdings (formerly Holdings II) common stock. On October 5, 2005, options were granted under the 2005 Incentive Plan to our employees and directors to purchase 4,985,950 shares of Holdings common stock at $7.50 per share. The options expire on October 5, 2015. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As a result of the new basis of accounting due to the Equity Buyout, we will adopt the provisions of SFAS No. 123(R), “Share Based Payments” as of October 3, 2005. This will result in a non-cash charge to stock option compensation expense during the fourth quarter of 2005. We have not completed our evaluation of the impact that the adoption of SFAS No. 123(R) will have for the fourth quarter of 2005, or subsequent periods, on our results of operations.

Subsequent to the Holdings II Merger, EXCO intends to pursue an equity capital transaction, the net proceeds of which will be applied to repay indebtedness incurred to fund the Equity Buyout and the ONEOK Energy acquisition. Assuming this equity capital transaction is successful, Holdings will merge with and into us.

ONEOK Energy Acquisition

On September 16, 2005, Holdings II incorporated TXOK Acquisition, Inc. (TXOK), a Delaware corporation, with a $1,000 investment in TXOK common stock. TXOK was formed to acquire (i) all of the issued and outstanding shares of common stock of ONEOK Energy Resources Company (ONEOK Energy) and (ii) all of the issued and outstanding membership interests of ONEOK Energy Resources Holdings, LLC (ONEOK Energy LLC) (collectively, ONEOK Energy). ONEOK Energy was wholly-owned by ONEOK, Inc., a Tulsa-based public utility company.

The ONEOK Energy acquisition closed on September 27, 2005. The purchase price paid at closing, based upon adjustments as of that date, was $642.9 million. Effective upon closing, ONEOK Energy and ONEOK Energy LLC became wholly-owned subsidiaries of TXOK and a cost method investment of Holdings II.

TXOK funded the ONEOK Energy acquisition with (i) $20.0 million in private debt financing, $15.0 million of which was provided by Mr. Boone Pickens, one of Holdings’ (as successor by merger to Holdings II) directors; (ii) the issuance of $150.0 million of TXOK preferred stock to BP EXCO Holdings LP, an entity controlled by Mr. Pickens; (iii) the TXOK credit facility, with an initial borrowing base of $325.0 million, of which approximately $308.8 million was drawn at the closing of the ONEOK Energy acquisition; and (iv) the TXOK second lien term loan facility for $200.0 million. Neither Holdings (as survivor of the merger with Holdings II) nor EXCO is an obligor, guarantor or a pledgor of its assets with respect to these financings. The proceeds TXOK received under the facilities in excess of the purchase price were used to fund the fees and expenses of the ONEOK Energy acquisition with the remainder being held for working capital purposes.

stock currently hold voting control of TXOK, and Holdings accounts for its investment in TXOK under the cost method of accounting. If the TXOK preferred stock is not redeemed on or before September 27, 2006, the TXOK preferred stock and accumulated dividends will automatically convert into common stock representing 90% of the outstanding common stock of TXOK.

The properties acquired in the ONEOK Energy acquisition include 1,041 gross (445.1 net) producing oil and natural gas wells in Texas and Oklahoma. ONEOK Energy has Proved Reserves (estimated as of July 31, 2005) of approximately 223.3 Bcfe of oil and natural gas and 151 miles of natural gas gathering lines. The acquired properties produced an average of 905 barrels of oil per day and 47.7 Mmcf of natural gas per day during September 2005.

We hired 57 people who were formerly employed by ONEOK, Inc. and historically worked on these assets. These employees are directing the TXOK operations. All compensation expenses of these employees are to be reimbursed to us by TXOK. In addition, we are providing general management, treasury, finance, legal, audit, tax, information technology, and payroll and benefit administration services. TXOK is reimbursing us for all costs incurred on behalf of TXOK and paying us $25,000 per month for the additional services that we provide.

The private investors, including one of our directors, who funded a total of $20.0 million in loans to TXOK to fund the $19.4 million in deposits paid in connection with the ONEOK Energy acquisition also entered into contracts with TXOK to render financial advisory services to TXOK pursuant to which they were paid approximately $4.9 million on October 7, 2005.

Other Transactions

Offers to Purchase Senior Notes

As a result of the Equity Buyout, EXCO must offer holders of our 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. As a result of this change of control, on November 2, 2005, we commenced an offer to purchase the senior notes at 101% of the principal amount plus accrued and unpaid interest on the senior notes. On November 2, 2005, we also commenced an offer to purchase up to $120.6 million of outstanding senior notes at 100% of the principal amount plus accrued and unpaid interest in connection with the asset sale provision contained in the indenture as a result of the Addison sale. The $120.6 million sum represents the proceeds remaining from the Addison sale that have not previously been applied to the permanent repayment of indebtedness or used in our business for acquisitions and capital expenditures pursuant to Section 4.07 of the indenture. Upon completion of the Addison senior notes purchase offer, the security interest in $120.6 million of the proceeds from the sale and the general restrictions under Section 4.07 of the indenture on the entire amount of proceeds shall terminate.

Off-Balance Sheet Arrangements

On October 3, 2005, EXCO entered into an agreement in connection with the Interim Bank Loan incurred by Holdings II to fund the Equity Buyout. The principal amount outstanding under the Interim Bank Loan is $350.0 million. Pursuant to the terms of the agreement, EXCO agreed to redeem all of its outstanding senior notes if the Interim Bank Loan is not repaid on or prior to July 3, 2006. Upon completion of the redemption, if any, EXCO and its subsidiaries have agreed to deliver guarantees of the exchange notes issuable by Holdings upon maturity of the Interim Bank Loan.

11. Income Taxes

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

For the nine months ended September 30, 2005 and 2004, the effective income tax benefit rate on losses from continuing operations was 42.2% and 26.8%, respectively. The nine months ended September 30, 2005 included tax benefits of $132,000 resulting from new tax legislation in the State of Ohio, where North Coast conducts substantial business operations. The nine months ended September 30, 2005 also includes a $2.1 million tax benefit related to an extraordinary dividend received from Addison, formerly our wholly-owned Canadian subsidiary which was sold in February 2005. This benefit was the result of clarification issued by the Department of the Treasury on May 10, 2005 to the American Jobs Creation Act of 2004 (the Act). The Act created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. This additional $2.1 million benefit is recognized as a component of taxes from continuing operations pursuant to SFAS No. 109 and EITF 93-13, which require that a tax effect of a change in enacted tax rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.

The nine months ended September 30, 2004 includes $909,000 of a tax benefit attributable to Canadian legislation which was enacted in May 2004 and phased in reduced income tax rates and provided for the deduction of crown royalties. Although the results of Addison are reflected as discontinued operations, this benefit is reflected as a component of continuing operations as required by SFAS No. 109 and EITF 93-13.

The following table presents a reconciliation of our income tax benefit computed by applying the statutory United States federal income tax rate to our income (loss) before taxes from continuing operations for the three and nine months ended September 30, 2004 and 2005, respectively:

	Three months ended September 30,						Nine months ended September 30,
	2004			2005			2004			2005
	(in thousands)
United States federal income taxes (benefit) at statutory rate of 35%	$	(7,938	)	$	(28,873	)	$	(16,673	)	$	(44,769	)

Increases (reductions) resulting from:

Non-deductible charges (non-taxable income)	(14		)	(25		)	(51		)	(70		)

Percentage depletion in excess of basis	—			(482		)	—			(827		)

Changes in tax legislation in the State of Ohio	—			598			—			(132		)

Change in U.S. tax law related to dividend from Canadian subsidiary	—			—			—			(2,075		)

Change in Canadian tax rates	—			—			(909		)	—

Adjustment to the valuation allowance	4,182			—			4,182			—

State taxes net of federal benefit and other	405			(3,996		)	633			(6,137		)

Income tax benefit, as restated	$	(3,365	)	$	(32,778	)	$	(12,818	)	$	(54,010	)

12. Restatement

On November 14, 2005, as part of EXCO’s review of its third quarter financial statements, EXCO reviewed a possible misapplication of Statement of Financial Accounting Standards No. 109, Accounting for Income Tax (SFAS No. 109) relating to the recording of an income tax benefit on a dividend received in February 2005 from Addison Energy Inc. (Addison), EXCO’s former wholly-owned Canadian subsidiary. On October 22, 2004, the American Jobs Creation Act of 2004 (the Act) was enacted into law. The Act created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. EXCO repatriated Cdn. $74.5 million (U.S. $59.6 million) in an extraordinary dividend, as defined in the Act, from Addison on February 9, 2005. At December 31, 2004, certain technical corrections to the Act had been identified and legislation to effect the corrections had been proposed to be enacted. On May 10, 2005, the Treasury Department issued Notice 2005-38 in which it stated that the Treasury Department would follow the proposed corrective legislation. The Treasury Department further stated that another technical release would be issued at a later date discussing the methodology for making certain computations in regard to the Act. However, EXCO believed that there still remained substantial questions as to whether or not the application of Notice 2005-38 provided sufficient clarification of an uncertain tax position as required under SFAS No. 109 to recognize the income tax benefit arising from the technical corrections and questions remained regarding calculation of the tax benefit thereunder.

There was further administrative guidance issued by the Treasury Department under Notice 2005-64 on August 19, 2005. EXCO believed that this additional guidance provided sufficient evidence as required under SFAS No. 109. As a result, EXCO planned to recognize the benefit of $2.1 million during the three months ended September 30, 2005. However, after reconsideration of Notice 2005-38, EXCO management concluded that this benefit should have been recognized in the quarter ended June 30, 2005. SFAS No. 109 requires that the entire tax effect of a change in enacted tax rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations. The impact of this restatement to the nine months ended September 30, 2005 condensed consolidated financial statements is presented in the following table.

	Nine Months Ended September 30, 2005
	As Previously Reported			Adjustments			As Restated
Loss from continuing operations before income taxes	$	(127,912	)	$	—		$	(127,912	)
Income tax benefit	(51,935		)	(2,075		)	(54,010		)
Income (loss) from continuing operations	(75,977		)	2,075			(73,902		)
Income (loss) from discontinued operations	124,108			(2,075		)	122,033
Net income	$	48,131		$	—		$	48,131

In addition, in the nine months ended September 30, 2004, a tax benefit had been recorded, as a component of discontinued operations, for changes in Canadian legislation which reduced income tax rates and allowed for the deductibility of crown royalties. Our financial statements have been restated to reclassify this benefit as a component of continuing operations pursuant to SFAS No. 109 and EITF 93-13. The impact of this restatement is as follows:

	Nine Months Ended September 30, 2004
Condensed Consolidated Statements of Operations:	As Reported			Adjustments			As Restated
Income (loss) from continuing operations before income taxes	$	(47,638	)	$	—		$	(47,638	)
Income tax benefit	(11,909		)	(909		)	(12,818		)
Income (loss) from continuing operations	(35,729		)	909			(34,820		)
Income from discontinued operations	18,329			(909		)	17,420
Net income (loss)	$	(17,400	)	$	—		$	(17,400	)

13. Consolidating Financial Statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary. The senior notes are jointly and severally and unconditionally guaranteed by our current and some of our future subsidiaries in the United States (referred to as Guarantor Subsidiaries). All of our subsidiaries are wholly-owned. Addison was not a guarantor of the senior notes. Instead, the senior notes were collateralized, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison. This share pledge 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 collateralized by a second-priority security interest in 100% of the capital stock of Taurus, 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, which are not required to be pledged under the indenture, are subject to the indenture’s reinvestment provisions.

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 subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments 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

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary			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)

September 30, 2005

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary		Eliminations			Consolidated
	(In thousands)
Assets
Current assets:
Cash and cash equivalents	$	215,856		$	20,515		$	—	$	—		$	236,371
Other current assets	40,757			47,474			—		—			88,231
Total current assets	256,613			67,989			—		—			324,602
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	—			22,026			—		—			22,026
Proved developed and undeveloped oil and natural gas properties	67,548			487,020			—		—			554,568
Allowance for depreciation, depletion and amortization	(13,012		)	(41,055		)	—		—			(54,067		)
Oil and natural gas properties, net	54,536			467,991			—		—			522,527
Gas gathering, office and field equipment, net	2,499			28,234			—		—			30,733
Goodwill	19,984			—			—		—			19,984
Investments in and advances to affiliates	468,912			2,600			—		(471,512		)	—
Other assets, net	3,201			9,417			—		—			12,618
Total assets	$	805,745		$	576,231		$	—	$	(471,512	)	$	910,464

Liabilities and Shareholder’s Equity
Current liabilities	$	72,292		$	63,011		$	—	$	—		$	135,303
Long-term debt	452,644			—			—		—			452,644
Other liabilities	50,294			41,708			—		—			92,002
Payable to parent	—			395,196			—		(395,196		)	—
Commitments and contingencies	—			—			—		—			—
Shareholder’s equity	230,515			76,316			—		(76,316		)	230,515
Total liabilities and shareholder’s equity	$	805,745		$	576,231		$	—	$	(471,512	)	$	910,464

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Three Months Ended September 30, 2004

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary		Eliminations			Consolidated
	(In thousands)
Revenues and other income:
Oil and natural gas sales	$	10,039		$	25,210		$	—	$	—		$	35,249
Commodity price risk management activities	(13,226		)	(16,690		)	—		—			(29,916		)
Other income (loss)	2,628			190			—		(2,880		)	(62		)
Equity in earnings of subsidiaries	5,441			—			—		(5,441		)	—
Total revenues and other income (loss)	4,882			8,710			—		(8,321		)	5,271

Costs and expenses:
Oil and natural gas production	3,106			4,347			—		—			7,453
Depreciation, depletion and amortization	1,942			5,830			—		—			7,772
Accretion of discount on asset retirement obligations	36			163			—		—			199
General and administrative	2,741			899			—		—			3,640
Interest	8,861			1,116			—		(1,089		)	8,888
Total costs and expenses	16,686			12,355			—		(1,089		)	27,952
Loss from continuing operations before income taxes	(11,804		)	(3,645		)	—		(7,232		)	(22,681		)
Income tax benefit	(714		)	(2,651		)	—		—			(3,365		)
Loss from continuing operations	(11,090		)	(994		)	—		(7,232		)	(19,316		)
Discontinued operations:
Income from operations	—			—			8,883		1,790			10,673
Income tax expense	—			—			2,447		—			2,447
Income from discontinued operations	—			—			6,436		1,790			8,226
Net income (loss)	$	(11,090	)	$	(994	)	$	6,436	$	(5,442	)	$	(11,090	)

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Three Months Ended September 30, 2005

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary		Eliminations			Consolidated
	(In thousands)
Revenues and other income:
Oil and natural gas sales	$	8,695		$	43,076		$	—	$	—		$	51,771
Commodity price risk management activities	(35,848		)	(71,657		)	—		—			(107,505		)
Interest and other income	7,727			757			—		(5,083		)	3,401
Equity in earnings of subsidiaries	(25,500		)	—			—		25,500			—
Total revenues and other income (loss)	(44,926		)	(27,824		)	—		20,417			(52,333		)

Costs and expenses:
Oil and natural gas production	1,879			5,717			—		—			7,596
Depreciation, depletion and amortization	1,271			7,504			—		—			8,775
Accretion of discount on asset retirement obligations	77			130			—		—			207
General and administrative	2,892			1,504			—		—			4,396
Interest	9,186			5,083			—		(5,083		)	9,186
Total costs and expenses	15,305			19,938			—		(5,083		)	30,160
Income (loss) from continuing operations before income taxes	(60,231		)	(47,762		)	—		25,500			(82,493		)
Income tax benefit	(10,516		)	(22,262		)	—		—			(32,778		)
Income (loss) from continuing operations	(49,715		)	(25,500		)	—		25,500			(49,715		)
Discontinued operations:
Loss from operations	—			—			—		—			—
Gain on disposition of Addison Energy Inc.	—			—			—		—			—
Income tax expense	—			—			—		—			—
Income from discontinued operations	—			—			—		—			—
Net income (loss)	$	(49,715	)	$	(25,500	)	$	—	$	25,500		$	(49,715	)

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Nine Months Ended September 30, 2004

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary			Eliminations			Consolidated
							(In thousands)
							(As Restated)						(As Restated)
Revenues and other income:
Oil and natural gas sales	$	31,879		$	68,241		$	—		$	—		$	100,120
Commodity price risk management activities	(36,155		)	(33,040		)	—			—			(69,195		)
Other income	6,511			559			—			(6,183		)	887
Equity in earnings of subsidiaries	20,687			—			—			(20,687		)	—
Total revenues and other income	22,922			35,760			—			(26,870		)	31,812

Costs and expenses:
Oil and natural gas production	9,836			11,285			—			—			21,121
Depreciation, depletion and amortization	5,843			15,117			—			—			20,960
Accretion of discount on asset retirement obligations	234			373			—			—			607
General and administrative	8,561			2,714			—			—			11,275
Interest	25,307			3,040			—			(2,860		)	25,487
Total costs and expenses	49,781			32,529			—			(2,860		)	79,450
Income (loss) from continuing operations before income taxes	(26,859		)	3,231			—			(24,010		)	(47,638		)
Income tax benefit	(9,459		)	(2,450		)	(909		)	—			(12,818		)
Income (loss) from continuing operations	(17,400		)	5,681			909			(24,010		)	(34,820		)
Discontinued operations:
Income from operations	—			—			21,559			3,323			24,882
Gain on disposition of Addison Energy Inc.	—			—			—			—			—
Income tax expense	—			—			7,462			—			7,462
Income from discontinued operations	—			—			14,097			3,323			17,420
Net income (loss)	$	(17,400	)	$	5,681		$	15,006		$	(20,687	)	$	(17,400	)

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Nine Months Ended September 30, 2005

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary			Eliminations			Consolidated
							(In thousands)
	(As Restated)												(As Restated)
Revenues and other income:
Oil and natural gas sales	$	22,326		$	109,143		$	—		$	—		$	131,469
Commodity price risk management activities	(56,704		)	(120,549		)	—			—			(177,253		)
Interest and other income (loss)	31,657			1,663			—			(26,295		)	7,025
Equity in earnings of subsidiaries	(39,956		)	—			—			39,956			—
Total revenues and other income (loss)	(42,677		)	(9,743		)	—			13,661			(38,759		)

Costs and expenses:
Oil and natural gas production	6,304			15,675			—			—			21,979
Depreciation, depletion and amortization	3,885			20,605			—			—			24,490
Accretion of discount on asset retirement obligations	235			377			—			—			612
General and administrative	11,721			3,849			—			—			15,570
Interest	26,424			26,373			—			(26,295		)	26,502
Total costs and expenses	48,569			66,879			—			(26,295		)	89,153
Loss from continuing operations before income taxes	(91,246		)	(76,622		)	—			39,956			(127,912		)
Income tax benefit	(14,273		)	(39,737		)	—			—			(54,010		)
Loss from continuing operations	(76,973		)	(36,885		)	—			39,956			(73,902		)
Discontinued operations:
Loss from operations	—			—			(4,402		)	—			(4,402		)
Gain on disposition of Addison Energy Inc.	175,717			—			—			—			175,717
Income tax expense (benefit)	50,613			—			(1,331		)	—			49,282
Income (loss) from discontinued operations	125,104			—			(3,071		)	—			122,033
Net income (loss)	$	48,131		$	(36,885	)	$	(3,071	)	$	39,956		$	48,131

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

For the Three Months Ended September 30, 2004

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by (used in) operating activities	$	(19,422	)	$	21,141		$	23,235		$	—	$	24,954
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(14,129		)	(36,158		)	(31,681		)	—		(81,968		)
Proceeds from disposition of oil and natural gas properties	9,586			20			—			—		9,606
Advances/investments with affiliates	(16,299		)	14,448			1,867			—		16
Other investing activities	515			—			538			—		1,053
Net cash used in investing activities	(20,327		)	(21,690		)	(29,276		)	—		(71,293		)
Financing Activities:
Proceeds from long-term debt	34,499			—			16,759			—		51,258
Payments on long-term debt	(17,500		)	—			(5,153		)	—		(22,653		)
Deferred financing costs	(6		)	—			60			—		54
Net cash provided by financing activities	16,993			—			11,666			—		28,659
Net increase (decrease) in cash	(22,756		)	(549		)	5,625			—		(17,680		)
Cash at beginning of period	30,571			10,115			2,136			—		42,822
Effect of exchange rates on cash and cash equivalents	—			—			562			—		562
Cash at end of period	$	7,815		$	9,566		$	8,323		$	—	$	25,704

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

For the Three Months Ended September 30, 2005

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary		Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by (used in) operating activities	$	(15,011	)	$	17,853		$	—	$	—	$	2,842
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(2,896		)	(93,198		)	—		—		(96,094		)
Proceeds from disposition of oil and natural gas properties	3,018			35,071			—		—		38,089
Proceeds from sale of Addison Energy Inc., net of cash sold	—			—			—		—
Advances/investments with affiliates	(32,006		)	31,978			—		—		(28		)
Other investing activities	—			627			—		—		627
Net cash used in investing activities	(31,884		)	(25,522		)	—		—		(57,406		)
Financing Activities:
Proceeds from long-term debt	—			—			—		—		—
Payments on long-term debt	—			—			—		—		—
Deferred financing costs	—			—			—		—		—
Other financing activities	—			—			—		—		—
Net cash provided by financing activities	—			—			—		—		—
Net decrease in cash	(46,895		)	(7,669		)	—		—		(54,564		)
Cash at beginning of period	262,729			28,206			—		—		290,935
Cash at end of period	$	215,834		$	20,537		$	—	$	—	$	236,371

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

For the Nine Months Ended September 30, 2004

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by (used in) operating activities	$	(4,802	)	$	53,146		$	40,068		$	—	$	88,412
Investing Activities:
Acquisition of North Coast Energy, Inc., less cash acquired	(225,562		)	10,429			—			—		(215,133		)
Additions to oil and natural gas properties, gathering systems and equipment	(23,626		)	(49,933		)	(70,581		)	—		(144,140		)
Proceeds from disposition of oil and natural gas properties	20,238			3,180			—			—		23,418
Advances/investments with affiliates	(120,651		)	(7,256		)	127,983			—		76
Other investing activities	1,296			—			423			—		1,719
Net cash provided by (used in) investing activities	(348,305		)	(43,580		)	57,825			—		(334,060		)
Financing Activities:
Proceeds from long-term debt	494,850			—			16,759			—		511,609
Payments on long-term debt	(124,070		)	—			(108,146		)	—		(232,216		)
Deferred financing costs	(13,230		)	—			102			—		(13,128		)
Net cash provided by (used in) financing activities	357,550			—			(91,285		)	—		266,265
Net increase in cash	4,443			9,566			6,608			—		20,617
Effect of exchange rates on cash and cash equivalents	—			—			(2,246		)	—		(2,246		)
Cash at beginning of period	3,372			—			3,961			—		7,333
Cash at end of period	$	7,815		$	9,566		$	8,323		$	—	$	25,704

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF CASH FLOWS (Unaudited)

For the Nine Months Ended September 30, 2005

	EXCO			Guarantor			Non-Guarantor
	Resources			Subsidiaries			Subsidiary			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by (used in) operating activities	$	(76,636	)	$	14,747		$	(19,158	)	$	—	$	(81,047	)
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(24,323		)	(126,859		)	(444		)	—		(151,626		)
Proceeds from disposition of oil and natural gas properties	7,714			37,669			—			—		45,383
Proceeds from sale of Addison Energy Inc., net of cash sold	444,812			—			(1,415		)	—		443,397
Advances/investments with affiliates	(37,663		)	86,859			(48,985		)	—		211
Other investing activities	59			627			—			—		686
Net cash provided by (used in) investing activities	390,599			(1,704		)	(50,844		)	—		338,051
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 and other financing activities	305			—			—			—		305
Net cash provided by (used in) financing activities	(106,642		)	—			59,601			—		(47,041		)
Net increase (decrease) in cash	207,321			13,043			(10,401		)	—		209,963
Cash at beginning of period	8,535			7,472			10,401			—		26,408
Cash at end of period	$	215,856		$	20,515		$	—		$	—	$	236,371

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

Forward-Looking Statements

This quarterly report contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act.

These forward-looking statements relate to, among other things, the following:

• our future financial and operating performance and results;

• our business strategy;

• market prices;

• our future commodity price risk management activities; and

• our plans and forecasts.

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

• fluctuations in prices of oil and natural gas;

• future capital requirements and availability of financing;

• estimates of reserves;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

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

• cash flow and liquidity;

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

• availability of drilling and production equipment;

• marketing of oil and natural gas;

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

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

• competition;

• general economic conditions;

• governmental regulations;

• receipt of amounts owed to us by purchasers of our production and counterparties to our commodity price risk management contracts;

• hedging decisions, including whether or not to enter into derivative financial instruments;

• events similar to those of September 11, 2001;

• actions of third party co-owners of interests in properties in which we also own an interest; and

• fluctuations in interest rates.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our 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 our cash proceeds from the sale of Addison Energy Inc. (Addison), surplus cash and 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, including our acquisition of Addison, on property and corporate acquisitions. We spent an additional $103.3 million on property and lease acquisitions during the first nine months of 2005.

On January 27, 2004, we acquired all of the outstanding common stock of North Coast Energy, Inc. (North Coast) for a purchase price of approximately $225.1 million, including the assumption of $57.1 million in outstanding bank debt. We funded the acquisition of North Coast through the issuance of $350.0 million in 7¼% senior notes due 2011 (senior notes) on January 20, 2004. On April 13, 2004 we issued an additional $100.0 million in senior 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, Taurus Acquisition, Inc. (Taurus), now known as ROJO Pipeline, Inc. The aggregate purchase price was Cdn. $551.3 million (U.S. $443.3 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.

As discussed in “Note 12. Restatement” to the condensed consolidated financial statements, we restated our unaudited financial statements for the nine months ended September 30, 2004 and 2005, respectively.

Equity Buyout, ONEOK Energy Acquisition and Other Recent Transactions

Equity Buyout

On October 3, 2005, EXCO Holdings II, Inc. (Holdings II) completed the purchase of all of the outstanding shares of capital stock of EXCO Holdings Inc. (Holdings) for an aggregate purchase price of approximately $700.0 million (Equity Buyout). Holdings II was a Delaware corporation controlled by a group of investors led by Douglas H. Miller, the Chairman and Chief Executive Officer of Holdings. The Equity Buyout was funded by a combination of (i) $350.0 million of interim loan indebtedness (Interim Bank Loan), (ii) approximately $183.1 million from the issuance of Holdings II common stock to new private equity investors and EXCO employees and (iii) the exchange of Holdings Class A and Class B common stock valued at approximately $166.9 million for Holdings II common stock. Holdings’ majority stockholder sold all of its shares for cash.

GAAP requires the application of “push down accounting” in situations where the ownership of an entity has changed. Holdings II is deemed to be the accounting acquirer of Holdings. The assets and liabilities of Holdings II will be recorded at their fair value and, under SAB No. 54, that fair value will be pushed down to us. Accordingly, the financial statements for periods subsequent to October 2, 2005, will reflect Holdings (as successor by merger to Holdings II) stepped-up basis resulting from the acquisition which has been pushed down to us. The aggregate purchase price will be allocated to the underlying assets and liabilities based upon the estimated values at October 3, 2005 (date of acquisition and merger). Carryover basis applies for tax purposes.

Acquisition cost calculations:
Payments for shares including options	$	504,216
Exchange of Holdings II shares for EXCO Holdings shares	166,884
Assumption of 7¼% senior notes ($452,643 aggregate book value plus $15,357 premium to fair value)	468,000
Assumption of long-term debt	1
Less cash assumed of $236,371, less the payment of $10,834 of cash compensation related to the Equity Buyout	(225,537		)
Total acquisition cost to be pushed down	$	913,564

Allocation of acquisition cost:
Oil and natural gas properties-proved	$	852,196
Oil and natural gas properties-unproved	58,573
Total oil and natural gas properties	910,769
Gas gathering assets and other equipment	33,246
Other assets, reflecting the reduction of deferred debt issuance costs of $8,862 to zero	285
Goodwill	249,363
Other current assets	88,231
Accounts payable and accrued expenses	(135,303		)
Asset retirement obligations and other long-term liabilities	(15,243		)
Oil and natural gas derivative liabilities	(77,780		)
Deferred income taxes of $143,475 at an average marginal tax rate of 39.1%(1), net of $3,471 reclass of historical deferred tax assets	(140,004		)
Total allocation	$	913,564

(1) Marginal tax rate includes federal income taxes at 35.0% plus a blended state tax rate of 4.1%

We have revised our estimates of the cost and the allocation of the cost in these financial statements.

• the holders of the Class A shares were to receive the first $175.0 million in proceeds, and

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

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

• A charge of $17.8 million for payments made to holders of options to purchase Class A shares of Holdings less options held by the ESPP. This amount was paid to option holders at the time of the Equity Buyout by Holdings to purchase all stock options outstanding at that time. The amount represents the cumulative difference between the $5.197 per share purchase price for the Equity Buyout for the Class A shares and the exercise price of the outstanding stock options times the number of stock options outstanding.

• A charge of $8.3 million for payments made to our employees who were participants in the Employee Stock Participation Plan (ESPP). This amount was paid at the time of the Equity Buyout and was based upon shares of Holdings Class A and Class B stock that were reserved, but unissued, and options granted to the ESPP under the Holdings Plan. All employees on the date of the Equity Buyout who were not direct owners of Holdings Class A or Class B stock received payments under the ESPP. For financial accounting purposes, the ESPP was considered to be a “variable” plan since, to be eligible, a recipient had to be employed at the date of the change of control to receive a payment. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.

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

ONEOK Energy Acquisition

On September 16, 2005, Holdings II incorporated TXOK Acquisition, Inc. (TXOK), a Delaware

corporation with a $1,000 investment in TXOK common stock. TXOK was formed to acquire (i) all of the issued and outstanding shares of common stock of ONEOK Energy Resources Company (ONEOK Energy) and (ii) all of the issued and outstanding membership interests of ONEOK Energy Resources Holdings, LLC (ONEOK Energy LLC) (collectively, ONEOK Energy). ONEOK Energy was wholly-owned by ONEOK, Inc., a Tulsa-based public utility company.

On October 7, 2005, EXCO advanced $4.0 million to Holdings (formerly Holdings II), which when combined with cash at Holdings, was used to fund an additional $20.0 million investment in TXOK Class B common stock by Holdings. The TXOK preferred stock currently has full voting rights to vote with the TXOK common stock on all matters submitted to a vote by stockholders. Accordingly, holders of the TXOK preferred stock currently hold voting control of TXOK, and Holdings accounts for its investment in TXOK under the cost method of accounting. If the TXOK preferred stock is not redeemed on or before September 27, 2006, the TXOK preferred stock and accumulated dividends will automatically convert into common stock representing 90% of the outstanding common stock of TXOK.

Other Transactions

Offers to Purchase Senior Notes

provision contained in the indenture as a result of the Addison sale. The $120.6 million sum represents the proceeds remaining from the Addison sale that have not previously been applied to the permanent repayment of indebtedness or used in our business for acquisitions and capital expenditures pursuant to Section 4.07 of the indenture. Upon completion of the offer to purchase related to the Addison sale, the security interest in $120.6 million of the proceeds from the sale and the general restrictions under Section 4.07 of the indenture on the entire amount of proceeds shall terminate.

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, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.

We prepared our condensed 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. 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, 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, we had 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. As of September 30, 2005, this valuation allowance and its associated deferred tax asset have been written off because it was deemed worthless.

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, 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 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 was carried over from the formerly public company as a result of the merger. The going private purchase price was allocated to the assets acquired and liabilities assumed according to their estimated fair values. The purchase price allocation resulted in $51.1 million of goodwill being recorded, $24.2 million in 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 September 30, 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 the going private transaction to December 31, 2004 were the result of sales of oil and natural gas properties (based upon the relative fair value of our oil and natural gas properties prior to and after the sales) and the sale of a bankruptcy claim related to Enron Corp. In a 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 accounted for 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 planned disposition of Addison, we considered Addison’s earnings to be permanently reinvested for use in those operations and, consequently, deferred federal income taxes, net of applicable foreign tax credits, had not been provided on the undistributed earnings of Addison that were reinvested. As a result of the sale of Addison, we provided for deferred federal income taxes in the fourth quarter of 2004 on the undistributed earnings of Addison.

Recent Accounting Pronouncements

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.

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

Our Results of Operations

The following is a discussion of our financial condition and results of operations for the three and nine month periods ended September 30, 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 oil and natural gas prices which impact our oil and natural gas revenues and our commodity price risk management activities.

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 natural 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 (Unaudited)”). As a result, we have treated Addison’s operating results as discontinued operations on the condensed consolidated statements of operations for the three and nine month periods ended September 30, 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 and nine month periods ended September 30, 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 on January 27, 2004.

	Three months ended				Quarter to			Nine months ended				Year to year
	September 30,				quarter change			September 30,				change
	2004		2005		2004-2005			2004		2005		2004-2005
	(Unaudited, in thousands)
Oil and natural gas revenues before commodity price risk management activities:
Oil revenues:
EXCO	$	5,125	$	5,337	$	212		$	16,102	$	15,000	$	(1,102	)
North Coast	1,237		1,945		708			2,850		4,388		1,538
Total	$	6,362	$	7,282	$	920		$	18,952	$	19,388	$	436
Natural gas revenues:
EXCO	$	10,891	$	15,401	$	4,510		$	32,011	$	39,094	$	7,083
North Coast	17,399		28,898		11,499			47,715		72,440		24,725
Total	$	28,290	$	44,299	$	16,009		$	79,726	$	111,534	$	31,808
Natural gas liquids revenues:
EXCO	$	597	$	190	$	(407	)	$	1,442	$	547	$	(895	)
North Coast	—		—		—			—		—		—
Total	$	597	$	190	$	(407	)	$	1,442	$	547	$	(895	)
Total oil and natural gas revenues:
EXCO	$	16,613	$	20,928	$	4,315		$	49,555	$	54,641	$	5,086
North Coast	18,636		30,843		12,207			50,565		76,828		26,263
Total	$	35,249	$	51,771	$	16,522		$	100,120	$	131,469	$	31,349

	Three months ended		Quarter to		Nine months ended		Year to year
	September 30,		quarter change		September 30,		change
	2004	2005	2004-2005		2004	2005	2004-2005
	(Unaudited)
Production:
Oil (Mbbls):
EXCO	121	89	(32	)	434	288	(146	)
North Coast	32	33	1		81	84	3
Total	153	122	(31	)	515	372	(143	)
Natural gas (Mmcf):
EXCO	2,145	2,097	(48	)	6,267	6,296	29
North Coast	2,718	2,982	264		7,569	8,906	1,337
Total	4,863	5,079	216		13,836	15,202	1,366
Natural gas liquids (Mbbls):
EXCO	18	6	(12	)	49	18	(31	)
North Coast	—	—	—		—	—	—
Total	18	6	(12	)	49	18	(31	)
Total production (Mmcfe):
EXCO	2,979	2,667	(312	)	9,165	8,132	(1,033	)
North Coast	2,910	3,180	270		8,055	9,410	1,355
Total	5,889	5,847	(42	)	17,220	17,542	322

	Three months ended				Quarter to			Nine months ended				Year to year
	September 30,				quarter change			September 30,				change
	2004		2005		2004-2005			2004		2005		2004-2005
	(Unaudited)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl):
EXCO	$	42.36	$	59.97	$	17.61		$	37.10	$	52.09	$	14.99
North Coast	38.66		58.94		20.28			35.19		52.24		17.05
Total	41.59		59.69		18.10			36.80		52.12		15.32
Natural gas (per Mcf):
EXCO	$	5.08	$	7.34	$	2.26		$	5.11	$	6.21	$	1.10
North Coast	6.40		9.69		3.29			6.30		8.13		1.83
Total	5.82		8.72		2.90			5.76		7.34		1.58
Natural gas liquids (per Bbl):
EXCO	$	33.17	$	31.67	$	(1.50	)	$	29.43	$	30.39	$	0.96
North Coast	—		—		—			—		—		—
Total	33.17		31.67		(1.50		)	29.43		30.39		0.96
Total average sales price (per Mcfe):
EXCO	$	5.58	$	7.85	$	2.27		$	5.41	$	6.72	$	1.31
North Coast	6.40		9.70		3.30			6.28		8.16		1.88
Total	5.99		8.85		2.86			5.81		7.49		1.68

Our revenues from the sale of oil, natural gas and NGLs, before cash settlements of derivative financial instruments, for the three and nine month periods ended September 30, 2005 increased by $16.5 million and $31.3 million, respectively, or 47% and 31%, respectively, over the three and nine month periods ended September 30, 2004 primarily due to an increase of $2.86 per equivalent Mcf for the three month period ended September 30, 2005 and $1.68 for the nine month period ended September 30, 2005 in our average sales price.

The increases in our weighted average sales prices increased our revenues by $16.3 million and $27.5 million, respectively, for the three and nine month periods ended September 30, 2005 over the comparable periods during 2004.

Oil production declined while oil revenues for EXCO increased during the three month period ended September 30, 2005 compared to the same period in 2004. The increase in revenue is primarily attributable to the higher prices for oil. For the nine months ended September 30, 2005, oil production decreased by 146 Mbbls due to the combination of property sales and general production decline. Oil revenues declined by $1.1 million reflecting the lower production which was partially offset by higher prices for the period.

At EXCO, natural gas production decreased by 48 Mmcf and increased by 29 Mmcf during the three and nine months ended September 30, 2005, respectively, compared to the same periods during 2004. For the three months ended September 30, 2005 compared to 2004, production from the Oak Hill Field (acquired in July 2004) and from the Minden Field (acquired in January 2005) increased production by 529 Mmcf. This increase was more than offset by the absence of the production from properties sold during 2004 and 2005 of 345 Mmcf, an expected decline in production from our Miami Corp #35-1 well of 145 Mmcf and other changes of 87 Mmcf. For the nine months ended September 30, 2005 compared to 2004, production primarily from the Oak Hill and Minden Fields increased production by 1,880 Mmcf. This increase was substantially offset by the absence of the production from properties sold during 2004 and 2005 of 1,231 Mmcf and an expected decline in production from our Miami Corp. #35-1 well of 620 Mmcf.

At North Coast, natural gas production increased by 264 Mmcf and 1,337 Mmcf during the three and nine months ended September 30, 2005 compared to the same periods during 2004. For the three months ended September 30, 2005 compared to 2004, production from the Pinestone properties, and other properties acquired since the fourth quarter of 2004, increased production by 538 Mmcf. These increases were partially offset by the expected decline in production and some production curtailment from our Knox trend wells of 235 Mmcf. Production for the three months ended September 30, 2005 was further impacted by production curtailments of approximately 39 Mmcf imposed upon us by natural gas pipeline companies resulting from capacity restraints and short-term shut downs of certain pipelines for maintenance purposes. For the nine months ended September 30, 2005 compared to 2004, production increased as a result of having 26 additional days of production during the 2005 period as we acquired North Coast on January 27, 2004. Production was further increased by 997 Mmcf from the Pinestone properties and the production from North Coast acquisitions closed during the third quarter of 2005 of 176 Mmcf. These increases were offset by reduced production from the Knox trend wells of 280 Mmcf and the curtailments as discussed above.

The following tables present our commodity price risk management activities and our other income (expense) for the three and nine month periods ended September 30, 2004 and 2005. The tables also show changes in these amounts between periods.

	Three months ended						Quarter to			Nine months ended						Year to year
	September 30,						quarter change			September 30,						change
	2004			2005			2004-2005			2004			2005			2004-2005
	(Unaudited, in thousands)
Commodity price risk management activities:
Cash settlements on derivative financial instruments	$	(6,841	)	$	(6,167	)	$	674		$	(18,000	)	$	(62,843	)	$	(44,843	)
Non-cash change in fair value of derivative financial instruments	(23,075		)	(101,338		)	(78,263		)	(51,195		)	(114,410		)	(63,215		)
Total commodity price risk management activities	$	(29,916	)	$	(107,505	)	$	(77,589	)	$	(69,195	)	$	(177,253	)	$	(108,058	)

	Three months ended					Quarter to		Nine months ended					Year to year
	September 30,					quarter change		September 30,					change
	2004			2005		2004-2005		2004			2005		2004-2005
	(Unaudited, in thousands)
Other income (loss), net:
Gain (loss) from foreign currency transactions	$	(376	)	$	437	$	813	$	(5	)	$	516	$	521
Interest, dividend and other, net	314			2,964		2,650		892			6,509		5,617
Total other income (loss), net	$	(62	)	$	3,401	$	3,463	$	887		$	7,025	$	6,138

Our commodity price risk management activities reduced revenue by $29.9 million and $69.2 million during the three and nine month periods ended September 30, 2004, respectively, and by $107.5 million and $177.3 million for the three and nine month periods ended September 30, 2005, respectively. Included in the $62.8 million cash settlements on derivative financial instruments for the nine months ended September 30, 2005 are payments totaling $52.6 million made in January and March 2005 to the counterparties of certain of our contracts to terminate these contracts. In January and March 2005, we entered into new commodity price risk management contracts for increased volumes at higher underlying product prices. There have been significant increases in the NYMEX oil and natural gas prices that are used to settle our derivative financial instruments over the oil and natural gas prices of our contracts. The increases in prices resulted in us making significant payments to our counterparties to settle our derivative financial instruments during the three and nine month periods ended September 30, 2004 and 2005 and our revenues decreased as a result. We also had a significant increase in the volume of natural gas under derivative financial instruments to reflect the increase in our natural gas production as a result of the acquisition of North Coast.

For the three months ended September 30, 2004 and 2005, we recognized as a reduction of revenue $23.1 million and $101.3 million, respectively, from the change in the fair value of our derivative financial instruments. For the nine months ended September 30, 2004 and 2005, we recognized as a reduction of revenue $51.2 million and $114.4 million, respectively, from the change in the fair value of our derivative financial instruments. We expect that our revenues will continue to be significantly impacted in future periods by changes in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices and the volume of future oil and natural gas sales covered under our commodity price risk management program. For the nine months ended September 30, 2005, the following percentages of our oil and natural gas production were subject to derivative financial instruments: 49% and 70% of oil and natural gas production, respectively, were subject to swap agreements and 5% of natural gas production was subject to floor price agreements.

The increase in other income during the three and nine month periods ended September 30, 2005 when compared to the same periods in 2004 is primarily the result of interest income earned on the investment of the proceeds received from the sale of Addison and increases in the value of foreign currencies attributable to estimated income tax refunds denominated in Canadian dollars.

Costs and Expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production costs per Mcfe for the three and nine month periods ended September 30, 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				Quarter to			Nine months ended				Year to year
	Septemer 30,				quarter change			September 30,				change
	2004		2005		2004-2005			2004		2005		2004-2005
	(Unaudited, in thousands)
Oil and natural gas production costs:
Oil and natural gas operating costs:
EXCO	$	2,951	$	2,100	$	(851	)	$	9,315	$	6,694	$	(2,621	)
North Coast	2,349		2,780		431			5,977		7,778		1,801
Total	$	5,300	$	4,880	$	(420	)	$	15,292	$	14,472	$	(820	)
Production and ad valorem taxes:
EXCO	$	1,344	$	1,631	$	287		$	3,687	$	4,635	$	948
North Coast	809		1,085		276			2,142		2,870		728
Total	$	2,153	$	2,716	$	563		$	5,829	$	7,505	$	1,676
Total oil and natural gas production costs:
EXCO	$	4,295	$	3,731	$	(564	)	$	13,002	$	11,329	$	(1,673	)
North Coast	3,158		3,865		707			8,119		10,648		2,529
Total	$	7,453	$	7,596	$	143		$	21,121	$	21,977	$	856

	Three months ended				Quarter to			Nine months ended				Year to year
	September 30,				quarter change			September 30,				change
	2004		2005		2004-2005			2004		2005		2004-2005
	(Unaudited)
Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs:
EXCO	$	0.99	$	0.79	$	(0.20	)	$	1.02	$	0.83	$	(0.19	)
North Coast	0.81		0.87		0.06			0.74		0.82		0.08
Total	0.83		0.83		—			0.89		0.83		(0.06		)
Production and ad valorem taxes:
EXCO	$	0.45	$	0.61	$	0.16		$	0.40	$	0.57	$	0.17
North Coast	0.28		0.34		0.06			0.27		0.31		0.04
Total	0.37		0.46		0.09			0.34		0.43		0.09
Total oil and natural gas production costs:
EXCO	$	1.44	$	1.40	$	(0.04	)	$	1.42	$	1.40	$	(0.02	)
North Coast	1.09		1.21		0.12			1.01		1.13		0.12
Total	1.20		1.29		0.09			1.23		1.26		0.03

Our oil and natural gas operating costs for the three month period ended September 30, 2005 decreased $420,000, or 8% from the same period in 2004. The net decrease reflects lower operating expenses at EXCO of $850,000 which were partially offset by increased expenses at North Coast. Significant components of the increases from North Coast properties include:

• the acquisition of Pinestone properties (acquired in November and December 2004);

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

• increased operating expenses of $176,000 resulting from other North Coast properties acquired since the fourth quarter of 2004;

• a general increase in the cost of goods and services used in our oil and natural gas operations during 2004 and 2005; and

• new wells added through our development and exploitation capital program.

These increases were partially offset by the absence of lease operating costs from high operating cost properties sold by EXCO during 2004 and 2005.

Our oil and natural gas operating costs for the nine month period ended September 30, 2005 decreased $820,000, or 4% 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;

• property acquisitions including EXCO’s Oak Hill Field (acquired in July 2004) and Minden Field properties (acquired on January 21, 2005), North Coast’s Pinestone properties (acquired in November and December 2004), and additional acquisitions closed by North Coast during the third quarter of 2005;

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

• a general increase in the cost of goods and services used in our oil and natural gas operations during 2004 and 2005; and

• new wells added through our development and exploitation capital program.

The oil and natural gas operating cost per unit for EXCO decreased by $0.20 to $0.79 per Mcfe for the three months ended September 30, 2005 over the same period in 2004. EXCO’s oil and natural gas operating cost per unit for the nine months ended September 30, 2005 decreased $0.19 to $0.83 per Mcfe compared to 2004 as the properties sold by EXCO discussed above had relatively high per unit operating costs. The oil and natural gas operating cost per unit for North Coast increased from $0.81 and $0.74 per Mcfe for the three and nine month periods ended September 30, 2004 to $0.87 and $0.82 per Mcfe for the three and nine month periods ended September 30, 2005. The increase is primarily a result of higher actual oil and natural gas operating costs (excluding the effect of the additional 26 days of operating results in 2005) without a comparable increase in oil and natural gas production volumes. Oil and natural gas operating costs increased primarily due to higher personnel related costs as discussed above, an increase in repair and maintenance costs and a general increase in the costs of goods and services used in our operations.

Production and ad valorem taxes for the three and nine month periods ended September 30, 2005 increased by $563,000 and $1.7 million, or 26% and 29%, over the same periods in 2004. These increases are primarily attributable to the increase in oil and natural gas revenues resulting from increased sales volumes of natural gas and higher oil and natural gas sales prices. The increases were partially offset by the absence of production taxes from oil and natural gas properties that were sold by EXCO in 2004 and 2005. Production taxes are set by the state and local governments and vary as to the tax rate and the value to which that rate is applied. Further, ad valorem taxes in Texas and other states are based partially on the value of oil and natural gas reserves, which have increased as a result of the higher oil and natural gas prices.

Our depreciation, depletion and amortization costs for the three and nine month periods ended September 30, 2005 increased by $1.0 million and $3.5 million, or 13% and 17%, from the same periods in 2004. The primary reasons for this increase result from an increase in the per unit depletion rate and, for the nine months ended

September 30, 2005, an increase in the equivalent sales volume during the period. The increase in the rate is due primarily to the average per unit prices paid for property acquisitions made during 2004 and 2005 being in excess of the prior period per unit depletion rate.

Accretion of discount on asset retirement obligations is a non-cash expense that measures the changes in the liability for an asset retirement obligation due to the passage of time by applying an interest method of allocation to the amount of the liability at the beginning of the period.

The following table presents our general and administrative costs for the three and nine month periods ended September 30, 2004 and 2005. The table also shows the changes in these amounts between periods.

	Three months ended						Quarter to			Nine months ended						Year to year
	September 30,						quarter change			September 30,						change
	2004			2005			2004-2005			2004			2005			2004-2005
	(Unaudited, in thousands, except per unit amounts)
General and administrative costs:
Gross G&A expense	$	4,526		$	5,252		$	726		$	13,872		$	18,041		$	4,169
Operator overhead charges	(530		)	(403		)	127			(1,632		)	(1,284		)	348
Capitalized acquisition and exploitation charges	(356		)	(453		)	(97		)	(965		)	(1,187		)	(222		)
Net G&A expense	$	3,640		$	4,396		$	756		$	11,275		$	15,570		$	4,295

General and administrative expense per Mcfe	$	0.62		$	0.75		$	0.13		$	0.65		$	0.89		$	0.24

Our general and administrative costs for the three months ended September 30, 2005 increased by $756,000, or 21% over the same period in 2004 and was attributable to increased personnel costs.

Our general and administrative costs for the nine months ended September 30, 2005 increased by $4.3 million, or 38% over the same period in 2004, and the increase was primarily attributable to:

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

• costs incurred of approximately $1.7 million in evaluating the tax and legal implications of the various strategic alternatives being considered in light of the sale of Addison;

• costs incurred of approximately $470,000 to comply with the provisions of the Sarbanes-Oxley Act; and

• costs incurred of approximately $200,000 for the sale of Addison.

• an increase of $1.4 million in salaries and related benefits of which $81,000 is the result of an additional 26 days of expenses resulting from our acquisition of North Coast on January 27, 2004. The remaining increase in salaries and related benefits is 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 $346,000 resulting from a reduction in overhead reimbursements received as a result of EXCO property sales during 2004 and 2005; and

• an increase of approximately $340,000 resulting primarily from increased franchise taxes of $206,000 and increased bad debt expense of $132,000.

The following table presents our interest expense for the three and nine month periods ended September 30, 2004 and 2005. The table also shows the changes in these amounts between periods.

	Three months ended				Quarter to			Nine months ended				Year to year
	September 30,				quarter change			September 30,				change
	2004		2005		2004-2005			2004		2005		2004-2005
	(Unaudited, in thousands)
Interest expense:
7¼% senior notes due 2011	$	7,957	$	8,657	$	700		$	20,679	$	24,765	$	4,086
U.S. credit agreement	215		94		(121		)	356		436		80
$50 million senior term loan	—		—		—			222		—		(222		)
Amortization and write-off of deferred financing costs	560		431		(129		)	3,596		1,297		(2,299		)
Interest rate swaps and other	156		4		(152		)	635		4		(631		)
Total interest expense	$	8,888	$	9,186	$	298		$	25,488	$	26,502	$	1,014

Our interest expense for the three months ended September 30, 2005 increased $298,000 from the same period in 2004. The increase is primarily due to an adjustment of $503,000 to interest expense related to $100.0 million aggregate principal amount of our senior notes issued in April 2004 at a price of 103.25% of the principal amount. This increase is partially offset by reduced interest expense under our U.S. credit agreement, amortization of deferred financing costs, and the absence of interest rate swaps in 2005 that we assumed in 2004 upon the acquisition of North Coast. Our interest expense for the nine months ended September 30, 2005 increased $1.0 million from the same period in 2004 due to increases in interest expense of $3.6 million attributable to $100.0 million of senior notes issued on April 13, 2004 and by $309,000 of the adjustment to interest expense attributable to the prior year. The increases of $3.9 million in 2005 are partially offset by lower interest costs associated with (i) $2.3 million of amortization and write-offs of deferred financing costs related to a bridge facility incurred in connection with the North Coast acquisition, (ii) the absence of $631,000 of expense from interest rate swaps we assumed in 2004 upon the acquisition of North Coast, and (iii) reduced interest expense from the U.S. credit facility of $222,000. No funds were borrowed under the bridge facility related to the North Coast acquisition.

Income Taxes

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. We repatriated Cdn. $74.5 million (U.S. $59.6 million) in an extraordinary dividend, as defined in the Act, from Addison on February 9, 2005. We recognized a tax liability of $8.2 million as of December 31, 2004 related to the extraordinary dividend. As a result of the proposed Tax Technical Correction Act of 2005 and certain Treasury Department notices, we reduced our current tax expense from continuing operations by $2.1 million in the second quarter of 2005. This tax benefit was reported as a component of income taxes from continuing operations pursuant to SFAS No. 109 and EITF 93-13, which require that tax effects of changes in enacted tax rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.

In June 2005, the state of Ohio enacted new legislation that changed the method of taxing businesses that operate in Ohio. We have significant operations in the state of Ohio through our North Coast subsidiary. As a result of the new tax legislation in Ohio, we recognized a deferred income tax benefit in the amount of $132,000 during the nine months ended September 30, 2005. The remaining income tax benefit for the three month period ended September 30, 2005 on income from continuing operations is primarily the result of state income tax benefits on our North Coast operations. The nine months ended September 30, 2005 also includes a $2.1 million tax benefit related to an extraordinary dividend received from Addison, our former wholly-owned Canadian subsidiary, and the $132,000 tax benefit from the State of Ohio tax legislation changes. These tax benefits increased the effective tax rate by 1.7% for the nine months ended September 30, 2005.

Our effective tax rate on losses from continuing operations for the nine month period ended September 30, 2005 approximated 42.2% as compared to an effective tax rate that approximated 26.8% for the nine month period ended September 30, 2004. The increase in the effective tax rate is a result of the benefit of $2.1 million related to the clarification of the Act, the deferred income tax benefit of $132,000 recognized for changes in Ohio tax laws and the result of higher state taxes in states in which North Coast operates, partially offset by the deferred income tax benefit of $909,000 during the nine months ended September 30, 2004 as a result of enacted changes in Canadian tax laws. Excluding the $2.2 million of credits in 2005 and the $909,000 credit in 2004 our effective tax rates would have been 37.3% and 25.0% for the nine month periods ended September 30, 2005 and 2004, respectively.

The Company incurred significant losses from mark-to-market transactions associated with its derivatives during the three months ended September 30, 2005. The resulting deferred tax benefits from these losses are presented as deferred tax assets on the September 30, 2005 Condensed Consolidated Balance Sheet. No valuation allowance has been established due to the anticipated step-up in the book basis of oil and natural gas producing properties as a result of the October 3, 2005 Equity Buyout, which will create deferred tax liabilities that will more than offset these deferred tax assets.

The following table presents a reconciliation of our income tax benefit computed by applying the statutory United States federal income tax rate to our income (loss) from continuing operations for the three and nine months ended September 30, 2004 and 2005, respectively:

	Three months ended September 30,						Nine months ended September 30,
	2004			2005			2004			2005
	(in thousands)
United States federal income taxes (benefit) at statutory rate of 35%	$	(7,938	)	$	(28,873	)	$	(16,673	)	$	(44,769	)

Increases (reductions) resulting from:

Non-deductible charges (non-taxable income)	(14		)	(25		)	(51		)	(70		)

Percentage depletion in excess of basis	—			(482		)	—			(827		)

Changes in tax legislation in the State of Ohio	—			598			—			(132		)

Change in U.S. tax law related to dividend from Canadian subsidiary	—			—			—			(2,075		)

Change in Canadian tax rates	—			—			(909		)	—

Adjustment to the valuation allowance	4,182			—			4,182			—

State taxes net of federal benefit and other	405			(3,996		)	633			(6,137		)

Income tax benefit, as restated	$	(3,365	)	$	(32,778	)	$	(12,818	)	$	(54,010	)

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 was Cdn. $551.3 million (U.S. $443.3 million) less the payment of the outstanding balance under Addison’s credit facility of Cdn. $90.1 million (U.S. $72.1 million) and other adjustments as specified in the purchase agreement. We have recognized a gain from the sale of Addison of U.S. $175.7 million before income tax expense of U.S. $50.1 million related to the gain. The income tax is composed of:

	Nine months ended
	September 30, 2005
	(Unaudited,
	in thousands)
U.S. income tax before foreign tax credits	$	50,128
Canadian income tax on the gain	33,717
U.S. foreign tax credit	(33,788		)
Total income tax on gain	$	50,057

Income taxes from discontinued operations for the nine months ended September 30, 2005 reflects the income tax on the gain of $50.1 million as discussed above, an income tax benefit of $1.3 million from Addison’s operations during the period January 1, 2005 to February 10, 2005, and approximately $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 nine months ended September 30, 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 received from the sales of oil and natural gas properties, cash flow from operations, bank financing and the sale or issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreement is subject to restrictions imposed by our lenders. In addition, our indenture governing our senior notes contains restrictions on incurring indebtedness and pledging our assets.

On February 10, 2005, we sold Addison for approximately $443.3 million after contractual adjustments. The net cash proceeds may only be utilized by us in accordance with the terms of the indenture governing the senior notes and our 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. The U.S. credit facility security interest was released in conjunction with the commencement of the senior notes purchase offer on November 2, 2005 related to the sale of Addison (the Addison senior notes purchase offer).

After the sale of Addison, we evaluated a number of strategic alternatives. On October 3, 2005, Holdings II, an entity formed by our management, completed the Equity Buyout by purchasing 100% of the outstanding equity of Holdings, our parent company, for an aggregate purchase price of approximately $700.0 million. To fund the Equity Buyout, Holdings II incurred $350.0 million of indebtedness under an Interim Bank Loan and raised $183.1 million of equity financing. Current management and other stockholders of Holdings exchanged Holdings capital stock for $166.9 million of Holdings II common stock. Immediately following the completion of these transactions, Holdings II merged with and into Holdings. We currently intend to pursue an equity capital transaction, the net proceeds of which will be applied to repay indebtedness incurred to fund the Equity Buyout and the TXOK transaction. Assuming this equity transaction is successful, Holdings will merge with and into us. The $350.0 million of indebtedness incurred by Holdings II is not part of our consolidated debt as of September 30, 2005.

On January 20, 2004, we issued $350.0 million aggregate principal amount of our senior notes. Additionally, on April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of our senior notes 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 $81.0 million for the nine months ended September 30, 2005. This was primarily the result of $67.6 million paid in January and March 2005 to terminate certain of our commodity price risk management contracts, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production, and approximately $50.1 million in U.S. and Canadian taxes incurred on the gain from the sale of Addison. These payments were funded by cash received from the sale of Addison. At September 30, 2005, our cash and cash equivalents balance was $236.4 million, an increase of $210.0 million from December 31, 2004 primarily as a result of the sale of Addison on February 10, 2005. On January 18, 2005 and July 15, 2005, we made interest payments on our senior notes totaling $32.6 million. Our working capital at September 30, 2005 increased to $189.3 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 nine months ended September 30, 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 senior notes.

The following table presents our capital expenditures for the nine months ended September 30, 2004 and 2005:

	Nine months ended
	September 30,
	2004		2005
	(Unaudited, in thousands)
Capital expenditures:
Property acquisitions	$	44,669	$	102,083
Acquisition of North Coast, net of cash acquired	215,133		—
Development capital expenditures	22,181		39,900
Other	4,276		5,884
Total capital expenditures	$	286,259	$	147,867

During the nine months ended September 30, 2005, we completed seven oil and natural gas property acquisitions. Estimated total Proved Reserves, net to our interest, includes approximately 60.4 Bcfe of natural gas. The total purchase price for the acquisitions was approximately $102.3 million. The acquisitions were funded with borrowings from our U.S. credit agreement and surplus cash.

For the year 2005, we have budgeted approximately $60.1 million for our development, exploitation and exploration activities in the United States. As of September 30, 2005, we had incurred $39.9 million and we were contractually obligated to spend $4.2 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.

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

In accordance with the terms of the indenture governing our senior notes, at the time of the closing of the Addison disposition, the security interest of the holders of our senior notes in two-thirds of the common stock of Addison was released and a second lien security interest (behind the first lien security interest under our U.S. credit agreement) was effected in U.S. $120.6 million of cash equivalents, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. An additional U.S. $75.9 million of proceeds from the Addison disposition were applied to temporarily pay down borrowings under our U.S. credit agreement to a nominal amount. The remaining Addison disposition proceeds of U.S. $130.3 million were invested in short-term investments as permitted under our U.S. credit agreement and the indenture governing 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 governing our senior notes. Section 4.07 of the indenture governing our senior notes 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. As of the date of this report on Form 10-Q, all but $120.6 million of net proceeds have been used to permanently reduce debt or have been reinvested in our business.

7¼% Senior Notes Due January 15, 2011

On January 20, 2004, we issued $350.0 million principal amount of our 7¼% 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 senior notes pursuant to Rule 144A at a price of 103.25% of the principal amount having the same terms and governed by the same indenture as the senior notes issued on January 20, 2004. Of the total proceeds of $103.3 million, approximately $98.8 million

was used to repay substantially all of our outstanding indebtedness under the Canadian credit agreement, approximately $1.2 million was used for fees and expenses associated with the offering, with the remainder, approximately $3.3 million, available for general working capital purposes.

As required by the 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.

Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011. Prior to January 15, 2007, we may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the senior notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the senior notes. On November 2, 2005, we commenced two offers to the holders of our senior notes to purchase their senior notes at 100% and 101%, respectively, of the principal amount of the senior notes plus accrued and unpaid interest. The offer at 100% of the principal amount of the senior notes (the Addison sale offer) is being made pursuant to Section 4.07 of the indenture governing the senior notes. Section 4.07 restricts our use of the net proceeds from the sale of Addison. The Addison sale offer is for up to $120.6 million of senior notes, which sum represents the net proceeds remaining from the sale of Addison. These proceeds are being held in escrow by the trustee for the senior notes pending completion of this offer. This offer expires on December 2, 2005. Upon expiration of the Addison sale offer the trustee will release from escrow any proceeds not used to purchase senior notes and such proceeds will no longer be restricted as to their use under Section 4.07.

The Equity Buyout constitutes a change of control under the indenture. As required by the indenture, we have commenced an offer to purchase all $450.0 million of senior notes outstanding at 101% of the principal amount plus accrued and unpaid interest through the date of purchase (the change of control offer). The change of control expires on December 9, 2005. In the event holders of senior notes tender any of their senior notes for purchase, we will fund any purchases first with available cash on hand, including the remaining net proceeds from the sale of Addison. If the tendered amount of senior notes exceeds our available cash on hand, we will fund any additional purchases with funds drawn under a new credit facility.

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.

U.S. Credit Agreement

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 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 and August 12, 2005, the borrowing base was reaffirmed at $145.0 million. The borrowing base will be redetermined each May 1 and November 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At September 30, 2005, we had $1,000 of outstanding indebtedness. Pursuant to the Interim Bank Loan incurred by Holdings II in connection with the Equity Buyout on October 3, 2005, total advances under our U.S. credit agreement cannot exceed $10.0 million until the Interim Bank Loan is repaid in full. Borrowings under our amended and restated U.S. credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. 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. This security interest was released in conjunction with the commencement of the Addison senior notes purchase offer on November 2, 2005. 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 September 30, 2005, the six month LIBOR rate was 4.23%, which would result in an interest rate of approximately 5.48% 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 September 30, 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 7¼% senior notes issued on January 20, 2004.

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

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 January and March 2005, we closed several of our commodity price risk management contracts upon the payment of $67.6 million to our counterparties, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production. We also entered into new commodity price risk management contracts at higher prices. As of October 31, 2005, we had contracts in place for the volumes and prices shown in the table below:

		Swaps				Floors
			Average		Average		Average
		Gas -	contract-		contract-	Gas -	contract-
		Mmbtus	$/Mmbtu	Oil-Bbls	$/Bbl	Mmbtus	$/Mmbtu
		(In thousands, except average contract prices)
Remainder of Q4	2005	2,532	7.19	37	52.84	177	4.25
	2006	14,418	6.93	237	67.04	—	—
	2007	12,410	6.58	201	64.99	—	—
	2008	10,980	7.62	183	63.00	—	—
	2009	1,825	4.51	—	—	—	—
	2010	1,825	4.51	—	—	—	—
	2011	1,825	4.51	—	—	—	—
	2012	1,830	4.51	—	—	—	—
	2013	1,825	4.51	—	—	—	—

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

Contractual Obligations and Commercial Commitments

The following table presents a summary of our contractual obligations at September 30, 2005 with set and determinable payments.

	Payments Due by Period
							2010 and
	2005		2006-2007		2008-2009		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)	26,383		103,856		13,980		12,330		156,549
Operating leases	916		5,002		4,210		1,436		11,564
Drilling/work commitments	4,171		—		—		—		4,171
Contract drilling commitment (4)	1,350		12,592		12,592		—		26,534
Management retention payments (5)	2,800		—		—		—		2,800
Total contractual cash obligations	$	35,620	$	121,451	$	30,782	$	463,766	$	651,619

(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 September 30, 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 (Unaudited)” for additional information regarding our derivative financial instruments.

(4) Agreement signed on November 4, 2005.

(5) Amounts paid in full as part of the October 3, 2005 Equity Buyout.

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 commodity price risk management activities as of October 31, 2005.

		Weighted Average		Fair Value at
	Volume	Strike Price Per		October 31,
	Mmbtus/Bbls	Mmbtu/Bbl		2005
	(In thousands, except prices)
Natural Gas:
Swaps:
Remainder of 2005	2,532	$	7.19	$	(14,805	)
2006	14,418	6.93		(56,944		)
2007	12,410	6.58		(35,322		)
2008	10,980	7.62		(8,290		)
2009	1,825	4.51		(4,781		)
2010	1,825	4.51		(3,689		)
2011	1,825	4.51		(3,063		)
2012	1,830	4.51		(2,632		)
2013	1,825	4.51		(2,300		)
	49,470			(131,826		)

Floor Prices:
Remainder of 2005	177	4.25		—
	177			—
Total Natural Gas				(131,826		)

Oil:
Swaps:
Remainder of 2005	37	52.84		(268		)
2006	237	67.04		1,378
2007	201	64.99		956
2008	183	63.00		771
Total Oil	658			2,837
Total Oil and Natural Gas				$	(128,989	)

At October 31, 2005, the average forward NYMEX oil prices per Bbl for the remainder of 2005 and for calendar 2006 were $60.24 and $61.13, respectively. The average forward NYMEX natural gas prices per Mmbtu for the remainder of 2005 and for calendar 2006 were $13.14 and $10.94, 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 October 31, 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 37,000 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 37,000 Bbls. For example, for a hedged volume of 37,000 Bbls, if the settlement price was $53.84, then commodity price risk management activities revenue would have decreased by $37,000. Conversely, if the settlement price was $51.84, commodity price risk management activities revenue would have increased by $37,000.

Interest Rate Risk

At September 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 7¼% on our $450.0 million in senior notes. As of September 30, 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—Our Liquidity, Capital Resources and Capital Commitments”. At September 30, 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 September 30, 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 J.P. Morgan Securities Inc. The commercial paper is issued by issuers having a credit rating of A1/P1 or better. Our principal risks with respect to these investments are interest rate risk and default risk. At September 30, 2005, we had approximately $204.5 million of such cash equivalent investments. On November 2, 2005, in conjunction with the Addison sale offer, we deposited $120.6 million with an indenture trustee. The funds are invested in U.S. government securities. A 1% change in market value would affect interest on these investments by approximately $2.0 million per year.

Foreign Currency Exchange Rate Risk

At September 30, 2005, we had a current receivable in the amount of Cdn. $14.6 million (U.S. $12.1 million) and a current payable in the amount of Cdn. $1.6 million (U.S. $1.4 million) related to the sale of Addison that are denominated in Canadian dollars. Foreign currency exchange gains and/or losses related to these amounts have not been significant. The receivable and payable are translated monthly using current exchange rates, with any resulting unrealized transaction gain or loss being recognized as other income (expense) in our statement of operations. As of September 30, 2005, we were not using any derivatives to manage foreign currency exchange rate risk. The liability was paid on October 11, 2005.

Equity Price Risk

Our investments in marketable equity securities are recorded at market value. We consider these investments to be “available for sale”, which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investments is “other than temporary”. As of September 30, 2005, we had no investments in marketable equity securities.

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) and Chief Financial Officer (CFO), who is also 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 Exchange Act). 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 and CFO/CAO, to allow timely decisions regarding required disclosures.

Based upon this evaluation, our CEO and CFO/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 this material weakness as discussed below, in preparing our financial statements as of and for the three and nine month periods ended September 30, 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.

Material Weakness

As discussed in Item 9A. Controls and Procedures beginning on page 125 of our Annual Report on Form 10-K for the period ended December 31, 2004, there was a material weakness in our processes, procedures and controls related to the preparation of our quarterly and annual tax provisions. In connection with the preparation of our quarterly report on Form 10-Q for the third quarter ended September 30, 2005, we reconsidered our position with respect to technical correction notices from the IRS related to the tax provision made on an extraordinary dividend received from our former wholly-owned Canadian subsidiary. Accordingly, we restated our financial statements for the quarter ended June 30, 2005 and September 30, 2005, to reflect the tax benefit in the June 30, 2005 quarter and to classify the benefit as a component of continuing rather than discontinued operations in the September 30, 2005 quarter. We also reclassified a Canadian tax benefit resulting from a tax rate change in the three and six month periods ended June 30, 2004 and the nine months ended September 30, 2004 from discontinued to continuing operations. We do not believe these restatements resulted from a new material weakness in our internal controls; however, we continue to evaluate the effectiveness of our processes, procedures and controls, with continued emphasis on accounting for income taxes. In 2005, through the date of this report, we have implemented additional controls including more stringent reviews of the quarterly tax provision, hired additional finance and accounting personnel, and expanded the scope of work of the outside consulting firm that we use to review our quarterly tax provision. In connection with our documentation and testing procedures to be performed to comply with Section 404 of the Sarbanes-Oxley Act of 2002, accounting for federal and state income taxes will be an area of significant emphasis.

While we believe that we are taking the steps necessary to remediate this material weakness in our processes, procedures and controls related to the preparation of our quarterly and annual tax provisions, we are still in the process of evaluating these controls. Accordingly, we will continue to monitor vigorously the effectiveness of these processes, procedures and controls and will make any further changes management determines appropriate.

Changes in Internal Controls

There were no changes to our internal controls over financial reporting during our last fiscal quarter that have materially affected or are reasonably likely to materially affect, our internal controls over financial reporting, except as described above.

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 for 2004 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 J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.

4.9		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 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 filed November 24, 2004 and incorporated by reference herein.***

10.28		Amendment Number One to EXCO Resources, Inc. Amended and Restated Severance Plan effective as of September 30, 2005, filed herewith.***

10.29		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.***

10.30		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.***

10.31		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.

10.32		Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO’s Form 8-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.33		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 filed January 21, 2005 and incorporated by reference herein.

10.34		Securities Account Control Agreement, dated as of February 8, 2005, among 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 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 filed February 16, 2005 and incorporated by reference herein.

10.36		Indenture among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to Amendment No. 4 to the Schedule TO filed February 16, 2005 and incorporated by reference herein.

10.37		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004.*

10.38		First Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*

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

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

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

10.42		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.**

10.43		EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.44		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term

		Incentive Plan filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.45		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.46		Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.47		Fourth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated September 30, 2005, as filed as an Exhibit to EXCO’s Form 8-K dated September��30, 2005 and incorporated by reference herein.

10.48		Letter Agreement, dated October 3, 2005, between EXCO Resources, Inc. and JPMorgan Chase Bank, N.A., as agent for certain lenders under the Credit Agreement by and among EXCO Holdings II, Inc. (EXCO Holdings Inc. as successor by merger) as Borrower and JPMorgan Chase Bank, N.A. as Administrative Agent for itself and the Lenders defined therein, dated October 3, 2005, filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.

10.49		Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.

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

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

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

99.1		Audit Committee Charter, filed as an Exhibit to EXCO’s Form 8-K dated November 18, 2004 filed November 24, 2004 and incorporated by reference herein.

* Filed as an Exhibit to EXCO’s Form S-4 filed March 25, 2004 and incorporated by reference herein.

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

*** These exhibits are management contracts.

SIGNATURES

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

	EXCO RESOURCES, INC. (Registrant)

Date: November 23, 2005	By:	/s/ DOUGLAS H. MILLER
		Douglas H. Miller
		Chairman and Chief Executive Officer

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

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 for 2004 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 J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Form 8-K/A Amendment No. 1 dated February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.

4.9		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 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 filed November 24, 2004 and incorporated by reference herein.***

10.28		Amendment Number One to EXCO Resources, Inc. Amended and Restated Severance Plan effective as of September 30, 2005, filed herewith.***

10.29		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.***

10.30		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.***

10.31		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.

10.32		Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO’s Form 8-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.33		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 filed January 21, 2005 and incorporated by reference herein.

10.34		Securities Account Control Agreement, dated as of February 8, 2005, among 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 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 filed February 16, 2005 and incorporated by reference herein.

10.36		Indenture among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to Amendment No. 4 to the Schedule TO filed February 16, 2005 and incorporated by reference herein.

10.37		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004.*

10.38		First Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*

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

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

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

10.42		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.**

10.43		EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.44		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.45		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.46		Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive

		Plan filed as an Exhibit to EXCO’s Form 8-K dated October 7, 2005 and incorporated by reference herein.***

10.47		Fourth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated September 30, 2005, as filed as an Exhibit to EXCO’s Form 8-K dated September 30, 2005 and incorporated by reference herein.

10.48		Letter Agreement, dated October 3, 2005, between EXCO Resources, Inc. and JPMorgan Chase Bank, N.A., as agent for certain lenders under the Credit Agreement by and among EXCO Holdings II, Inc. (EXCO Holdings Inc. as successor by merger) as Borrower and JPMorgan Chase Bank, N.A. as Administrative Agent for itself and the Lenders defined therein, dated October 3, 2005, filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.

10.49		Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.

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

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

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

99.1		Audit Committee Charter, filed as an Exhibit to EXCO’s Form 8-K dated November 18, 2004 filed November 24, 2004 and incorporated by reference herein.

* Filed as an Exhibit to EXCO’s Form S-4 filed March 25, 2004 and incorporated by reference herein.

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

*** These exhibits are management contracts.

Exco Resources (EXCO) Inactive 10-Q/A2005 Q3 Quarterly report (amended)