EXCO RESOURCES INC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2004

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

The number of shares of common stock, par value $0.01 per share, outstanding at July 31, 2004 was 1,000.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION (1)
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets at December 31, 2003 and June 30, 2004
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2003 and 2004
	Condensed Consolidated Statements of Cash Flow for the Three and Six Months Ended June 30, 2003 and 2004
	Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2003 and 2004
	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 and Reports on Form 8-K
Signatures
Index to Exhibits

(1) Financial information for the periods prior to July 29, 2003, the date of the going private transaction, represents predecessor basis financial statements. See Note 1 to the condensed consolidated financial statements.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

	December 31, 2003			June 30, 2004
				(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	7,333		$	42,822
Accounts receivable:
Oil and natural gas sales	13,514			25,438
Joint interest	3,857			2,764
Interest and other	1,895			1,782
Oil and natural gas derivatives	705			41
Marketable securities	818			538
Other	3,447			4,212
Total current assets	31,569			77,597
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	9,195			13,065
Proved developed and undeveloped oil and natural gas properties	416,679			654,116
Accumulated depreciation, depletion and amortization	(11,931		)	(33,916		)
Oil and natural gas properties, net	413,943			633,265
Gas gathering assets, net	—			17,817
Office and field equipment, net	1,101			5,316
Deferred financing costs, net	1,565			11,779
Oil and natural gas derivatives	204			26
Advances to affiliates	46			—
Goodwill	53,346			50,484
Other assets	3,256			381
Total assets	$	505,030		$	796,665

See accompanying notes

	December 31, 2003			June 30, 2004
				(Unaudited)
Liabilities and Stockholder’s Equity
Current liabilities:
Accounts payable and accrued liabilities	$	25,308		$	43,665
Revenues and royalties payable	3,350			7,395
Income taxes payable	3,726			6,278
Current portion of asset retirement obligations	—			1,325
Oil, natural gas and interest rate derivatives	12,804			31,280
Total current liabilities	45,188			89,943
Long-term debt	207,951			2
7 ¼% Senior notes due 2011	—			453,152
Asset retirement obligations and other long-term liabilities	18,343			24,309
Deferred income taxes	45,899			35,498
Oil and natural gas derivatives	3,780			18,957
Commitments and contingencies	—			—
Stockholder’s equity:
Common stock, $.01 par value:
Authorized shares—100,000
Issued and outstanding shares—1,000 at December 31, 2003 and June 30, 2004	1			1
Capital contributed by EXCO Holdings Inc.	172,045			172,045
Retained earnings (deficit)	4,177			(2,133		)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustments	7,680			4,927
Unrealized gain (loss) on equity investments	(34		)	(36		)
Total stockholder’s equity	183,869			174,804
Total liabilities and stockholder’s equity	$	505,030		$	796,665

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited, in thousands, except per share amounts)

	Three Months Ended June 30,					Six Months Ended June 30,
	2003		2004			2003			2004
	(Predecessor)		(Successor)			(Predecessor)			(Successor)

Revenues:
Oil and natural gas	$	25,666	$	59,493		$	52,676		$	107,227
Commodity price risk management activities	—		(17,603		)	—			(44,481		)
Other income (loss)	296		1,069			(1,401		)	1,714
Total revenues	25,962		42,959			51,275			64,460
Costs and expenses:
Oil and natural gas production	8,886		11,907			17,406			22,698
Depreciation, depletion and amortization	5,067		12,335			10,146			23,091
Accretion of discount on asset retirement obligations	330		420			625			836
General and administrative	4,096		5,773			7,644			10,538
Interest	1,287		9,253			2,395			18,045
Total costs and expenses	19,666		39,688			38,216			75,208
Income (loss) before income taxes	6,296		3,271			13,059			(10,748		)
Income tax expense (benefit)	2,578		515			5,247			(4,438		)
Income (loss) before cumulative effect of change in accounting principle	3,718		2,756			7,812			(6,310		)
Cumulative effect of change in accounting principle, net of income taxes	—		—			255			—
Net income (loss)		3,718	$	2,756			8,067		$	(6,310	)
Dividends on preferred stock	1,311					2,622
Earnings on common stock	$	2,407				$	5,445

Basic earnings per share:
Income before cumulative effect of change in accounting principle	$	0.34				$	0.73
Cumulative effect of change in accounting principle, net of income taxes	—					0.04
Earnings on common stock	$	0.34				$	0.77

Diluted earnings per share:
Income before cumulative effect of change in accounting principle	$	0.29				$	0.62
Cumulative effect of change in accounting principle, net of income taxes	—					0.02
Earnings on common stock	$	0.29				$	0.64

Weighted average number of common and common equivalent shares outstanding:
Basic	7,087					7,055

Diluted	12,564					12,555

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW

(Unaudited, in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2004			2003			2004
	(Predecessor)			(Successor)			(Predecessor)			(Successor)

Operating Activities:
Net income (loss)	$	3,718		$	2,756		$	8,067		$	(6,310	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	5,067			12,335			10,146			23,091
Accretion of discount on asset retirement obligations	330			420			625			836
Non-cash changes in fair value of derivatives	—			9,060			—			31,923
Cumulative effect of change in accounting principle, net of income taxes	—			—			(255		)	—
Deferred income taxes	975			(1,997		)	1,354			(9,251		)
Amortization of deferred financing costs	—			817			—			2,956
Proceeds from sale of Enron claim	—			4,750			—			4,750
(Income) expense from derivative ineffectiveness and terminated hedges, net	(1,234		)	—			162			—
Other operating activities	55			—			205			1
Effect of changes in:
Accounts receivable	7,580			(4,439		)	2,521			(396		)
Other current assets	(733		)	(1,036		)	(885		)	32
Accounts payable and other current liabilities	116			11,949			2,499			16,049
Net cash provided by operating activities	15,874			34,615			24,439			63,681
Investing Activities:
Acquisition of North Coast Energy, Inc., less cash acquired	—			(78		)	—			(215,133		)
Additions to oil and natural gas properties, gathering systems and equipment	(13,218		)	(34,624		)	(27,592		)	(62,172		)
Proceeds from dispositions of property and equipment	1,380			6,966			4,430			13,812
Other investing activities	(72		)	(100		)	(104		)	666
Net cash used in investing activities	(11,910		)	(27,836		)	(23,266		)	(262,827		)
Financing Activities:
Proceeds from long-term debt	9,389			103,250			25,466			460,351
Payments on long-term debt	(11,888		)	(91,094		)	(22,599		)	(209,563		)
Preferred stock dividends	(1,311		)	—			(2,622		)	—
Deferred financing costs	(35		)	(1,963		)	(1,007		)	(13,182		)
Other financing activities	45			73			43			60
Net cash provided (used) by financing activities	(3,800		)	10,266			(719		)	237,666
Net increase in cash	164			17,045			454			38,520
Effect of exchange rates on cash and cash equivalents	107			(2,870		)	113			(3,031		)
Cash at beginning of period	2,238			28,647			1,942			7,333
Cash at end of period	$	2,509		$	42,822		$	2,509		$	42,822

Supplemental Cash Flow Information:
Interest paid	$	1,292		$	355		$	2,206		$	2,214

Income taxes paid	$	—		$	1,907		$	—		$	2,693

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited, in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2003			2004			2003			2004
	(Predecessor)			(Successor)			(Predecessor)			(Successor)

Net income (loss)	$	3,718		$	2,756		$	8,067		$	(6,310	)
Other comprehensive income:
Hedging activities:
Effective changes in fair value	705			—			828			—
Reclassification adjustments for settled contracts	(3,917		)	—			(6,450		)	—
Amortization of terminated contracts	(631		)	—			(1,606		)	—
Total hedging activities	(3,843		)	—			(7,228		)	—
Foreign currency translation adjustment	2,756			(1,730		)	4,675			(2,753		)
Unrealized gain (loss) on equity investments	88			(30		)	136			(2		)
Total comprehensive income (loss)	$	2,719		$	996		$	5,650		$	(9,065	)

See accompanying notes.

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2004

(Unaudited)

1. The Merger

On July 29, 2003, pursuant to an Agreement and Plan of Merger, ER Acquisition, Inc., a Texas corporation, and a wholly-owned subsidiary of EXCO Holdings Inc., a Delaware corporation, was merged into EXCO Resources, Inc. (EXCO, the Company, or Resources). EXCO Holdings Inc. (Holdings or our parent) was formed by our chairman and chief executive officer, Douglas H. Miller, and his buying group for the purpose of entering into the merger agreement. The holders of EXCO’s common stock, other than Holdings and its subsidiaries, received cash of $18.00 per share. The buyout was funded with borrowings from EXCO’s existing credit facilities of approximately $53.6 million and approximately $172.0 million of equity. The equity capital for Holdings was provided by:

• Cerberus Capital Management, L.P., or Cerberus, an investment management firm— $106.5 million in cash;

• Other institutional investors—$34.3 million in cash;

• Certain members of EXCO’s management—$10.5 million in cash and the contribution of EXCO shares; and

• Other institutional and other investors—$20.7 million in cash and the contribution of EXCO shares.

Upon completion of the merger transaction, EXCO’s common stock was delisted from trading on the NASDAQ National Market or any other exchange and EXCO’s common stock registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934 was terminated. Accordingly, earnings per share data is not shown for any of the periods subsequent to July 28, 2003.

The total purchase price for EXCO was $353.5 million representing the purchase of all outstanding common stock and stock options including the amounts contributed to Holdings by management and key employees and other investors, and liabilities assumed as detailed below and has been allocated as follows (dollars in thousands):

Purchase Price Calculations:
Payments for tendered shares including options	$	195,327
Value of EXCO shares contributed by management	8,429
Value of EXCO shares contributed by other investors	17,966
Assumption of debt	130,003
Merger related costs	1,819
Total EXCO acquisition costs	$	353,544
Allocation of purchase price:
Oil and natural gas properties—proved	$	358,111
Oil and natural gas properties—unproved	9,967
Goodwill	51,120
Other property and equipment and other assets	3,678
Current assets	36,705
Deferred income taxes (1)	(50,733		)
Accounts payable and accrued expenses	(37,757		)
Asset retirement obligations	(15,744		)
Fair value of oil and natural gas derivatives	(1,803		)
Total allocation	$	353,544

(1) Represents deferred income taxes recorded at the date of the merger due to differences between the book basis and the tax basis of assets. For book purposes, we had a step-up in basis related to purchase accounting while our existing tax basis carried over.

As a result of the change in control, generally accepted accounting principles (GAAP) requires the acquisition by Holdings to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations”. GAAP requires the application of “push down accounting” in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the acquired entity (i.e. EXCO) reflect the new basis of accounting in accordance with Staff Accounting Bulletin No. 54 (“SAB 54”). Accordingly, the financial statements as of December 31, 2003 and for the 156 day period then ended reflect Holdings’ stepped up basis resulting from the acquisition that has been pushed down to us. The aggregate purchase price has been allocated to the underlying assets and liabilities based upon the respective estimated fair values at July 29, 2003 (date of acquisition). Carryover basis accounting applies for tax purposes. All financial information presented prior to July 29, 2003 represents predecessor basis of accounting.

The purchase price allocation resulted in $51.1 million of goodwill, $24.2 million in the United States geographic operating segment and $26.9 million in the Canadian geographic operating segment. None of the goodwill is 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 annually 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. Changes in the balance of goodwill from the date of acquisition to December 31, 2003 are the result of foreign currency translation adjustments for associated Canadian goodwill.

See “Note 9. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc.” for pro forma condensed consolidated statements of operations.

2. Basis of Presentation

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

The accompanying condensed consolidated balance sheets as of December 31, 2003 and June 30, 2004 and the results of operations, cash flows and comprehensive income for the three and six months ended June 30, 2004 are for EXCO and its subsidiaries and represent the stepped-up successor basis of accounting (New EXCO).

The accompanying condensed consolidated results of operations, cash flow and comprehensive income for the three and six months ended June 30, 2003 are for EXCO and its subsidiaries and represent the predecessor basis of accounting (Old EXCO). All inter-company transactions have been eliminated.

In management’s opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting solely of normal recurring accruals) necessary to present fairly the financial position of EXCO Resources, Inc. as of December 31, 2003 and June 30, 2004, and the results of operations, cash flow and other comprehensive income for the three and six month periods ended June 30, 2003 and 2004.

We have prepared the accompanying unaudited financial statements pursuant to the rules and regulations of the Securities and Exchange Commission. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. You should read these unaudited interim financial statements in conjunction with our audited financial statements and notes included in the Prospectus for our senior notes exchange offer dated April 22, 2004.

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

Certain prior year amounts have been reclassified to conform to the current year presentation.

Stock Options

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

Old EXCO elected to continue to utilize the accounting method prescribed by APB 25, under which no compensation cost

was recognized, and adopt the disclosure requirements of SFAS 123. As a result, SFAS 123 had no effect on our results of operations at March 31, 2003. Stock based compensation expense reflected in the table below for the three and six months ended June 30, 2003, was a result of options issued under Old EXCO’s 1998 Stock Option Plan that were issued subject to our shareholders’ approval and options that were issued to employees of Addison.

Had compensation costs for these plans been determined consistent with SFAS 123, Old EXCO’s net income and earnings per share (EPS) would have been adjusted to the following pro forma amounts:

		Three Months Ended June 30, 2003		Six Months Ended June 30, 2003
		(In thousands, except per share amounts)

Stock based compensation expense (net of taxes)	As Reported	$	285	$	553
	Pro Forma	$	686	$	1,355
Net income	As Reported	$	3,718	$	8,067
	Pro Forma	$	3,317	$	7,265
Basic EPS	As Reported	$	0.34	$	0.77
	Pro Forma	$	0.28	$	0.66
Diluted EPS	As Reported	$	0.29	$	0.64
	Pro Forma	$	0.26	$	0.58

Certain of our employees have been granted Holdings stock options under Holdings’ 2004 Long-Term Incentive Plan (the Holdings Plan). The Holdings Plan provides for grants of stock options that can be exercised for Class A common shares of Holdings. The stock options vest upon the earlier of specified events or three years from the date of grant and expire ten years after the date of grant. Holdings has reserved 12,962,968 shares of its Class A common stock for issuance upon the exercise of stock options. As of June 30, 2004 options for 8,801,354 shares of common stock have been granted by Holdings.

Effective with the grant of these options on June 3, 2004, we have elected to continue to utilize the accounting method prescribed by APB 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 123, no compensation expense was incurred during the three months or six months ended June 30, 2004 from the granting of these stock options and as such no proforma disclosure is required. In addition, we anticipate no additional compensation expense during the remainder of 2004 from the grant of these options and no proforma disclosures of earnings is required.

3. Asset Retirement Obligations

Prior to 2003, Old EXCO provided for future site restoration costs on its Canadian oil and natural gas properties based upon management’s estimates. The costs were being recognized over the remaining life of proved reserves by a charge to depreciation, depletion and amortization in the statement of operations with a related increase in the non-current deferred abandonment liability. Actual expenditures for site restoration were charged to the deferred abandonment liability when incurred. Old EXCO did not provide for site restoration on its U.S. properties as it estimated that salvage values would exceed the asset retirement costs.

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Old EXCO adopted the new rules on asset retirement obligations on January 1, 2003, for its U.S. and Canadian operations. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.4 million, recognition of an asset retirement obligation liability of approximately $10.4 million, an increase in deferred income tax liability of approximately $690,000, and a cumulative effect of adoption that increased net income and stockholder’s equity by approximately $255,000. The increase in net income resulting from the cumulative effect of the change in accounting increased basic earnings per share by $.04 and diluted earnings per share by $.02 for the six months ended June 30, 2003.

The following pro forma data summarizes Old EXCO’s net income and earnings per share as if it had adopted the provisions of SFAS 143 on January 1, 2003, including an associated pro forma asset retirement obligation on that date of $7.1 million:

	Six Months Ended June 30, 2003
	(In thousands, expect per share amounts)

Net income, as reported	$	8,067
Pro forma adjustments to reflect retroactive adoption of SFAS 143	(255		)
Pro forma net income	$	7,812

Earnings on common stock per share:
Basic-as reported	$	0.77

Basic-pro forma	$	0.73

Diluted-as reported	$	0.64

Diluted-pro forma	$	0.62

The following is a reconciliation of our asset retirement obligations as of June 30, 2003 and 2004 (in thousands of dollars):

	June 30,
	2003			2004

Deferred abandonment costs at beginning of year	$	2,176		$	17,742
Cumulative effect of change in accounting principle	10,433			—
Liabilities incurred or assumed during period	239			8,545
Liabilities settled during period	(541		)	(1,855		)
Accretion of discount	625			836
Effect of foreign currency conversions	1,116			(309		)
Asset retirement obligation at end of period	14,048			24,959
Less current portion	—			1,325
Long-term obligation	$	14,048		$	23,634

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

4. Earnings Per Share

SFAS No. 128, “Earnings per Share”, required Old EXCO to present two calculations of earnings per common share for the three and six month periods ended June 30, 2003. Basic earnings per common share equals net income less preferred stock dividends divided by weighted average common shares outstanding during the period. Diluted earnings per common share equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents. Common stock equivalents are shares assumed to be issued if (1) outstanding stock options or warrants were in-the-money and exercised, and (2) the outstanding 5% convertible preferred stock was converted to common stock.

Earnings per share subsequent to July 28, 2003 (after the going private transaction) are not presented since New EXCO is wholly-owned by Holdings, our parent.

	Three Months Ended June 30, 2003	Six Months Ended June 30, 2003
	(In thousands)	(In thousands)

Weighted average number of basic shares outstanding	7,087	7,055
Effects of:
Employee and director stock options	543	534
Convertible preferred stock	4,934	4,966
Weighted average number of diluted shares outstanding	12,564	12,555

5. 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.

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, 2003 and June 30, 2004, we had $9.2 million and $13.1 million, respectively, in unproved oil and natural gas properties. We assess our unproved oil and natural gas properties on a quarterly basis. During the six months ended June 30, 2004, we reclassified $3.6 million from unproved oil and natural gas properties to proved oil and natural gas properties.

Depreciation, depletion and amortization of evaluated oil and natural gas properties is provided using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers.

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

At the end of each quarterly period, the unamortized cost of 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. This ceiling test calculation is done separately for the United States and 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 and in projecting the future rates of production and plan of development. 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 to the estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

6. Geographic Operating 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. We have reportable operations in the United States and Canada. The following tables provide our interim geographic operating segment data. Geographic operating segment income tax expenses have been determined based on expected effective tax rates for the various tax jurisdictions where we have oil and natural gas producing activities.

	United States			Canada			Corporate and Other			Total
	(In thousands)

Three months ended June 30, 2003:
Oil and natural gas sales	$	10,357		$	15,309		$	—		$	25,666
Other income (loss)	631			—			(335		)	296
	10,988			15,309			(335		)	25,962

Production costs	5,010			3,876			—			8,886
Depreciation, depletion and amortization	2,341			2,726			—			5,067
Accretion expense	137			193			—			330
General and administrative	—			—			4,096			4,096
Interest	—			—			1,287			1,287
	7,488			6,795			5,383			19,666

Income (loss) before income taxes	3,500			8,514			(5,718		)	6,296
Income tax expense (benefit)	1,190			3,797			(2,409		)	2,578
Net income (loss)	$	2,310		$	4,717		$	(3,309	)	$	3,718

Total assets	$	129,873		$	157,199		$	—		$	287,072

Three months ended June 30, 2004:
Oil and natural gas sales	$	36,205		$	23,288		$	—		$	59,493
Commodity price risk management activities	(15,716		)	(1,887		)	—			(17,603		)
Other income	—			—			1,069			1,069
	20,489			21,401			1,069			42,959

Production costs	7,110			4,797			—			11,907
Depreciation, depletion and amortization	7,135			5,200			—			12,335
Accretion expense	210			210			—			420
General and administrative	—			—			5,773			5,773
Interest	—			—			9,253			9,253
	14,455			10,207			15,026			39,688

Income (loss) before income taxes	6,034			11,194			(13,957		)	3,271
Income tax expense (benefit)	2,052			4,435			(5,972		)	515
Net income (loss)	$	3,982		$	6,759		$	(7,985	)	$	2,756

Total assets	$	490,998		$	305,667		$	—		$	796,665
Goodwill	$	22,139		$	28,345		$	—		$	50,484

	United States			Canada			Corporate and Other			Total
	(In thousands)

Six months ended June 30, 2003:
Oil and natural gas sales	$	19,430		$	33,246		$	—		$	52,676
Other income (loss)	1,606			—			(3,007		)	(1,401		)
	21,036			33,246			(3,007		)	51,275

Production costs	9,918			7,488			—			17,406
Depreciation, depletion and amortization	4,716			5,430			—			10,146
Accretion expense	275			350			—			625
General and administrative	—			—			7,644			7,644
Interest	—			—			2,395			2,395
	14,909			13,268			10,039			38,216

Income (loss) before income taxes	6,127			19,978			(13,046		)	13,059
Income tax expense (benefit)	2,083			8,243			(5,079		)	5,247
Net income (loss)	$	4,044		$	11,735		$	(7,967	)	$	7,812

Total assets	$	129,873		$	157,199		$	—		$	287,072

Six months ended June 30, 2004:
Oil and natural gas sales	$	64,872		$	42,355		$	—		$	107,227
Commodity price risk management activities	(39,276		)	(5,205		)	—			(44,481		)
Other income	—			—			1,714			1,714
	25,596			37,150			1,714			64,460

Production costs	13,513			9,185			—			22,698
Depreciation, depletion and amortization	13,188			9,903			—			23,091
Accretion expense	410			426			—			836
General and administrative	—			—			10,538			10,538
Interest	—			—			18,045			18,045
	27,111			19,514			28,583			75,208

Income (loss) before income taxes	(1,515		)	17,636			(26,869		)	(10,748		)
Income tax expense (benefit)	(515		)	6,987			(10,910		)	(4,438		)
Net income (loss)	$	(1,000	)	$	10,649		$	(15,959	)	$	(6,310	)

Total assets	$	490,998		$	305,667		$	—		$	796,665
Goodwill	$	22,139		$	28,345		$	—		$	50,484

7. 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. The ineffective portion of any change in the fair value of a derivative designated as a hedge was immediately recognized in earnings in our predecessor basis financial statements. Prior to July 29, 2003, all of Old EXCO’s derivative financial instruments were designated as cash flow hedges. Beginning July 29, 2003, the date of the merger, we have not designated our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value currently in earnings.

Old EXCO entered into several swap transactions during 2000 and 2001 with Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern Division of New York. We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001. We believed that we were owed approximately $15.3 million, including settlements already due but not paid, but the exact amount of the claim was to be determined pursuant to the terms of the ISDA Master Agreement. At the date of the going private transaction, July 29, 2003, we preliminarily valued the Enron derivative asset at $2.8 million, which represented our conservative estimate of the fair market value of our bankruptcy claim against Enron North America, which was shown in the accompanying consolidated balance sheet in other assets. Our estimate of the value of our bankruptcy claim was based upon the low range of informal offers that we received from third parties attempting to purchase those claims as well as management’s best estimate of the financial condition of Enron’s bankruptcy estate as determined from published reports and court filings related to the bankruptcy. Our claim was sold to a third party in April 2004 for approximately $4.7 million. The difference between the $4.7 million received for

the claim and the $2.8 million derivative asset was treated as a purchase price adjustment for the going private transaction. As a result, we have reduced goodwill by $1.2 million and increased deferred income taxes payable by $700,000.

The following table sets forth our oil and natural gas derivatives as of June 30, 2004. The fair values at June 30, 2004 are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at June 30, 2004. We have the right to offset amounts we expect to receive or pay among our individual counterparties. As a result, we have offset amounts for financial statement presentation purposes.

	Volume mmbtu/ bbls	Weighted Average Strike Price		Weighted Average Differential to NYMEX			Fair Value at June 30, 2004
	(In thousands, except prices and differentials)
Natural Gas:

Swaps:
2004	6,456	$	4.60				$	(11,157	)
2005	15,622	4.93					(18,293		)
2006	10,403	4.82					(7,568		)
2007	6,387	4.60					(2,811		)
2008	2,745	4.55					(482		)
2009	1,825	4.51					(102		)
2010	1,825	4.51					64
2011	1,825	4.51					203
2012	1,830	4.51					287
2013	1,825	4.51					325
	50,743

Floor Prices:
2004	5,339	4.04					40
2005	1,058	4.25					84
	6,397

Ceiling Prices:
2004	3,720	6.01					(2,927		)
	3,720

Basis Protection Swaps:
2004	884			$	(.83	)	70
	884

Total Natural Gas							(42,267		)

Oil:
Swaps:
2004	368	24.05					(4,666		)
2005	329	25.65					(2,980		)
	697

Total Oil							(7,646		)
Total Oil and Natural Gas							$	(49,913	)

At June 30, 2004, the average forward NYMEX oil prices per Bbl for the remainder of calendar 2004 and 2005 were $36.80 and $34.96, respectively and the average forward NYMEX natural gas price per Mmbtu for the remainder of calendar 2004 and 2005 were $6.33 and $6.13, respectively.

8. Credit Agreements

U.S. Credit Agreement. On January 27, 2004, our U.S. credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the U.S. credit agreement maturity date to January 27, 2007. Upon the issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004, the U.S. credit agreement borrowing base was reduced to $95.0 million. (See “Note 9. Issuance of Senior Unsecured Notes

and the Acquisition of North Coast Energy, Inc.”). Effective June 28, 2004, the borrowing base was redetermined at $145.0 million, and will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At June 30, 2004, we had $1,000 of outstanding indebtedness and letter of credit commitments of $275,000 and approximately $144.7 million available for borrowing. Borrowings under our amended and restated credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. 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 .50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At June 30, 2004, the six month LIBOR rate was 1.94%, which would result in an interest rate of approximately 3.19% on any new indebtedness we may incur under the U.S. credit agreement.

Canadian Credit Agreement. On January 27, 2004, our Canadian credit agreement was amended and restated to provide for borrowings up to $189.4 million with a borrowing base of approximately $105.0 million (CDN $138.6 million using the exchange rate on January 26, 2004). The amendment also provided for an extension of the Canadian credit agreement maturity date to January 27, 2007. The issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004 did not impact the borrowing base under the Canadian credit agreement. (See “Note 9. Issuance of Senior Unsecured Notes and the Acquisition of North Coast Energy, Inc.”). Effective June 28, 2004, the borrowing base was redetermined at $105.0 million (CDN $141.7 million using the exchange rate on June 25, 2004), and will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At June 30, 2004, we had approximately $1,000 of outstanding indebtedness and approximately $105.0 million available for borrowing. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be (i) the Canadian prime rate plus an applicable margin or (ii) the Banker’s Acceptance rate plus an applicable margin. At June 30, 2004, the six month Banker’s Acceptance rate was 2.29%, which would result in an interest rate of approximately 3.54% on any new indebtedness we incur under the Canadian credit agreement.

Financial Covenants and Ratios. Our amended and restated U. S. and Canadian credit agreements contain 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 credit agreements) 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 credit agreements) 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 credit agreements) 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 credit agreements) to be less than 2.5 to 1.0 at the end of each fiscal quarter.

Additionally, the credit agreements contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and prohibit the payment of dividends on our common stock.

As of June 30, 2004, we were in compliance with the covenants contained in our U.S. and Canadian credit agreements.

Dividend Restrictions.

We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common

stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock. Even if our credit agreements 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.

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

On November 26, 2003, we entered into the North Coast Acquisition Agreement, as amended and restated on December 4, 2003, to acquire all of the issued and outstanding stock of North Coast pursuant to a tender offer and merger. We acquired all of the outstanding common stock, options and warrants of North Coast on January 27, 2004 for a purchase price of $167.8 million and we assumed $57.0 million of North Coast’s outstanding indebtedness. As a result, on January 27, 2004, North Coast became a wholly-owned subsidiary and established a new core operating area for us in the Appalachian Basin. We have accounted for the North Coast acquisition using the purchase method of accounting and have consolidated its operations effective January 27, 2004.

On January 20, 2004, we completed the private placement of $350.0 million aggregate principal amount of 7 ¼% senior notes due 2011 pursuant to Rule 144A and Regulation S under the Securities Act at a price of 100% of the principal amount. The net proceeds of the offering were used to acquire North Coast, pay down debt under our credit facilities and North Coast’s credit facility, repay our senior term loan in full and pay fees and expenses associated with those transactions.

On April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of 7 ¼% senior notes due 2011 pursuant to Rule 144A, having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued on April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. The net proceeds of the April 13, 2004 offering were used to repay substantially all of our outstanding indebtness 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 7 ¼% senior notes due 2011, which were privately placed in January and April 2004, for $450.0 million aggregate principal amount of our 7 ¼% senior notes due 2011 that have been registered under the Securities Act of 1933. 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, commencing July 15, 2004. The senior notes mature on January 15, 2011. Prior to January 15, 2007, we may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the notes. If a change of control occurs, subject to certain conditions, we must offer holders of the notes an opportunity to sell us their notes at a purchase price of 101% of the principal amount of the notes, plus accrued and unpaid interest to the date of the purchase.

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

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

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

• Make investments;

• Create liens on our assets;

• Enter into sale/leaseback transactions;

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

• Engage in transactions with our affiliates;

• Transfer or issue shares of stock of subsidiaries;

• Transfer or sell assets; and

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

The estimated fair value of our 7 ¼% senior notes due 2011 was $455.6 million as compared to the carrying amount of $453.2 million (including $3.2 million of unamortized premium) at June 30, 2004. The fair value of the senior notes is estimated based on quoted market prices for the senior notes.

Concurrent with the issuance of the senior notes, we wrote-off $938,000 of costs incurred in January 2004 to secure bridge loan financing which was not utilized upon issuance of the senior notes and deferred financing costs of approximately $726,000 related to the senior term loan, which was retired with the proceeds of the senior notes.

The total purchase price for North Coast was $225.6 million representing the purchase of all outstanding common stock and liabilities assumed as detailed below and has been allocated as follows (dollars 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	632
Total North Coast acquisition costs (before cash acquired)	$	225,562

Allocation of purchase price:
Oil and natural gas properties – proved	$	192,512
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	$	225,562

The following unaudited pro forma condensed consolidated statements of operations for the six months ended June 30, 2003 and 2004 have been derived from our unaudited consolidated statement of operations for the six months ended June 30, 2003 and 2004 and North Coast’s unaudited consolidated financial statements for the six months ended June 30, 2003 and the 27 day period from January 1 to January 27, 2004. The pro forma statements of operations give effect to the following events as if each occurred on January 1 of each respective year.

• Our going private transaction, which occurred on July 29, 2003. See “Note 1. The Merger”.

• Our acquisition of North Coast for a purchase price of approximately $225.6 million. The North Coast acquisition was accounted for using the purchase method of accounting in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations.” Accordingly, EXCO’s historical financial statements reflect the allocation of the purchase price to the underlying assets and liabilities based upon their estimated fair values. For tax purposes we also received a step up in tax basis equal to the purchase price.

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

• The issuance of $350.0 million in senior notes.

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

• The payment of our related fees and expenses.

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.

	EXCO Historical		North Coast Historical				Pro Forma
	Six Months Ended June 30, 2003		Six Months Ended June 30, 2003	Adjustments for the Transactions			Six Months Ended June 30, 2003
	(In thousands)
Revenues and other income:
Oil and natural gas	$52,676		$27,741	$—			$80,417
Commodity price risk management activities	—		—	—			—
Well operating, gathering and other	—		3,253	(3,253	)	(b)	—
Other income (expense)	(1,401	)	239	255		(b)	(907	)
Total revenues and other income	51,275		31,233	(2,998	)		79,510
Costs and expenses:
Oil and natural gas production	17,406		5,234	(361	)	(b)	22,279
Well operating, gathering and other	—		2,637	(2,637	)	(b)	—
Exploration expense	—		1,261	(1,261	)	(c)	—
Depreciation, depletion and amortization	10,146		4,437	7,504		(d)	22,087
Accretion of asset retirement obligations	625		—	170		(e)	795
General and administrative	7,644		3,115	(394	)	(f)	10,365
Interest	2,395		1,411	11,689		(h)	15,495
Total costs and expenses	38,216		18,095	14,710			71,021
Income (loss) before income taxes	13,059		13,138	(17,708	)		8,439
Income tax expense (benefit)	5,247		4,621	(6,535	)	(i)	3,333
Net income (loss)	$7,812		$8,517	$(11,173	)		$5,156

	EXCO Historical			North Coast							Pro Forma
	Six			Historical							Six
	Months Ended June 30, 2004			27 Day Period Ended January 27, 2004 (a)			Adjustments for the Transactions				Months Ended June 30, 2004
	(In thousands)
Revenues and other income:
Oil and natural gas	$	107,227		$	6,540		$	—			$	113,767
Commodity price risk management activities	(44,481		)	—			—				(44,481		)
Well operating, gathering and other	—			490			(490		)	(b)	—
Other income (expense)	1,714			150			20			(b)	1,884
Total revenues and other income	64,460			7,180			(470		)		71,170
Costs and expenses:
Oil and natural gas production	22,698			878			(108		)	(b)	23,468
Well operating, gathering and other	—			362			(362		)	(b)	—
Exploration expense	—			200			(200		)	(c)	—
Depreciation, depletion and amortization	23,091			851			473			(d)	24,415
Accretion of asset retirement obligations	836			—			30			(e)	866
General and administrative	10,538			11,535			(11,021		)	(g)	11,052
Interest	18,045			186			934			(h)	19,165
Total costs and expenses	75,208			14,012			(10,254		)		78,966
Income (loss) before income taxes	(10,748		)	(6,832		)	9,784				(7,796		)
Income tax expense (benefit)	(4,438		)	(2,448		)	3,664			(i)	(3,222		)
Net income (loss)	$	(6,310	)	$	(4,384	)	$	6,120			$	(4,574	)

(a)	Represents historical information for North Coast for the 27 day period from January 1 to January 27, 2004.

(b)	Represents reclassifications to conform to EXCO’s presentation.

(c)	Represents the adjustment to capitalize exploration expense as required under the full-cost method of accounting employed by EXCO.

(d)	Represents increased depreciation, depletion and amortization primarily relating to the step up in basis of oil and natural gas properties associated with the purchase price allocation for the North Coast transaction as if it occurred at the beginning of each respective period.

(e)	Represents additional accretion charges resulting from the revaluation of fair value based upon EXCO management’s assessment of certain factors as they relate to North Coast’s asset retirement obligation.

(f)	Represents third party costs incurred by EXCO directly related to the going private transaction and additional contractual management compensation resulting from the going private transaction.

(g)	Represents transaction costs incurred by North Coast and expensed during the 27 day period from January 1 to January 27, 2004 primarily related to investment banking fees, employee bonus and severance payments and other costs incurred in connection with the acquisition of North Coast by EXCO.

(h)	Represents the additional interest expense that would have resulted had the $350.0 million of 7 ¼% senior notes due 2011 been issued on January 1, 2004 net of the reduction in interest expense relating to the repayment of outstanding debt under the bank credit agreements and the senior term loan occurred on January 1, 2004.

(i)	Represents the income tax effect of the pro forma adjustments and adjustment of North Coast’s historical rate to approximate EXCO’s U.S. tax rate.

10. Acquisitions and Dispositions

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

During the six months ended June 30, 2004, we completed eight oil and natural gas property acquisitions in Canada and three in the United States. Estimated total proved reserves net to our interest from these acquisitions included approximately 750 Mbbls of oil and NGLs and 22.2 Bcf of natural gas. The total purchase price for the acquisitions was approximately $30.7 million funded with borrowings under our Canadian credit agreement and from surplus cash.

During the six months ended June 30, 2004, we completed 14 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 1,693 Mbbls of oil and NGLs and 9.1 Bcf of natural gas. The total sales proceeds we received were approximately $13.8 million. During the first six months of 2003, we recorded revenue of approximately $3.7 million and oil and natural gas production costs of $1.6 million on these properties. During the first six months of 2004, we recorded revenue of approximately $2.7 million and oil and natural gas production costs of $1.1 million on these properties through the date of their respective disposition.

Transactions that occurred during the six months ended June 30, 2003

During the six months ended June 30, 2003, we completed six oil and natural gas property acquisitions, four in Canada and two in the United States. Estimated total proved reserves net to our interest from these acquisitions included approximately 366 Mbbls of oil and NGLs and 7.8 Bcf of natural gas. The total purchase price for the acquisitions was approximately $10.9 million funded with borrowings under our Canadian credit agreement and from surplus cash. In addition, we also completed 20 smaller acquisitions during this period for consideration that totaled approximately $1.0 million.

During the first six months of 2003, we sold 26 oil and natural gas properties in the United States. As of January 1, 2003, estimated total proved reserves net to our interest from these properties included approximately 1,069 Mbbls of oil and NGLs and 1.1 Bcf of natural gas. The total sales proceeds we received were approximately $4.4 million. During the first six months of 2003, revenues, oil and natural gas production costs and depletion expense related to these properties were not significant.

11. Consolidating Financial Statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary. The senior unsecured notes are jointly and severally guaranteed by our current and some of our future subsidiaries in the United States (referred to as Guarantor Subsidiaries). Addison is not a guarantor of the senior unsecured notes. Instead, the notes are secured, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison. This share pledge is limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock is not equal to or greater than 20% of then outstanding aggregate principal amount of the notes. The notes are also secured by a second-priority security interest in 100% of the capital stock of Taurus Acquisition, Inc.

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

• Resources;

• the guarantor subsidiaries on a combined basis;

• the non-guarantor subsidiary;

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

• the Company on a consolidated basis.

Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC are guarantors of the senior unsecured notes. These companies have no material operations and, accordingly, these companies have been omitted from the guarantor financial information. Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the guarantor and non-guarantor subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investment in subsidiaries and intercompany balances and transactions. As of January 27, 2004, North Coast Energy, Inc. and North Coast Energy Eastern, Inc. became guarantors of our senior unsecured notes.

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

December 31, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)

Assets
Current assets:
Cash and cash equivalents	$	3,372		$	—		$	3,961		$	—		$	7,333
Other current assets	10,262			—			13,974			—			24,236
Total current assets	13,634			—			17,935			—			31,569
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	2,598			—			6,597			—			9,195
Proved developed and undeveloped oil and natural gas properties	102,955			84,416			229,308			—			416,679
Allowance for depreciation, depletion and amortization	(3,091		)	(2,162		)	(6,678		)	—			(11,931		)
Oil and natural gas properties, net	102,462			82,254			229,227			—			413,943
Office and field equipment, net	811			—			290			—			1,101
Goodwill	24,218			—			29,128			—			53,346
Investments in and advances to affiliates	184,519			12,895			—			(197,368		)	46
Other assets, net	4,498			—			527			—			5,025

Total assets	$	330,142		$	95,149		$	277,107		$	(197,368	)	$	505,030

Liabilities and Stockholder’s Equity
Current liabilities	$	25,644		$	—		$	19,544		$	—		$	45,188
Long-term debt	99,470			—			108,481			—			207,951
Deferred income taxes	12,139			—			33,760			—			45,899
Other liabilities	9,021			1,527			11,575			—			22,123
Payable to parent	—			—			48,927			(48,927		)	—
Commitments and contingencies	—			—			—			—			—
Stockholder’s equity	183,868			93,622			54,820			(148,441		)	183,869
Total liabilities and stockholder’s equity	$	330,142		$	95,149		$	277,107		$	(197,368	)	$	505,030

EXCO RESOURCES, INC.

CONSOLIDATING BALANCE SHEET (Unaudited)

June 30, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)

Assets
Current assets:
Cash and cash equivalents	$	30,571		$	10,115		$	2,136		$	—		$	42,822
Other current assets	4,435			9,510			20,830			—			34,775
Total current assets	35,006			19,625			22,966			—			77,597
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	2,078			6,101			4,886			—			13,065
Proved developed and undeveloped oil and natural gas properties	102,201			286,585			265,330			—			654,116
Allowance for depreciation, depletion and amortization	(6,642		)	(10,874		)	(16,400		)	—			(33,916		)
Oil and natural gas properties, net	97,637			281,812			253,816			—			633,265
Gas gathering, office and field equipment, net	1,116			21,722			295			—			23,133
Goodwill	22,139			—			28,345						50,484
Investments in and advances to affiliates	535,340			25,018			—			(560,372		)	(14		)
Other assets, net	11,933			22			245			—			12,200
Total assets	$	703,171		$	348,199		$	305,667		$	(560,372	)	$	796,665

Liabilities and Stockholder’s Equity
Current liabilities	$	53,686		$	12,327		$	23,930		$	—		$	89,943
Long-term debt	453,153			—			1			—			453,154
Deferred income taxes	(1,293		)	4,660			32,131			—			35,498
Other liabilities	22,821			6,523			13,922			—			43,266
Payable to parent	—			47,493			173,690			(221,183		)	—
Commitments and contingencies	—			—			—			—			—
Stockholder’s equity	174,804			277,196			61,993			(339,189		)	174,804
Total liabilities and stockholder’s equity	$	703,171		$	348,199		$	305,667		$	(560,372	)	$	796,665

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Three Months Ended June 30, 2003

	Resources		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)

Revenues:
Oil and natural gas sales	$	3,433	$	6,924	$	15,309	$	—		$	25,666
Other income (loss)	117		140		39		—			296
Equity in earnings of subsidiaries	8,091		—		—		(8,091		)	—
Total revenues and other income	11,641		7,064		15,348		(8,091		)	25,962
Costs and expenses:
Oil and natural gas production	3,370		1,640		3,876		—			8,886
Depreciation, depletion and amortization	1,524		817		2,726		—			5,067
Accretion of discount on asset retirement obligations	125		12		193		—			330
General and administrative	2,624		—		1,472		—			4,096
Interest	280		—		1,007		—			1,287
Total costs and expenses	7,923		2,469		9,274		—			19,666
Income before income taxes	3,718		4,595		6,074		(8,091		)	6,296
Income tax expense	—		—		2,578		—			2,578
Net income	$	3,718	$	4,595	$	3,496	$	(8,091	)	$	3,718

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Three Months Ended June 30, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)

Revenues:
Oil and natural gas sales	$	11,246		$	24,958		$	23,289		$	—		$	59,493
Commodity price risk management activities	(15,580		)	(137		)	(1,886		)	—			(17,603		)
Other income (loss)	2,845			226			586			(2,588		)	1,069
Equity in earnings of subsidiaries	15,859			—			—			(15,859		)	—
Total revenues and other income	14,370			25,047			21,989			(18,447		)	42,959
Costs and expenses:
Oil and natural gas production	3,099			4,011			4,797			—			11,907
Depreciation, depletion and amortization	1,926			5,209			5,200			—			12,335
Accretion of discount on asset retirement obligations	96			114			210			—			420
General and administrative	3,230			1,252			1,291			—			5,773
Interest	8,896			1,150			1,795			(2,588		)	9,253
Total costs and expenses	17,247			11,736			13,293			(2,588		)	39,688
Income (loss) before income taxes	(2,877		)	13,311			8,696			(15,859		)	3,271
Income tax expense (benefit)	(5,633		)	3,794			2,354			—			515
Net income	$	2,756		$	9,517		$	6,342		$	(15,859	)	$	2,756

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Six Months Ended June 30, 2003

	Resources			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)

Revenues:
Oil and natural gas sales	$	6,500		$	12,930	$	33,246	$	—		$	52,676
Other income (loss)	(1,612		)	140		71		—			(1,401		)
Equity in earnings of subsidiaries	19,195			—		—		(19,195		)	—
Total revenues and other income	24,083			13,070		33,317		(19,195		)	51,275
Costs and expenses:
Oil and natural gas production	6,752			3,166		7,488		—			17,406
Depreciation, depletion and amortization	3,019			1,697		5,430		—			10,146
Accretion of discount on asset retirement obligations	206			69		350		—			625
General and administrative	4,898			—		2,746		—			7,644
Interest	580			—		1,815		—			2,395
Total costs and expenses	15,455			4,932		17,829		—			38,216
Income before income taxes	8,628			8,138		15,488		(19,195		)	13,059
Income tax expense	—			—		5,247		—			5,247
Income before cumulative effect of change in accounting principle	8,628			8,138		10,241		(19,195		)	7,812
Cumulative effect of change in accounting principle, net of income taxes	(561		)	—		816		—			255
Net income	$	8,067		$	8,138	$	11,057	$	(19,195	)	$	8,067

EXCO RESOURCES, INC.

CONSOLIDATING STATEMENTS OF OPERATIONS (Unaudited)

For the Six Months Ended June 30, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)

Revenues:
Oil and natural gas sales	$	21,841		$	43,030		$	42,356		$	—		$	107,227
Commodity price risk management activities	(37,155		)	(2,124		)	(5,202		)	—			(44,481		)
Other income (loss)	3,883			369			765			(3,303		)	1,714
Equity in earnings of subsidiaries	24,208			—			—			(24,208		)	—
Total revenues and other income	12,777			41,275			37,919			(27,511		)	64,460
Costs and expenses:
Oil and natural gas production	6,731			6,782			9,185			—			22,698
Depreciation, depletion and amortization	3,901			9,287			9,903			—			23,091
Accretion of discount on asset retirement obligations	199			209			428			—			836
General and administrative	5,820			1,970			2,748			—			10,538
Interest	16,445			1,925			2,978			(3,303		)	18,045
Total costs and expenses	33,096			20,173			25,242			(3,303		)	75,208
Income (loss) before income taxes	(20,319		)	21,102			12,677			(24,208		)	(10,748		)
Income tax expense (benefit)	(14,009		)	5,465			4,106			—			(4,438		)
Net income (loss)	$	(6,310	)	$	15,637		$	8,571		$	(24,208	)	$	(6,310	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Unaudited)

For the Three Month Period Ended June 30, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided (used) by operating activities	$	(6,299	)	$	5,424		$	16,749		$	—	$	15,874
Investing Activities:
Additions to oil and natural gas property and equipment	(1,714		)	382			(11,886		)	—		(13,218		)
Proceeds from dispositions of property and equipment	(190		)	1,570			—			—		1,380
Advances/investments with affiliates	7,356			(7,376		)	20			—		—
Other investing activities	—			—			(72		)	—		(72		)
Net cash provided (used) in investing activities	5,452			(5,424		)	(11,938		)	—		(11,910		)
Financing Activities:
Proceeds from long-term debt	5,750			—			3,639			—		9,389
Payments on long-term debt	(3,750		)	—			(8,138		)	—		(11,888		)
Deferred financing costs	(18		)	—			(17		)	—		(35		)
Other financing activities	(1,267		)	—			1			—		(1,266		)
Net cash provided (used) by financing activities	715			—			(4,515		)	—		(3,800		)
Net increase (decrease) in cash	(132		)				296			—		164
Effect of exchange rates on cash and cash equivalents	—			—			107			—		107
Cash at beginning of period	2,451			—			(213		)	—		2,238
Cash at end of period	$	2,319		$	—		$	190		$	—	$	2,509

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Unaudited)

For the Three Month Period Ended June 30, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by operating activities	$	13,248		$	17,990		$	3,377		$	—	$	34,615
Investing Activities:
Additions to oil and natural gas property and equipment	(4,728		)	(7,865		)	(22,031		)	—		(34,624		)
Acquisition of North Coast Energy, Inc	(78		)	—			—			—		(78		)
Proceeds from dispositions of property and equipment	3,423			3,543			—			—		6,966
Other investing activities	—			—			(100		)	—		(100		)
Net cash used in investing activities	(1,383		)	(4,322		)	(22,131		)	—		(27,836		)
Financing Activities:
Proceeds from note payable and long-term debt	103,250			—			—			—		103,250
Payments on long-term debt							(91,094		)	—		(91,094		)
Advances/investments with affiliates	(93,270		)	(16,826		)	110,169			—		73
Deferred financing costs	(2,011		)	—			48			—		(1,963		)
Net cash provided (used) by financing activities	7,969			(16,826		)	19,123			—		10,266
Net increase (decrease) in cash	19,834			(3,158		)	369			—		17,045
Effect of exchange rates on cash and cash equivalents	—			—			(2,870		)	—		(2,870		)
Cash at beginning of period	14,444			9,566			4,637			—		28,647
Cash at end of period	$	34,278		$	6,408		$	2,136		$	—	$	42,822

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Unaudited)

For the Six Month Period Ended June 30, 2003

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided (used) by operating activities	$	(7,167	)	$	9,904		$	21,702		$	—	$	24,439
Investing Activities:
Additions to oil and natural gas property and equipment	(4,283		)	(276		)	(23,033		)	—		(27,592		)
Proceeds from dispositions of property and equipment	2,860			1,570			—			—		4,430
Advances/investments with affiliates	10,672			(11,198		)	526			—		—
Other investing activities	—			—			(104		)	—		(104		)
Net cash provided (used) in investing activities	9,249			(9,904		)	(22,611		)	—		(23,266		)
Financing Activities:
Proceeds from long-term debt	13,250			—			12,216			—		25,466
Payments on long-term debt	(11,750		)	—			(10,849		)	—		(22,599		)
Deferred financing costs	(551		)	—			(456		)	—		(1,007		)
Other financing activities	(2,579		)	—			—			—		(2,579		)
Net cash provided (used) by financing activities	(1,630		)	—			911			—		(719		)
Net increase in cash	452			—			2			—		454
Effect of exchange rates on cash and cash equivalents	—			—			113			—		113
Cash at beginning of period	1,867			—			75			—		1,942
Cash at end of period	$	2,319		$	—		$	190		$	—	$	2,509

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW (Unaudited)

For the Six Month Period Ended June 30, 2004

	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Operating Activities:
Net cash provided by operating activities	$	14,622		$	32,003		$	17,056		$	—	$	63,681
Investing Activities:
Additions to oil and natural gas property and equipment	(9,498		)	(13,774		)	(38,900		)	—		(62,172		)
Acquisition of North Coast Energy, Inc	(225,562		)	10,429			—			—		(215,133		)
Proceeds from dispositions of property and equipment	10,652			3,160			—			—		13,812
Other investing activities	781			—			(115		)	—		666
Net cash used in investing activities	(223,627		)	(185		)	(39,015		)	—		(262,827		)
Financing Activities:
Proceeds from note payable and long-term debt	460,351			—			—			—		460,351
Payments on long-term debt	(106,570		)	—			(102,993		)	—		(209,563		)
Advances/investments with affiliates	(104,353		)	(21,703		)	126,116			—		60
Deferred financing costs	(13,224		)	—			42			—		(13,182		)
Net cash provided (used) by financing activities	236,204			(21,703		)	23,165			—		237,666
Net increase in cash	27,199			10,115			1,206			—		38,520
Effect of exchange rates on cash and cash equivalents	—			—			(3,031		)	—		(3,031		)
Cash at beginning of period	3,372			—			3,961			—		7,333
Cash at end of period	$	30,571		$	10,115		$	2,136		$	—	$	42,822

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

Forward-Looking Statements

The statements contained in this report regarding our future financial and operating performance and results, business strategy and market prices and future hedging activities, and other statements, including, in particular, statements about our plans and forecasts that are not historical facts are forward-looking statements, as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Among these forward-looking statements are statements regarding our anticipated performance in the year 2004, specifically statements relating to our production, production costs, depreciation, depletion and amortization expense, general and administrative expenses, interest expense, and capital expenditures. We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words “may,” “will,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget,” or 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 conditions, and/or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events, or otherwise. These statements are not guarantees of future performance and involve risks and uncertainties that could cause our actual results to differ, perhaps materially, from our expectations in this report, including, but not limited to:

• estimates of reserves;

• market factors;

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

• results of future drilling;

• marketing activity;

• future production and costs;

• outcome of litigation; and

• other factors discussed in this report and in our other SEC filings.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this Quarterly Report, and the risk factors included in the Prospectus for our senior notes exchange offer dated April 22, 2004.

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 Canada. From January 1, 2001 to June 30, 2004, we have spent in excess of $440.0 million on property and corporate acquisitions. Further, on July 29, 2003, we completed a “going private” transaction that resulted in all of our outstanding common stock being acquired by EXCO Holdings Inc., a holding company owned by certain members of our management and several institutional and other investors. This transaction resulted in a change in the valuation of our assets and liabilities. 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 $225.6 million, including the assumption of $57.0 million in outstanding bank debt. Our strategy is to continue 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 funded the acquisition of North Coast through the issuance on January 20, 2004 of $350.0 million in 7¼% senior notes due January 15, 2011. Additionally, on April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of 7¼% senior notes due January 15, 2011 having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued on 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 this offering to repay substantially all of the indebtedness outstanding under our Canadian credit agreement. We expect to continue to use debt, primarily under our bank credit agreements, to make future acquisitions. We also expect to enter into new derivative financial instruments to reduce our exposure to changes in the prices of oil and natural gas.

Critical Accounting Policies

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

We prepared our 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. Effective July 29, 2003, in connection with the going private transaction, we discontinued hedge accounting for derivative financial instruments. See “Accounting for Derivatives” for a discussion of this change. 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 the Prospectus, dated April 22, 2004, for our senior notes exchange offer was prepared in accordance with SEC guidelines. The Proved Reserve data was based upon estimates prepared by our independent petroleum engineers. 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, the decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties for impairment.

Accounting for Derivatives

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

When entering into hedging transactions, we formally documented all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. The process included linking all derivatives that were designated as cash flow hedges to forecasted transactions. We also formally assessed, both at the hedge’s inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were highly effective in offsetting changes in cash flows of hedged items. When it was determined that a derivative was not highly effective as a hedge or that it ceased to be a highly effective hedge, we discontinued hedge accounting prospectively. Under hedge accounting, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings and the ineffective portion of any change in fair value of a derivative designated as a hedge is immediately recognized in earnings.

Effective July 29, 2003, in connection with the going private transaction, we discontinued hedge accounting for all existing derivatives. Currently, we do not designate derivative transactions as hedges for accounting purposes; accordingly, changes in the fair value of derivative financial instruments, including interest rate swaps, will be recognized currently in our statement of operations.

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 have determined that the Canadian dollar is 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.

Deferred Tax Asset Valuations

We periodically assess the probability of recovering recorded deferred tax assets based on our assessment of future earnings outlook by tax jurisdiction. These estimates are inherently imprecise because we make many assumptions in the assessment process. For the three and six months ended June 30, 2003 (predecessor basis), our net deferred tax asset in the U.S. was fully reserved due to the uncertainty of the realization of such benefits. Effective with the going private transaction, as of July 29, 2003, EXCO (successor basis) is now in a deferred tax liability position in the U.S. due to the step-up in basis for book purposes related to purchase accounting and the carryover of tax basis. Accordingly, no valuation allowance relating to deferred tax assets was recognized in our purchase price allocation except for a valuation allowance of approximately $2.6 million for net operating loss carryforwards that are subject to limitations and are expected to expire before being utilized.

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 acquisitions, 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 are 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.

Goodwill

As a result of a change in control, the going private transaction has been accounted for using the purchase method of accounting pursuant to SFAS No. 141, “Accounting for Business Combinations.” As a result, EXCO Holdings’ cost of acquiring EXCO has been allocated to the assets and liabilities acquired based upon estimated fair values. Under applicable generally accepted accounting principles, the new basis of accounting for EXCO Holdings is “pushed down” to the subsidiary company, EXCO. Therefore, EXCO’s financial position and operating results subsequent to July 28, 2003 reflect a new basis of accounting and are not comparable to prior periods. In addition, tax basis carried over from the formerly public company as a result of the merger. The going private purchase price has been allocated to the assets acquired and liabilities assumed according to the estimated fair values. The purchase price allocation resulted in $51.1 million of goodwill being recorded, $24.2 million in the United States geographic operating segment and $26.9 million in the Canadian geographic operating segment. Changes in the balance of goodwill from the date of acquisition to June 30, 2004 are the result of sales of oil and natural gas properties in the United States, the sale of our Enron claim and foreign currency translation adjustments for associated Canadian goodwill. 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

annually 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

Prior to 2003, we provided for future site restoration costs on our Canadian oil and natural gas properties based upon management’s estimates. The costs were being recognized over the remaining life of Proved Reserves by a charge to depreciation, depletion and amortization in the statement of operations with a related increase in the non-current deferred abandonment liability. Actual expenditures for site restoration were charged to the deferred abandonment liability when incurred. We did not provide for site restoration costs on our U.S. properties as we estimated that salvage values would exceed the asset retirement costs.

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted the new rules on asset retirement obligations on January 1, 2003, for both our U.S. and Canadian operations. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $11.4 million, recognition of an asset retirement obligation liability of approximately $10.4 million, an increase in deferred income tax liability of approximately $690,000 and a cumulative effect of adoption that increased net income and stockholder’s equity by approximately $255,000.

Accounting for Income Taxes

Income taxes are provided based upon the liability method of accounting. Deferred taxes are recorded to reflect the tax benefit and consequences of future years differences between the tax bases 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. We generally consider the earnings of Addison, our Canadian subsidiary, to be permanently reinvested for use in those operations and, consequently, deferred federal income taxes, net of applicable foreign tax credits, are not provided on the undistributed earnings of Addison that are to be so reinvested.

Recently Issued Accounting Standards

SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Intangible Assets,” were issued in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report goodwill separately from other intangible assets. SFAS No. 142 established new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and other intangible assets are not amortized but rather are reviewed annually for impairment.

One interpretation relating to these standards is that oil and natural gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and natural gas properties, as intangible assets on the balance sheet, and the disclosures required by SFAS No. 141 and No. 142 relating to intangibles would be included in the notes to financial statements. On May 3, 2004, the FASB issued an amendment to SFAS No. 141 and No. 142 to clarify and state that oil and natural gas mineral rights held under lease and other contractual arrangements should not be treated as intangible assets. Our balance sheet presentation of these assets conforms to the FASB amendment.

Our Results of Operations

The following is a discussion of our financial condition and results of operations for the three and six month periods ended June 30, 2003 and 2004.

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

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

• 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 7 ¼% senior notes on January 20, 2004 in the amount of $350.0 million and on April 13, 2004 in the amount of $103.3 million (including applicable premium).

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

• the “going private” transaction that occurred on July 29, 2003 and the resulting step-up in basis reflecting the purchase price, and

• the discontinued use of hedge accounting for all existing derivatives, effective July 29, 2003.

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, we do not process a significant portion of the natural gas or NGLs we produce. At the Black Lake Field we operate a natural gas processing plant that is 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 short-term contracts using market sensitive pricing. Our sales contracts are of a type common within the industry, and we frequently negotiate a separate contract for each property. We sell our natural gas to transmission and utility companies that have pipelines in the vicinity of our producing properties, to companies that will construct pipelines to our properties, to third party natural gas marketing companies and directly to end users.

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 cannot assure you that we will be able to market all the oil, natural gas or NGLs we produce. If our oil, natural gas or NGLs can be marketed, we cannot assure you that we can 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

The majority of our Canadian oil is ultimately sold to Plains Marketing Canada, L.P. at market sensitive prices less applicable tariffs, trucking and quality adjustments.

At June 30, 2004, we were selling approximately 20,000 Mmbtus of our Canadian natural gas per day to a purchaser at market sensitive prices. The remainder of our Canadian natural gas is sold to various purchasers at market sensitive prices.

Our NGLs are sold primarily to two different buyers under contracts which provide for index pricing less transportation and fractionation fees.

Revenues

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 month and six month periods ended June 30, 2003 and 2004. For the three month and six month periods ended June 30, 2003, cash settlements of hedge transactions are included in oil and natural gas revenues in the condensed consolidated statement of operations. Those settlements are not reflected in the revenue amounts shown below. The table also shows the changes in these amounts between periods.

	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Year to year change
	2003		2004		2003-2004			2003		2004		2003-2004
	(In thousands)
Oil and natural gas revenues before commodity price risk management activities:

Oil revenues:
EXCO	$	5,481	$	5,339	$	(142	)	$	12,300	$	10,977	$	(1,323	)
North Coast	—		995		995			—		1,613		1,613
Total U.S.	5,481		6,334		853			12,300		12,590		290
Canada	3,013		5,756		2,743			6,652		9,319		2,667
Total	$	8,494	$	12,090	$	3,596		$	18,952	$	21,909	$	2,957

Natural gas revenues:
EXCO	$	8,842	$	10,839	$	1,997		$	18,427	$	21,120	$	2,693
North Coast	—		18,585		18,585			—		30,317		30,317
Total U.S.	8,842		29,424		20,582			18,427		51,437		33,010
Canada	10,473		13,527		3,054			22,412		25,736		3,324
Total	$	19,315	$	42,951	$	23,636		$	40,839	$	77,173	$	36,334

Natural gas liquids revenues:
EXCO	$	313	$	447	$	134		$	690	$	845	$	155
North Coast	—		—		—			—		—		—
Total U.S.	313		447		134			690		845		155
Canada	1,824		4,005		2,181			4,182		7,300		3,118
Total	$	2,137	$	4,452	$	2,315		$	4,872	$	8,145	$	3,273

Total oil and natural gas revenues:
EXCO	$	14,636	$	16,625	$	1,989		$	31,417	$	32,942	$	1,525
North Coast	—		19,580		19,580			—		31,930		31,930
Total U.S.	14,636		36,205		21,569			31,417		64,872		33,455
Canada	15,310		23,288		7,978			33,246		42,355		9,109
Total	$	29,946	$	59,493	$	29,547		$	64,663	$	107,227	$	42,564

	Three months ended June 30,		Quarter to quarter change		Six months ended June 30,		Year to year change
	2003	2004	2003-2004		2003	2004	2003-2004

Production:

Oil (Mbbls):
EXCO	199	144	(55	)	411	313	(98	)
North Coast	—	29	29		—	49	49
Total U.S.	199	173	(26	)	411	362	(49	)
Canada	113	167	54		224	282	58
Total	312	340	28		635	644	9

Natural gas (Mmcf):
EXCO	1,895	2,034	139		3,794	4,122	328
North Coast	—	2,842	2,842		—	4,851	4,851
Total U.S.	1,895	4,876	2,981		3,794	8,973	5,179
Canada	1,860	2,615	755		3,993	4,975	982
Total	3,755	7,491	3,736		7,787	13,948	6,161

Natural gas liquids (Mbbls):
EXCO	15	16	1		30	31	1
North Coast	—	—	—		—	—	—
Total U.S.	15	16	1		30	31	1
Canada	76	167	91		159	310	151
Total	91	183	92		189	341	152

Total production (Mmcfe):
EXCO	3,179	2,996	(183	)	6,438	6,187	(251	)
North Coast	—	3,016	3,016		—	5,142	5,142
Total U.S.	3,179	6,012	2,833		6,438	11,329	4,891
Canada	2,993	4,621	1,628		6,288	8,532	2,244
Total	6,172	10,633	4,461		12,726	19,861	7,135

	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Year to year change
	2003		2004		2003-2004			2003		2004		2003-2004

Average sales price (before cash settlements of derivative financial instruments):

Oil (per Bbl):
EXCO	$	27.55	$	36.97	$	9.42		$	29.94	$	35.02	$	5.08
North Coast	—		34.21		34.21			—		33.16		33.16
Total U.S.	27.55		36.61		9.06			29.94		34.78		4.84
Canada	26.60		34.39		7.79			29.67		32.99		3.32
Total		27.21		35.47		8.26			29.84		33.99		4.15

Natural gas (per Mcf):
EXCO	$	4.67	$	5.33	$	0.66		$	4.86	$	5.12	$	0.26
North Coast	—		6.54		6.54			—		6.25		6.25
Total U.S.	4.67		6.03		1.36			4.86		5.73		0.87
Canada	5.63		5.17		(0.46		)	5.61		5.17		(0.44		)
Total		5.14		5.73		0.59			5.24		5.53		0.29

Natural gas liquids (per Bbl):
EXCO	$	20.75	$	27.96	$	7.21		$	23.16	$	27.51	$	4.35
North Coast	—		—		—			—		—		—
Total U.S.	20.75		27.96		7.21			23.16		27.51		4.35
Canada	24.16		23.98		(0.18		)	26.41		23.51		(2.90		)
Total		23.59		24.32		0.73			25.90		23.87		(2.03	)

Total oil and natural gas revenues (per Mcfe):

EXCO	$	4.60	$	5.55	$	0.95		$	4.88	$	5.32	$	0.44
North Coast	—		6.49		6.49			—		6.21		6.21
Total U.S.	4.60		6.02		1.42			4.88		5.73		0.85
Canada	5.12		5.04		(0.08		)	5.29		4.96		(0.33		)
Total		4.85		5.59		0.74			5.08		5.40		0.32

Our revenues from the sale of oil, natural gas and NGLs, before cash settlements of derivative financial instruments, for the three months and six months ended June 30, 2004 increased by $29.5 million, and $42.6 million, respectively, or 99% and 66%, respectively, over the three months and six months ended June 30, 2003 primarily due to the acquisition of North Coast. Oil and natural gas revenues for North Coast for the three month period ended June 30, 2004 and for the period from January 27, 2004 to June 30, 2004 were $19.6 million and $31.9 million, respectively. The increase in revenue was also due to 23% and 16%, respective increases in oil and natural gas production volumes on an equivalent basis, excluding North Coast. This increase in production volumes is due primarily to favorable results from development drilling activity in Canada and the completion in January 2004 of our Miami Corp. 35-1 sidetrack well. For the three month and six month periods ended June 30, 2004, increases in oil, natural gas and NGL prices increased revenues by $4.9 million and $4.5 million respectively. Oil production and oil revenues for EXCO have declined due to property sales in 2003 and 2004 and a general decline in production from our oil producing properties.

	Three months ended June 30,						Quarter to quarter change			Six months ended June 30,						Year to year change
	2003			2004			2003-2004			2003			2004			2003-2004
	(In thousands)
Commodity price risk management activities:

Cash settlements on derivative financial instruments	$	(4,881	)	$	(8,543	)	$	(3,662	)	$	(12,761	)	$	(12,558	)	$	203
Non-cash change in fair value of derivative financial instruments	—			(9,060		)	(9,060		)	—			(31,923		)	(31,923		)
Total commodity price risk management activities	$	(4,881	)	$	(17,603	)	$	(12,722	)	$	(12,761	)	$	(44,481	)	$	(31,720	)

	Three months ended June 30,					Quarter to quarter change			Six months ended June 30,					Year to year change
	2003			2004		2003-2004			2003			2004		2003-2004
	(In thousands)
Other income (expense):

Income from terminated hedges	$	631		$	—	$	(631	)	$	1,606		$	—	$	(1,606	)
Income (expense) from hedge ineffectiveness	—			—		—			(2,544		)	—		2,544
Gain/(loss) from foreign currency translation	(823		)	501		1,324			(1,078		)	681		1,759
Interest, dividend, processing and other, net	488			568		80			615			1,033		418
Total other income (expense)	$	296		$	1,069	$	773		$	(1,401	)	$	1,714	$	3,115

Our cash settlements of derivative financial instruments reduced revenue by $4.9 million and $8.5 million during the three months ended June 30, 2003 and 2004, respectively, and $12.8 million and $12.6 million, respectively, during the six months ended June 30, 2003 and 2004. The NYMEX oil and natural gas prices that are used to settle our hedges increased significantly 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 quarter and decreased our revenues 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.

Prior to the completion of the going private transaction, we accounted for our derivative financial instruments as cash flow hedges. During the six months period ended June 30, 2003, we reduced our revenues by $2.5 million for the ineffective portion of the change in the fair value of our hedges. The ineffectiveness was primarily due to a significant increase in March 2003 in the difference between the NYMEX price for oil and natural gas, which is the price we use to settle our derivative financial instruments and the actual price that we receive in the field for the physical delivery of our oil and natural gas production. For the three and six month periods ended June 30, 2004, we have recognized as a reduction of revenue $9.1 million and $31.9 million, respectively, from the change in the fair value of our derivative financial instruments. Previously, the effective portion of this change was reflected in other comprehensive income while the ineffective portion was recognized in current period earnings. We expect that our revenues will continue to be significantly impacted in future periods by the change 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 three months ended June 30, 2004, the following percentages of our oil and natural gas production were subject to derivative financial instruments: 57% and 44% of oil and natural gas production were subject to swap agreements; 23% of natural gas production was subject to floor price agreements; and, 12% of natural gas production was subject to costless collar agreements.

During the three and six months ended June 30, 2003, we recorded approximately $600,000 and $1.6 million as non-cash income from terminated hedges as other income. As a result of the going private transaction, we ceased recording such income. During the three month and six month periods ended June 30, 2004, we have recorded foreign currency transaction gains of $501,000 and $681,000, respectively, while we had foreign currency transaction losses of $823,000 and $1.1 million during the three and six month periods ended June 30, 2003. This increase in income is a result of the relative increase of the U.S. dollar versus the Canadian dollar.

Costs and Expenses

The following tables present our oil and natural gas production costs and average oil and natural gas production cost per Mcfe for the three and six months ended June 30, 2003 and 2004.

	Three months ended June 30,				Quarter to Quarter change			Six months ended June 30,				Year to year change
	2003		2004		2003-2004			2003		2004		2003-2004
	(In thousands)

Oil and natural gas production costs:

Oil and natural gas operating costs:
EXCO	$	3,738	$	2,844	$	(894	)	$	7,245	$	6,364	$	(881	)
North Coast	—		2,189		2,189			—		3,473		3,473
Total U.S.	3,738		5,033		1,295			7,245		9,837		2,592
Canada	3,617		4,608		991			7,201		8,781		1,580
Total	$	7,355	$	9,641	$	2,286		$	14,446	$	18,618	$	4,172

Production and ad valorem taxes:
EXCO	$	1,272	$	1,262	$	(10	)	$	2,673	$	2,343	$	(330	)
North Coast	—		815		815			—		1,333		1,333
Total U.S.	1,272		2,077		805			2,673		3,676		1,003
Canada	259		189		(70		)	287		404		117
Total	$	1,531	$	2,266	$	735		$	2,960	$	4,080	$	1,120

Total oil and natural gas production costs:
EXCO	$	5,010	$	4,106	$	(904	)	$	9,918	$	8,707	$	(1,211	)
North Coast	—		3,004		3,004			—		4,806		4,806
Total U.S.	5,010		7,110		2,100			9,918		13,513		3,595
Canada	3,876		4,797		921			7,488		9,185		1,697
Total	$	8,886	$	11,907	$	3,021		$	17,406	$	22,698	$	5,292

	Three months ended June 30,				Quarter to Quarter change			Six months ended June 30,				Year to year change
	2003		2004		2003-2004			2003		2004		2003-2004


Oil and natural gas production costs per Mcfe:

Oil and natural gas operating costs:
EXCO	$	1.18	$	0.95	$	(0.23	)	$	1.13	$	1.03	$	(0.10	)
North Coast	—		0.73		0.73			—		0.68		0.68
Total U.S.	1.18		0.84		(0.34		)	1.13		0.87		(0.26		)
Canada	1.21		1.00		(0.21		)	1.15		1.03		(0.12		)
Total	1.19		0.91		(0.28		)	1.14		0.94		(0.20		)

Production and ad valorem taxes:
EXCO	$	0.40	$	0.42	$	0.02		$	0.42	$	0.38	$	(0.04	)
North Coast	—		0.27		0.27			—		0.26		0.26
Total U.S.	0.40		0.35		(0.05		)	0.42		0.32		(0.10		)
Canada	0.09		0.04		(0.05		)	0.05		0.05		—
Total	0.25		0.21		(0.04		)	0.23		0.21		(0.02		)

Total oil and natural gas production:
EXCO	$	1.58	$	1.37	$	(0.21	)	$	1.54	$	1.41	$	(0.13	)
North Coast	—		1.00		1.00			—		0.93		0.93
Total U.S.	1.58		1.18		(0.40		)	1.54		1.19		(0.35		)
Canada	1.30		1.04		(0.26		)	1.19		1.08		(0.11		)
Total	1.44		1.12		(0.32		)	1.37		1.14		(0.23		)

Our oil and natural gas operating costs for the three and six months ended June 30, 2004 increased $2.3 million and $4.2 million, or 31% and 29%, respectively, from the same periods in 2003. The primary reasons for the increases in oil and natural gas operating costs are:

• our acquisition of North Coast which increased oil and natural gas operating costs by $2.2 million and $3.5 million;

• our acquisitions of additional interests in the Vinegarone properties in the United States and the acquisition of several

properties in Canada during 2003 and 2004; and

• other, smaller acquisitions and new wells added through our development and exploitation capital program, mainly in Canada.

These increases were partially offset by the oil and natural gas operating costs incurred on oil and natural gas properties in the United States that were sold in 2003 and 2004. Oil and natural gas operating costs in the Appalachian Basin, where North Coast operates, are generally lower on a per unit basis, than in the basins where EXCO operates.

Production and ad valorem taxes for the three and six months ended June 30, 2004 increased by $735,000 and $1.1million, or 48% and 38%, respectively, over the same periods in 2003. These increases are primarily attributable to our acquisition of North Coast which increased production and ad valorem taxes by $815,000 and $1.3 million. These increases were partially offset by absence of production taxes from oil and natural gas properties in the United States that were sold in 2003 and 2004. These taxes are generally based upon the price received for production. No production taxes are paid in Canada.

Our depreciation, depletion and amortization costs for the three and six months ended June 30, 2004 increased by $7.3 million and $12.9 million, or 143% and 128%, respectively, from the same periods in 2003. The primary reasons for this increase are:

• the increase in basis associated with proved oil and natural gas property value due to the going private transaction;

• our acquisitions of North Coast (which accounted for approximately $3.8 million and $6.3 million of the increases), the additional interests in the Vinegarone properties and other smaller property acquisitions during 2003 and 2004; and

• the higher sales volumes from Canadian properties for the three and six months ended June 30, 2004 when compared to the three and six months ended June 30, 2003.

Accretion of discount on asset retirement obligations is the result of the adoption, as of January 1, 2003, of SFAS 143, “Accounting for Asset Retirement Obligations.” This non-cash expense 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. See “Note 2—Summary of Significant Accounting Policies — Deferred Abandonment and Asset Retirement Obligations” of the notes to our December 31, 2003 consolidated financial statements included in the Prospectus dated April 22, 2004, for our senior notes exchange offer for additional information regarding our adoption of SFAS 143.

	Three months ended June 30,						Quarter to Quarter change			Six months ended June 30,						Year to year change
	2003			2004			2003-2004			2003			2004			2003-2004
	(In thousands, except per unit and employee count)
General and administrative costs:

Gross G&A expense	$	5,022		$	7,050		$	2,028		$	9,493		$	12,874		$	3,381
Operator overhead charges	(597		)	(625		)	(28		)	(1,199		)	(1,315		)	(116		)
Capitalized acquisition and exploitation charges	(329		)	(652		)	(323		)	(650		)	(1,021		)	(371		)
Net G&A expense	$	4,096		$	5,773		$	1,677		$	7,644		$	10,538		$	2,894

General and administrative expense per Mcfe	$	0.66		$	0.54		$	(0.12	)	$	0.60		$	0.53		$	(0.07	)
Number of employees at end of period	129			296			167			129			296			167

Our general and administrative costs for the three and six months ended June 30, 2004 increased by $1.7 million and $2.9 million, or 41% and 38%, respectively, over the same periods in 2003 and was primarily attributable to:

• the acquisition of North Coast which increased general and administrative costs by $1.3 million and $2.0 million and the total number of employees at June 30, 2004 by 151;

• an increase in salaries, benefits and other personnel related costs of $1.1 million and $2.4 million, a significant portion of which is related to compensation and bonus plans as a result of the going private transaction;

• a reduction in legal expense of approximately $600,000 and $798,000 primarily due to costs incurred in 2003 for the going private transaction; and

• in 2003, we had stock option compensation expense of approximately $409,000 and $846,000 while there was no stock option compensation expense in 2004.

We expect that our general administrative expenses will increase during 2004 as a result of the acquisition of North Coast. The Appalachian Basin, where North Coast operates, represents a new core area for us and, as a result, we have decided at this time to not make significant changes in the operations or staffing of North Coast.

	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Year to year change
	2003		2004		2003-2004			2003		2004		2003-2004
	(In thousands)

Interest expense:

7 ¼% senior notes due 2011	$	—	$	7,788	$	7,788		$	—	$	12,722	$	12,722
U.S. and Canadian credit agreements	1,287		318		(969		)	2,331		1,605		(726		)
$50 million senior term loan	—		—		—			—		222		222
Amortization and write off of deferred financing costs	—		914		914			—		3,056		3,056
Interest expense on interest rate swaps	—		208		208			—		341		341
Other interest expense	—		25		25			64		99		35
Total interest expense	$	1,287	$	9,253	$	7,966		$	2,395	$	18,045	$	15,650

Our interest expense for the three and six months ended June 30, 2004 increased $8.0 million and $15.7 million from the same periods in 2003. These increases are primarily due to the issuance on January 20, 2004 of $350.0 million aggregate principal amount and on April 13, 2004 of $100.0 million, aggregate principal amount of 7¼% senior notes due 2011. Additionally, the amortization of deferred financing costs related to the senior notes and the amendment and restatement of our U.S. and Canadian credit facility increased interest expense by $914,000 and $3.1 million. (Prior to 2004, the amortization of deferred financing costs is reflected in the condensed consolidated statement of operations as part of depreciation, depletion and amortization). Amortization of deferred financing costs in 2004 includes approximately $1.7 million in costs relating to the senior term loan that was repaid in full in January 2004 and fees incurred on a bridge facility related to the North Coast acquisition. No funds were borrowed under the bridge facility. Our long-term debt balance at June 30, 2004 was $453.2 million compared to $207.9 million at December 31, 2003. As a result of the issuance of the senior notes on January 20, 2004 and April 13, 2004, we expect our interest expense to be significantly higher in 2004 than it was in 2003.

Prior to the completion of the going private transaction, we did not record any income tax benefit in the U.S. associated with losses generated in the U.S., as it was uncertain whether we would be able to utilize our net deferred tax asset. Accordingly, the tax effects of our U.S. generated losses were offset by an increase in our valuation allowance. This resulted in an overall higher effective tax rate.

Effective July 29, 2003 and in conjunction with our going private transaction, the deferred tax asset valuation allowance was reduced in the purchase price allocation as EXCO (successor basis) is now in a deferred tax liability position. There is a valuation allowance of approximately $2.6 million for net operating loss carryforwards that are subject to limitations and are expected to expire before being utilized. During the three and six months ended June 30, 2004, EXCO recognized tax benefits in the U.S. of $1.8 million and $8.5 million relating to U.S. generated losses during this period. During the three month period ended June 30, 2004, we recognized Canadian tax expense of $2.4 million that consists of a current tax expense of $2.5 million and a deferred income tax benefit of approximately $150,000. During the six month period ended June 30, 2004, we recognized Canadian tax expense of $4.1 million that consists of a current tax expense of $4.8 million and a deferred income tax benefit of approximately $700,000. The deferred tax benefit for the three and six month periods ended June 30, 2004 is primarily the result of tax legislation enacted in May 2004 in the Province of Alberta to lower its income tax rate by 1%. That resulted in a benefit of approximately $900,000. There was additional tax legislation that became effective in Canada on November 7, 2003 that will phase-in reduced income tax rates and allow for the deductibility of crown royalties in the determination of federal and provincial income taxes which resulted in a deferred tax benefit of $4.9 million in the fourth quarter of 2003. However, the Province of Alberta has indicated that it is not going to follow the federal government phase-in deduction of crown royalties and it intends to enact legislation during 2004 that will provide for the full deduction of crown royalties beginning in 2007 with no phase-in period. This legislation has been introduced but has not yet been enacted. As a result, we have not recognized the impact of these potential tax law changes as of June 30, 2004.

The cumulative effect of change in accounting principle, net of income tax, is the result of the adoption of SFAS 143 on January 1, 2003. In accordance with the provisions of SFAS 143, we recognized a $255,000 benefit from the cumulative effect of change in accounting principle, net of $690,000 of associated deferred income taxes.

Our Liquidity, Capital Resources and Capital Commitments

General

Most of our growth has resulted from acquisitions and our development and exploitation program. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash flow from operations, bank financing and the sale or issuance of 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. We are currently highly leveraged. We may need to raise additional equity capital to allow us to acquire significant oil and natural gas properties in the future. We cannot assure you that funds will be available to us in the future to meet our budgeted capital spending or to fund acquisitions. Furthermore, our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders. In addition, the indenture governing our senior notes contains restrictions on incurring indebtedness and the pledging of our assets. If we cannot secure additional funds for our planned development and exploitation activities or for future acquisitions, then we will be required to delay or substantially reduce these activities.

We have significantly increased the amount of our long-term debt since December 31, 2003. This increase was primarily the result of the issuance on January 20, 2004 of $350.0 million aggregate principal amount of 7¼% senior notes. Additionally, on April 13, 2004, we completed a private placement of an additional $100.0 million aggregate principal amount of our 7¼% senior notes due January 15, 2011 having the same terms and governed by the same indenture as the notes issued on January 20, 2004. The notes issued April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. We used approximately $98.8 million of the proceeds from the April 2004 offering to repay substantially all of the indebtedness outstanding under our Canadian credit agreement.

We generated operating cash flow of approximately $34.6 million and $63.7 million after changes in working capital for the three and six months ended June 30, 2004, which helped fund our acquisition, development and exploitation activities. At June 30, 2004, our cash and cash equivalents balance was $42.8 million, an increase of $35.5 million from December 31, 2003. On July 15, 2004, we made the initial interest payment on our 7 ¼% senior notes in the amount of $15.9 million. Our working capital deficit at June 30, 2004 decreased to $12.3 million from $13.6 million at December 31, 2003. This occurred primarily due to the accumulation of cash in anticipation of the July 15, 2004 interest payment.

Acquisitions and Capital Expenditures

In November 2003, we entered into the North Coast Acquisition Agreement to acquire all of the issued and outstanding stock of North Coast. On January 27, 2004, we completed the North Coast acquisition. We funded the North Coast acquisition from the net proceeds from the offering of the senior notes on January 20, 2004.

	Six Months Ended June 30,
	2003		2004
	(In thousands)
Capital expenditures:
Property acquisitions	$	12,570	$	30,655
Acquisition of North Coast Energy, Inc. net of cash acquired	—		215,133
Development capital expenditures	14,216		25,644
Other	6,610		4,925
Total capital expenditures	$	33,396	$	276,357

During 2004, we have budgeted approximately $75.6 million for our development, exploitation and exploration activities, including $23.5 million for properties acquired in the North Coast acquisition. For the six months ended June 30, 2004, we spent $10.6 million in the United States and $15.1 million in Canada on our development and exploitation activities. As of June 30, 2004, we were contractually obligated to spend $2.7 million for our development and exploitation activities.

On July 21, 2004, we entered into an agreement to acquire oil and natural gas properties located in Alberta, Canada for a price of CDN $25.5 million (approximately U.S. $19.1 million). We anticipate that we will complete this acquisition during August 2004. We anticipate that this acquisition will be funded with borrowings under our Canadian credit agreement. We also completed an acquisition of oil and natural gas properties located in Alberta, Canada on July 21, 2004 for a price of CDN $1.8 million (approximately U.S. $1.4 million). This acquisition was funded with surplus cash.

On July 29, 2004, we acquired natural gas properties located in Rusk County, Texas for a total purchase price of $35.9 million ($35.6 million after contractual adjustments). Additionally, we have placed $2.3 million in an escrow account to acquire additional interests in certain of the same properties if the seller is able to satisfy certain contractual obligations. Estimated total proved reserves acquired and to be acquired, net to our interest, include approximately 244,600 Bbls of oil and 25.2 Bcf of natural gas. We funded the acquisition with $32.0 million in borrowings under our U.S. credit agreement and from surplus cash. The properties acquired consist of 32 producing natural gas wells, which we now operate, and a significant number of proved undeveloped, probable and possible locations. The acquisition of these properties may result in an increase in our budgeted capital expenditures for our development, exploitation and exploration activities in 2004.

We expect to continue to utilize cash from operations and available funds under our credit agreements to fund our acquisitions, capital expenditures and working capital. We also plan on selling non-strategic assets during 2004. From January 1,

2004 through June 30, 2004, we have sold non-strategic oil and natural gas properties in the United States for net proceeds of approximately $13.8 million. We anticipate that we may realize up to $50.0 million from the sale of oil and natural gas properties during 2004. We also sold EXCO’s claim in the Enron bankruptcy to a third party in April 2004 for net proceeds of approximately $4.7 million. We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our amended and restated credit facilities are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes and oil and natural gas prices. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may affect our production in future periods. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. We have experienced increased costs for tubular goods and for certain services during 2004. Further, we have encountered difficulties in contracting for drilling rigs and other services due to high demand. Currently, we do not believe that these conditions have had a significant impact upon our capital expenditures programs or our results of operations. If the conditions continue, however, projects may be delayed due to lack of services or materials or we may have to delay projects to stay within our capital budget.

7 ¼% 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 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 agreements, 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 available for general working capital purposes.

On April 13, 2004, we issued an additional $100.0 million principal amount of our 7¼% senior notes due January 15, 2011 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 notes issued on January 20, 2004. Of the total proceeds of $103.25 million, approximately $98.8 million was used to repay substantially all of our outstanding indebtedness under the Canadian credit agreement, approximately $1.2 million was used for fees and expenses associated with the offering, with the remainder, approximately $3.2 million, available for general working capital purposes.

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

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

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

• Make investments;

• Create liens on our assets;

• Enter into sale/leaseback transactions;

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

• Engage in transactions with our affiliates;

• Transfer or issue shares of stock of subsidiaries;

• Transfer or sell assets; and

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

As required by the registration rights agreements we entered into in conjunction with the sale of the senior notes, we exchanged the senior notes for a new issue of substantially identical notes registered under the Securities Act. The exchange offer expired on May 28, 2004 and holders of all but $300,000 of the senior notes accepted our offer. The exchange offer was closed on June 1, 2004.

Credit Agreements

U.S. Credit Agreement. On January 27, 2004, our U.S. credit agreement was amended and restated to provide for

borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the U.S. credit agreement maturity date to January 27, 2007. Upon the issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004, the U.S. credit agreement borrowing base was reduced to $95.0 million. Effective June 28, 2004, the borrowing base was redetermined at $145.0 million, and will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At June 30, 2004, we had $1,000 of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $144.7 million available for borrowing. Borrowings under our amended and restated credit agreement are secured by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. 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 .50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At June 30, 2004, the six month LIBOR rate was 1.94%, which would result in an interest rate of approximately 3.19% on any new indebtedness we may incur under the U.S. credit agreement. At July 31, 2004, we had $32.0 million of outstanding U.S. indebtedness with a weighted average cost of 4.50%, which on August 6, 2004 was paid down to $24.0 million of outstanding U.S. indebtedness with a weighted average cost of 2.75%, and approximately $120.7 million available for borrowing.

Canadian Credit Agreement. On January 27, 2004, our Canadian credit agreement was amended and restated to provide for borrowings up to $189.4 million with a borrowing base of approximately $105.0 million (CDN $138.6 million using the exchange rate on January 26, 2004). The amendment also provided for an extension of the Canadian credit agreement maturity date to January 27, 2007. The issuance of the $100.0 million in additional 7¼% senior notes on April 13, 2004 did not impact the borrowing base under the Canadian credit agreement. 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), and will be redetermined each November 1 and May 1 thereafter. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. At June 30, 2004, we had approximately $1,000 of outstanding indebtedness and approximately $105.0 million available for borrowing. Borrowings under the credit agreement are secured by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. At our election, interest on borrowings may be (i) the Canadian prime rate plus an applicable margin or (ii) the Banker’s Acceptance rate plus an applicable margin. At June 30, 2004, the six month Banker’s Acceptance rate was 2.29%, which would result in an interest rate of approximately 3.54% on any new indebtedness we incur under the Canadian credit agreement. At July 31, 2004, we had approximately $1,000 of outstanding Canadian indebtedness with a weighted average cost of 4.00%, and approximately $105.0 million available for borrowing.

Financial Covenants and Ratios. Our amended and restated U. S. and Canadian credit agreements contain 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 credit agreements) 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 credit agreements) to be less than 2.5 to 1.0 at the end of each fiscal quarter.

As of June 30, 2004, we were in compliance with the covenants contained in our U.S. and Canadian credit agreements.

Dividend Restrictions. We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock. Even if our credit agreements 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.

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 7 1/4% senior notes issued on January 20, 2004.

Debt Service Requirements. Our debt service requirements as of June 30, 2004 on our amended and restated U.S. credit agreement, our amended and restated Canadian credit agreement and our senior notes are shown in the following table.

	Payments Due by Period
	2004		2005		2006		2007		2008 and thereafter		Total
	(In millions)
U.S. Credit Agreement
Interest	$	—	$	—	$	—	$	—	$	—	$	—
Principal	—		—		—		—		—		—

	—		—		—		—		—		—
Canadian Credit Agreement
Interest	—		—		—		—		—		—
Principal	—		—		—		—		—		—

	—		—		—		—		—		—
7¹/₄% Senior Notes
Interest	30.8		32.6		32.6		32.6		99.2		227.8
Principal	—		—		—		—		450.0		450.0

	30.8		32.6		32.6		32.6		549.2		677.8
Total
Interest	30.8		32.6		32.6		32.6		99.2		227.8
Principal	—		—		—		—		450.0		450.0
	$	30.8	$	32.6	$	32.6	$	32.6	$	549.2	$	677.8

Equity Transactions

On March 11, 2003, we entered into an Agreement and Plan of Merger providing for the merger of ER Acquisition, Inc., a wholly-owned subsidiary of EXCO Holdings into EXCO. EXCO Holdings was formed by our chairman and chief executive officer, Douglas H. Miller, and his buyout group for the purpose of completing the going private transaction, which closed on July 29, 2003. In the going private transaction, each outstanding share of our common stock, other than shares held by EXCO Holdings and its affiliates, was converted into the right to receive $18.00 in cash per share. The buyout was funded by borrowing under our former credit facilities and approximately $172.0 million in equity. The equity capital for the going private transaction was provided by investment funds and accounts managed by Cerberus, our management and institutional and other investors. The capital stock of EXCO Holdings is owned by:

• members of our management and other of our employees, who own in the aggregate approximately 16% of the voting capital stock of EXCO Holdings;

• EXCO Investors, LLC, a limited liability company formed prior to the going private transaction for the purpose of holding capital stock of EXCO Holdings, the members of which include business acquaintances of Mr. Miller, which owns approximately 11% of the voting capital stock of EXCO Holdings (the vote of which shares is controlled by Mr. Miller);

• affiliates of Cerberus, who own in the aggregate approximately 55% of the voting capital stock of EXCO Holdings; and

• other institutional investors, who own in the aggregate approximately 18% of the voting capital stock of EXCO Holdings.

EXCO Holdings’ stepped up basis was pushed down to us in accordance with Staff Accounting Bulletin No. 54. See Note 1 to our December 31, 2003 consolidated financial statements included in the Prospectus for our senior notes exchange offer dated April 22, 2004. Accordingly, EXCO Holdings’ investment in us is reflected as additional paid in capital in the December 31, 2003 consolidated balance sheet.

Derivative Financial Instruments

We may use derivative 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 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 credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. As of July 31, 2004, we had the following open positions in place:

	Swaps						Floors			Ceilings
	Gas- Mmmbtu	Average contract- $/Mmbtu		Oil- Mbbls	Average contract- $/Bbl		Gas- Mmmbtu	Average contract- $/Mmbtu		Gas- Mmmbtu	Average contract- $/Mmbtu

2004	5,367	$	4.61	329	$	25.19	4,406	$	4.04	3,060	$	6.01
2005	19,272	5.18		602	31.11		1,059	4.25		—	—
2006	12,228	4.95		—	—		—	—		—	—
2007	6,387	4.60		—	—		—	—		—	—
2008	2,745	4.55		—	—		—	—		—	—
2009	1,825	4.51		—	—		—	—		—	—
2010	1,825	4.51		—	—		—	—		—	—
2011	1,825	4.51		—	—		—	—		—	—
2012	1,830	4.51		—	—		—	—		—	—
2013	1,825	4.51		—	—		—	—		—	—

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

Interest Rate Risk Management Activities

As a result of the North Coast acquisition, we assumed the following interest rate swaps:

Original Term	Notional Amount		LIBOR Rate Fixed		Fair Value at July 31, 2004
					(In thousands)
January 1, 2003 to December 31, 2004	$	20,000,000	3.2	%	$	(144	)
January 1, 2001 to December 31, 2004	$	20,000,000	3.0	%	$	(120	)

Gains and losses are determined using a 360 day year and based on the 3-month LIBOR rate set quarterly. The cash settlements on these interest rate swaps are included in interest expense.

Contractual Obligations and Commercial Commitments

The following table presents a summary of our contractual obligations at June 30, 2004 with set and determinable payments .

	Payments Due by Period
Contractual Obligations	2004-2005		2006-2007		2008 and thereafter		Total
	(Dollars in thousands)
Long-term debt(1)	$	—	$	2	$	450,000	$	450,002
Operating leases	3,221		2,905		1,582		7,708
Drilling/work commitments	2,731		—		—		2,731
Property acquisition agreements(2)	58,673		—		—		58,673
Bonus retention program for employee stockholders	2,760		3,220		—		5,980
Total contractual cash obligations	$	67,385	$	6,127	$	451,582	$	525,094

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

(2) Includes agreements entered into in July 2004.

We also have a $275,000 letter of credit that has been issued to a service provider which will expire in 2004.

Item 3. Quantitative and Qualitative Disclosure About Market Risk

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

Commodity Price Risk

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

The following table sets forth our oil and natural gas hedging activities as of July 31, 2004.

	Volume mmbtu/ bbls	Weighted Average Strike Price		Weighted Average Differential to NYMEX			Fair Value at July 31, 2004
	(In thousands, except prices and differentials)
Natural Gas:

Swaps:
2004	5,367	$	4.61				$	(9,205	)
2005	19,272	5.18					(22,826		)
2006	12,228	4.95					(11,492		)
2007	6,387	4.60					(5,254		)
2008	2,745	4.55					(1,495		)
2009	1,825	4.51					(669		)
2010	1,825	4.51					(418		)
2011	1,825	4.51					(249		)
2012	1,830	4.51					(136		)
2013	1,825	4.51					(69		)
	55,129

Floor Prices:
2004	4,406	4.04					18
2005	1,059	4.25					74
	5,465

Ceiling Prices:
2004	3,060	6.01					(2,493		)
	3,060

Basis Protection Swaps:
2004	662			$	(0.83	)	(29		)
	662

Total Natural Gas							(54,243		)

Oil:
Swaps:
2004	329	25.19					(5,627		)
2005	602	31.11					(4,754		)
	931

Total Oil							(10,381		)
Total Oil and Natural Gas							$	(64,624	)

At July 31, 2004, the average forward NYMEX oil prices per Bbl for remainder of calendar 2004 and 2005 were $42.39 and $39.19, respectively and the average forward NYMEX natural gas price per Mmbtu for the remainder of calendar 2004 and 2005 were $6.34 and $6.39, 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 during the quarter ended June 30, 2004, if the settlement price exceeded the actual weighted average strike price of $24.62, then a reduction in commodity price risk management activities revenue would have been recorded for the difference between the settlement price and $24.62 multiplied by the hedged volume of 193,750 Bbls. Conversely, if the settlement price was less than $24.62, then an increase in commodity price risk management activities revenue would have been recorded for the difference between the settlement price and $24.62 multiplied by the hedged volume of 193,750 Bbls. For example, for a hedged volume of 193,750 Bbls, if the settlement price was $25.62, then commodity price risk management activities revenue would have decreased by $193,750. Conversely, if the settlement price was $23.62, commodity price risk management activities revenue would have increased by $193,750.

Interest Rate Risk

At July 31, 2004, our exposure to interest rates related primarily to borrowings under our credit agreements and interest earned on short-term investments. The interest rate is fixed at 7 ¼% on our $450.0 million in senior notes. As of June 30, 2004, we were not using any derivatives to manage interest rate risk. As a result of the North Coast acquisition, we have assumed two interest rate swap agreements. Under these agreements, North Coast swapped the variable interest rate to be paid under its credit agreements for a fixed interest rate. Each agreement has a term through December, 31, 2004 and was for a notional amount of $20.0 million. The effective fixed rates of interest under the agreements are 4.9% and 5.1%. Interest is payable on borrowings under the Company’s credit agreements based on a floating rate as more fully described in “Part I – Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources”.

Equity Price Risk

Our investments in marketable securities are recorded at market value. We consider these investments to be “available for sale”, which means that unrealized gains and losses are excluded from earnings and included in other comprehensive income unless the decline in the fair value of the investments is “other than temporary”. At June 30, 2004, the market value of our investments in marketable securities was $464,000. A temporary change in value of 10% would result in a $46,000 change in the market value and a corresponding adjustment to other comprehensive income of $46,000. An “other than temporary” decline in value of 10% would result in a $46,000 reduction in the market value and a corresponding non-cash pre-tax impairment expense of $46,000. As of June 30, 2004, we were not using any derivatives to manage equity price risk.

Foreign Currency Exchange Rate Risk

We account for a significant portion of our business in Canadian dollars. We are therefore subject to foreign currency exchange rate risk on cash flows of our Canadian operations that are not denominated in Canadian dollars. Presently, a significant portion of the sales of our Canadian oil and natural gas is denominated in U.S. dollars. Foreign currency exchange gains and/or losses related to these transactions have not been significant. The borrowings under our Canadian credit facility are denominated in Canadian dollars. The asset and liability balances of our Canadian business are translated monthly using current exchange rates, with any resulting unrealized translation gains or losses included in other comprehensive income. The unrealized foreign translation gain for the six month period ended June 30, 2004 was $4.9 million. As of June 30, 2004, we were not using any derivatives to manage foreign currency exchange rate risk.

Other Market Risk

During 2000 and through September 2001, we entered into several swap transactions with Enron North America Corp., an affiliate of Enron Corp. On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court. We terminated our Enron hedges and discontinued hedge accounting for our Enron derivatives effective November 30, 2001. At July 29, 2003, the date of the going private transaction, we had conservatively valued our asset from Enron at $2.8 million, or approximately 20% of the value on the day we terminated our positions. This valuation was based on the low range of informal offers we received for our position with Enron and other market information. In April 2004, we sold this claim to a third party for approximately $4.7 million.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures. The term “disclosure controls and procedures” is defined in Rule 13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. Our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this quarterly report, and they have concluded that as of that date, our disclosure controls and procedures were effective at ensuring that required information will be disclosed on a timely basis in our reports filed under the Exchange Act.

(b) Changes in Internal Controls. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 6 . Exhibits and Reports on Form 8-K

(a) The following exhibits are included herein:

EXHIBIT NUMBER		DESCRIPTION
3.1		Restated Articles of Incorporation of EXCO Resources, Inc.*

3.2		Restated Bylaws of EXCO Resources, Inc., as amended.**

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		Form of 7¼% Global Note Due 2011.**

4.4		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.*

4.5		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.**

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

10.1		Agreement, dated as of October 14, 2002, by and between EXCO Resources, Inc. and Douglas H. Miller, filed as an Exhibit to Douglas H. Miller’s Schedule 13D filed October 24, 2002 and incorporated by reference herein.

10.2		Joinder Agreement, executed by T. W. Eubank and dated as of October 23, 2002, filed as an Exhibit to Douglas H. Miller’s Schedule 13D filed October 24, 2002 and incorporated by reference herein.

10.3		Form of Joinder Agreement (executed by the following parties: J. Douglas Ramsey, Ph.D.; J. David Choisser; Charles R. Evans; Richard E. Miller; James M. Perkins, Jr.; Richard L. Hodges; John D. Jacobi; Daniel A. Johnson; Harold L. Hickey; Stephen E. Puckett; Russell W. Romoser; W. Andy Bracken; Paul B. Rudnicki; Gary M. Nelson; H. Wayne Gifford; Gary L. Parker; Craig F. Hruska; Steve Fagan; Dennis G. McIntyre; Neil Burrows; Gregory Robb; Jonathan Kuhn; James L. Beninger; Terry Pidkowa; Duane Masse; Jennifer M. Perry; Kirstie M. Egan; Wesley E. Roberts; Delwyn C. Dennison; Muharem Mastalic; Terry L. Trudeau; Jeffrey D. Benjamin and Earl E. Ellis) to that certain Agreement by and between EXCO Resources, Inc. and Douglas H. Miller and dated as of October 14, 2002, attached as Appendix B-4 to EXCO’s Schedule 14A filed on March 28, 2003 and incorporated by reference herein.

10.4		Confidentiality Agreement, dated as of September 12, 2002, between EXCO Resources, Inc. and Douglas H. Miller, individually and on behalf of the Receiving Party, filed as an Exhibit to EXCO, et al’s Schedule 13E-3 filed on March 28, 2003 and incorporated by reference herein.

10.5		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.

10.6		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.*

10.7		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.**

10.8		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.**

10.9		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.*

10.10		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.**

10.11		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.**

10.12		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.

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

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

10.15		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.

10.16		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.*

10.17		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.*

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

10.19		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.*

10.20		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.*

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

10.22		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.*

10.23		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.*

10.24		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.*

10.25		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 herewith.

10.26		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 herewith.

10.27		EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed herewith. ***

10.28		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed herewith.***

10.29		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed herewith.***

10.30		Severance Plan of EXCO Resources, Inc. effective as of August 15, 2002 filed as an Exhibit to EXCO’s Form 10-Q filed November 14, 2002 and incorporated by reference herein.***

10.31		EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed herewith.***

10.32		Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed herewith.***

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

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

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

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

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

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

*** These exhibits are management contracts.

(b) Reports on Form 8-K

During the quarter ended June 30, 2004, we filed the following current reports on Form 8-K:

On May 20, 2004, we filed a current report on Form 8-K, furnishing under Items 9 and 12 a press release we issued on May 19, 2004 announcing financial and operating results for the quarterly period ended March 31, 2004.

On June 1, 2004, we filed a current report on Form 8-K, furnishing under Items 5 and 7 a press release announcing the expiration of our exchange offer for our $450 million of 7 ¼% Senior Notes due 2011.

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: August 13, 2004	By:	/s/ DOUGLAS H. MILLER
		Douglas H. Miller Chairman and Chief Executive Officer

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

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

Index to Exhibits

EXHIBIT NUMBER		DESCRIPTION

3.1		Restated Articles of Incorporation of EXCO Resources, Inc.*

3.2		Restated Bylaws of EXCO Resources, Inc., as amended.**

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		Form of 7¼% Global Note Due 2011.**

4.4		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.*

4.5		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.**

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

10.1		Agreement, dated as of October 14, 2002, by and between EXCO Resources, Inc. and Douglas H. Miller, filed as an Exhibit to Douglas H. Miller’s Schedule 13D filed October 24, 2002 and incorporated by reference herein.

10.2		Joinder Agreement, executed by T. W. Eubank and dated as of October 23, 2002, filed as an Exhibit to Douglas H. Miller’s Schedule 13D filed October 24, 2002 and incorporated by reference herein.

10.3		Form of Joinder Agreement (executed by the following parties: J. Douglas Ramsey, Ph.D.; J. David Choisser; Charles R. Evans; Richard E. Miller; James M. Perkins, Jr.; Richard L. Hodges; John D. Jacobi; Daniel A. Johnson; Harold L. Hickey; Stephen E. Puckett; Russell W. Romoser; W. Andy Bracken; Paul B. Rudnicki; Gary M. Nelson; H. Wayne Gifford; Gary L. Parker; Craig F. Hruska; Steve Fagan; Dennis G. McIntyre; Neil Burrows; Gregory Robb; Jonathan Kuhn; James L. Beninger; Terry Pidkowa; Duane Masse; Jennifer M. Perry; Kirstie M. Egan; Wesley E. Roberts; Delwyn C. Dennison; Muharem Mastalic; Terry L. Trudeau; Jeffrey D. Benjamin and Earl E. Ellis) to that certain Agreement by and between EXCO Resources, Inc. and Douglas H. Miller and dated as of October 14, 2002, attached as Appendix B-4 to EXCO’s Schedule 14A filed on March 28, 2003 and incorporated by reference herein.

10.4		Confidentiality Agreement, dated as of September 12, 2002, between EXCO Resources, Inc. and Douglas H. Miller, individually and on behalf of the Receiving Party, filed as an Exhibit to EXCO, et al’s Schedule 13E-3 filed on March 28, 2003 and incorporated by reference herein.

10.5		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.

10.6		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.*

10.7		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.**

10.8		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.**

10.9		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.*

10.10		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.**

10.11		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.**

10.12		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.

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

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

10.15		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.

10.16		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.*

10.17		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.*

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

10.19		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.*

10.20		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.*

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

10.22		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.*

10.23		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.*

10.24		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.*

10.25		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 herewith.

10.26		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 herewith.

10.27		EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed herewith.***

10.28		Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed herewith.***

10.29		Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed herewith.***

10.30		Severance Plan of EXCO Resources, Inc. effective as of August 15, 2002 filed as an Exhibit to EXCO’s Form 10-Q filed November 14, 2002 and incorporated by reference herein.***

10.31		EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed herewith.***

10.32		Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed herewith.***

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

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

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

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

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

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

*** These exhibits are management contracts.

During the quarter ended June 30, 2004, we filed the following current reports on Form 8-K: