10-Q 1 a08-18983_110q.htm QUARTERLY REPORT PURSUANT TO SECTIONS 13 OR 15(D)

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

FORM 10-Q

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

		For the quarterly period ended June 30, 2008

		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 x NO o

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

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting
company)

Smaller reporting company
o

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

YES o NO x

The number of shares of common stock, par value $0.001 per share, outstanding as of August 1, 2008 was 210,883,821.

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EXCO RESOURCES, INC.

INDEX

PART I.		FINANCIAL INFORMATION

Item 1.		Financial Statements
		Condensed Consolidated Balance Sheets at June 30, 2008 and December 31, 2007
		Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2008 and 2007
		Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2008 and 2007
		Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2008 and 2007
		Notes to Condensed Consolidated Financial Statements
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.		Quantitative and Qualitative Disclosures About Market Risk
Item 4.		Controls and Procedures

PART II.		OTHER INFORMATION

Item 1.		Legal Proceedings
Item 4.		Submission of Matters to a Vote of Security Holders
Item 6.		Exhibits
		Signatures
		Index to Exhibits

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
(in thousands)	2008			2007
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	34,142		$	55,510
Accounts receivable:
Oil and natural gas	229,567			146,297
Joint interest	19,378			21,614
Interest and other	4,811			2,151
Derivative financial instruments	2,808			66,632
Deferred income taxes	209,601			6,764
Other	27,077			12,332
Total current assets	527,384			311,300
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	453,680			334,803
Proved developed and undeveloped oil and natural gas properties	5,667,619			4,926,053
Accumulated depletion	(709,572		)	(500,493		)
Oil and natural gas properties, net	5,411,727			4,760,363
Gas gathering assets	442,865			340,706
Accumulated depreciation and amortization	(23,794		)	(16,142		)
Gas gathering assets, net	419,071			324,564
Office and field equipment, net	23,456			20,844
Advance on pending acquisition	25,206			39,500
Derivative financial instruments	4,562			2,491
Deferred financing costs, net	18,705			20,406
Other assets	1,398			6,226
Goodwill	470,077			470,077
Total assets	$	6,901,586		$	5,955,771

See accompanying notes.

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	June 30,			December 31,
(in thousands, except per share and share data)	2008			2007
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	153,570		$	106,305
Accrued interest payable	22,094			21,835
Revenues and royalties payable	149,145			100,978
Income taxes payable	80			87
Current portion of asset retirement obligations	1,861			1,656
Derivative financial instruments.	598,860			47,306
Total current liabilities	925,610			278,167
Long-term debt	2,618,013			2,099,171
Asset retirement obligations and other long-term liabilities	105,699			89,810
Deferred income taxes	213,991			271,398
Derivative financial instruments	405,011			109,205
Commitments and contingencies	—			—

7.0% Cumulative Convertible Perpetual Preferred Stock, $0.001 par value, 39,008 shares outstanding at June 30, 2008 and December 31, 2007, liquidation preference of $391,218	388,574			388,574
Hybrid Preferred Stock, $0.001 par value, 160,992 shares outstanding at June 30, 2008 and December 31, 2007, liquidation preference of $1,614,616	1,603,704			1,603,704
Shareholders’ equity:
Preferred stock, $0.001 par value; authorized shares - 10,000,000; issued and outstanding shares - 200,000 presented above	—			—
Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 105,556,370 at June 30, 2008 and 104,578,941 at December 31, 2007	106			105
Additional paid-in capital	1,064,639			1,043,645
Retained earnings (deficit)	(423,761		)	71,992
Total shareholders’ equity	640,984			1,115,742
Total liabilities and shareholders’ equity	$	6,901,586		$	5,955,771

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended						Six months ended
	June 30,						June 30,
(in thousands, except per share data)	2008			2007			2008			2007
Revenues and other income:
Oil and natural gas	$	428,651		$	261,552		$	753,594		$	381,911
Midstream	26,956			5,211			34,848			9,757
Gain (loss) on derivative financial instruments	(662,653		)	77,897			(1,003,847		)	(18,122		)
Other income	2,249			1,883			3,676			5,162
Total revenues and other income	(204,797		)	346,543			(211,729		)	378,708
Costs and expenses:
Oil and natural gas production	62,058			47,046			114,539			76,973
Midstream operating expenses	22,824			4,139			30,851			7,103
Gathering and transportation	3,700			2,303			6,831			3,275
Depreciation, depletion and amortization.	111,281			105,148			220,498			156,472
Accretion of discount on asset retirement obligations	1,473			1,267			2,789			2,210
General and administrative	19,657			14,990			42,284			29,165
Interest	20,273			33,543			56,293			110,252
Total costs and expenses	241,266			208,436			474,085			385,450
Income (loss) before income taxes.	(446,063		)	138,107			(685,814		)	(6,742		)
Income tax expense (benefit)	(183,149		)	55,221			(260,061		)	(1,931		)
Net income (loss)	(262,914		)	82,886			(425,753		)	(4,811		)
Preferred stock dividends	(35,000		)	(51,099		)	(70,000		)	(52,235		)
Net income (loss) available to common shareholders	$	(297,914	)	$	31,787		$	(495,753	)	$	(57,046	)
Net income (loss) per common share:
Net income (loss) per common share - basic	$	(2.83	)	$	0.30		$	(4.72	)	$	(0.55	)
Net income (loss) per common share - diluted	$	(2.83	)	$	0.30		$	(4.72	)	$	(0.55	)
Weighted average shares:
Basic	105,253			104,313			104,968			104,258
Diluted	105,253			106,909			104,968			104,258

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended
	June 30,
(in thousands)	2008			2007
Operating Activities:
Net loss	$	(425,753	)	$	(4,811	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	220,498			156,472
Stock option compensation expense.	6,688			4,465
Accretion of discount on asset retirement obligations	2,789			2,210
Non-cash change in fair value of derivatives	909,111			56,824
Cash settlements of assumed derivatives	62,099			3,678
Deferred income taxes	(260,244		)	(1,931		)
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt	817			9,916
Effect of changes in:
Accounts receivable	(83,688		)	(91,091		)
Other current assets	(13,829		)	(755		)
Accounts payable and other current liabilities	93,746			34,149
Net cash provided by operating activities.	512,234			169,126
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(910,485		)	(2,353,707		)
Advance on pending acquisition	(25,205		)	5,000
Proceeds from disposition of property and equipment and other	1,532			376,041
Net cash used in investing activities	(934,158		)	(1,972,666		)
Financing Activities:
Borrowings under credit agreements	812,200			1,928,000
Repayments under credit agreements	(291,700		)	(2,023,532		)
Settlements of derivative financial instruments with a financing element	(62,099		)	(3,678		)
Proceeds from issuance of common stock	12,929			2,228
Proceeds from issuance of preferred stock	—			2,000,000
Payment of preferred stock dividends	(70,000		)	(43,717		)
Payments for preferred stock issuance costs	—			(7,498		)
Deferred financing costs	(774		)	(17,804		)
Net cash provided by financing activities	400,556			1,833,999
Net increase (decrease) in cash	(21,368		)	30,459
Cash at beginning of period	55,510			22,822
Cash at end of period	$	34,142		$	53,281

Supplemental Cash Flow Information:
Interest paid	$	63,651		$	108,662
Derivative financial instruments assumed in Vernon Acquisition	$	—		$	(60,015	)
Derivative financial instruments assumed in Southern Gas Acquisition	$	—		$	(42,204	)
Supplemental non-cash investing and financing activities:
Capitalized stock compensation	$	1,276		$	882
Capitalized interest	$	316		$	—
Issuance of common stock for director services	$	102		$	—
Value of shares received for sale of properties	$	—		$	3,431

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

				Additional		Retained			Total
	Common Stock			paid-in		earnings			shareholders’
(in thousands)	Shares	Amount		capital		(deficit)			equity
Balance at December 31, 2007	104,579	$	105	$	1,043,645	$	71,992		$	1,115,742
Issuance of common stock	977	1		13,030		—			13,031
Preferred stock dividends	—	—		—		(70,000		)	(70,000		)
Share-based compensation	—	—		7,964		—			7,964
Net loss	—	—		—		(425,753		)	(425,753		)
Balance at June 30, 2008	105,556	$	106	$	1,064,639	$	(423,761	)	$	640,984

Balance at December 31, 2006	104,162	$	104	$	1,024,442	$	155,304		$	1,179,850
Issuance of common stock	222	—		2,228		—			2,228
Preferred stock dividends	—	—		—		(52,235		)	(52,235		)
Share-based compensation	—	—		5,347		—			5,347
Net loss	—	—		—		(4,811		)	(4,811		)
Balance at June 30, 2007	104,384	$	104	$	1,032,017	$	98,258		$	1,130,379

See accompanying notes.

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EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and basis of presentation

Unless the context requires otherwise, references in this quarterly report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

EXCO Resources, Inc., a Texas corporation, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. Our assets in East Texas/North Louisiana are owned by our subsidiary, EXCO Operating Company, LP (formerly EXCO Partners Operating Partnership, LP), and its subsidiaries and together they are collectively referred to as EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt.

The accompanying condensed consolidated balance sheets as of June 30, 2008 and December 31, 2007, the results of operations for the three and six months ended June 30, 2008 and 2007, the statements of cash flows for the six months ended June 30, 2008 and 2007 and the changes in shareholders’ equity for the six months ended June 30, 2008 and 2007, are for EXCO and its subsidiaries. All intercompany transactions have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or SEC, and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of EXCO at June 30, 2008 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2007.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

2. Significant recent activities

Appalachian Acquisition

On February 20, 2008, EXCO acquired shallow natural gas properties from EOG Resources, Inc. located primarily in EXCO’s central Pennsylvania operating area, or the Appalachian Acquisition. The purchase price, after reduction for preliminary closing adjustments of $7.4 million, was $388.4 million and was financed with funds drawn under the EXCO Resources credit agreement. Our preliminary purchase price allocation to the Appalachian Acquisition is presented in the following table. We expect to finalize the purchase price allocation in the third quarter of 2008.

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(in thousands)
Purchase price calculation:
Preliminary purchase price	$	387,644
Acquisition related expenses	741
Total purchase price	$	388,385

Allocation of purchase price:
Oil and natural gas properties - proved	$	334,308
Oil and natural gas properties - unproved	45,676
Gas gathering, compression facilities and other	19,876
Other property and equipment	2,617
Asset retirement obligations	(12,647		)
Other liabilities assumed	(1,445		)
Total purchase price allocation	$	388,385

Southern Gas Acquisition – final purchase price allocation

On March 31, 2008, we finalized the purchase price of our May 2007 acquisition of properties located in the Mid-Continent region from Anadarko Petroleum Corporation, or the Southern Gas Acquisition. Included in the Southern Gas Acquisition were oil and natural gas properties which were sold to Crimson Exploration on May 8, 2007, or the Gulf Coast Sale. The final adjusted purchase price allocation of $772.5 million is presented in the following table:

(in thousands)
Purchase price calculation:
Purchase price	$	770,498
Acquisition related expenses	2,040
Total purchase price	$	772,538

Allocation of purchase price:
Oil and natural gas properties - proved	$	586,407
Oil and natural gas properties - unproved	4,725
Gulf Coast Sale, including the value of the Crimson stock	241,948
Other, net	(5,771		)
Fair value (liability) of assumed derivative financial instruments	(42,204		)
Asset retirement obligations	(12,567		)
Total purchase price allocation	$	772,538

Pro forma results of operations

The following table reflects the unaudited pro forma results of operations as though the Appalachian Acquisition, our March 30, 2007 private placement of preferred stock and the acquisitions and dispositions during 2007, including proved and unproved oil and natural gas properties in North Louisiana, or the Vernon Acquisition, the Southern Gas Acquisition and the Gulf Coast Sale, had occurred on January 1, 2007 (see our Annual Report on Form 10-K for the year ended December 31, 2007 for a discussion of these acquisitions and sales).

	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share data)	2008			2007			2008			2007
Revenues and other income	$	(204,797	)	$	378,272		$	(205,375	)	$	550,062
Net income (loss)	$	(262,914	)	$	87,714		$	(423,386	)	$	51,287
Preferred stock dividends	(35,000		)	(35,000		)	(70,000		)	(70,000		)
Net income (loss) available to common shareholders	$	(297,914	)	$	52,714		$	(493,386	)	$	(18,713	)
Basic earnings (loss) per share	$	(2.83	)	$	0.51		$	(4.70	)	$	(0.18	)
Diluted earnings (loss) per share	$	(2.83	)	$	0.41		$	(4.70	)	$	(0.18	)

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3. Recent accounting pronouncements

In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards, or SFAS, No. 157, “Fair Value Measurements,” or SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years for financial instruments. FASB Financial Staff Position No. FAS 157-2 deferred implementation for other non-financial assets and liabilities for one year. Examples of non-financial assets and liabilities are asset retirement obligations and non-financial assets and liabilities initially measured at fair value in a business combination. We adopted SFAS No. 157 on January 1, 2008. See “Note 9. Derivative financial instruments and fair value measurements” for a discussion of the impacts of the adoption of SFAS No. 157.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” or SFAS No. 141(R). SFAS No. 141(R) replaces SFAS No. 141. SFAS No. 141(R) broadens the scope of business combinations to include bargain purchases and combinations of related companies, provides guidance on measuring goodwill and requires acquisition costs to be separate from the value of assets and liabilities purchased. SFAS No. 141(R) is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be adopted by us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 141(R) on our financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements,” or SFAS No. 160. SFAS No. 160 amends Accounting Research Bulletin 51, or ARB 51. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. It also amends certain of ARB No. 51’s consolidation procedures for consistency with the requirements of SFAS No. 141(R). SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be adopted by us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 160 on our financial statements.

In March 2008, the FASB issued SFAS, No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be adopted by us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 161 on our financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” or SFAS No. 162. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements. We do not expect SFAS No. 162 to have an impact on our financial statements.

4. Significant accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of proved reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in our Annual Report on Form 10-K for the year ended December 31, 2007.

5. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2008:

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(in thousands)
Asset retirement obligations at January 1, 2008	$	84,370
Activity during the six months ended June 30, 2008:
Liabilities incurred during the period	2,263
Liabilities settled during the period	(2,420		)
Additions to retirement obligations due to acquisitions	14,099
Accretion of discount	2,789
Asset retirement obligations as of June 30, 2008	101,101
Less current portion	1,861
Long-term portion	$	99,240

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

6. Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs, which totaled $453.7 million and $334.8 million as of June 30, 2008 and December 31, 2007, respectively, are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis, and we expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved 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 quantities 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, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.

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 our oil and natural gas properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). When computing our ceiling test, we evaluate the limitation at the end of each reporting period date. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation for price changes that occur after the balance sheet date to assess impairment as permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. At June 30, 2008, there was no ceiling test impairment.

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

7. Earnings (loss) per share

We account for earnings per share in accordance with SFAS No. 128, “Earnings per share,” or SFAS No. 128. SFAS No. 128 requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings (loss) per share for the three and six months ended June 30, 2008 and 2007 equals the net income (loss) available to common shareholders divided by the weighted average common shares outstanding during the period. Diluted earnings (loss) per common share for the three and six months ended June 30, 2008 and 2007 is computed in the same manner as basic earnings per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, including our Series A-1, Series B and Series C 7.0% Cumulative Convertible Perpetual Preferred Stock, or the 7.0% Preferred Stock, and our Series A-1 Hybrid Preferred Stock, or the Hybrid Preferred Stock, and together with the 7.0% Preferred Stock, the Preferred Stock, whether exercisable or not. Since we incurred net losses for the three and six months ended June 30, 2008 and the six months ended June 30, 2007, we have excluded the potential common stock equivalents from the assumed conversion of stock options of 5,774,000, 4,351,391 and 2,487,983, respectively. We have also excluded 105,263,074 shares of common stock equivalents

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from the assumed conversion of the 7.0% Convertible Preferred Stock and Hybrid Preferred Stock from the computation of earnings per share for all periods presented as they are antidilutive.

The following table presents the basic and diluted loss per share computations:

	Three months ended June 30,					Six months ended June 30,
(in thousands, except per share amounts)	2008			2007		2008			2007
Basic income (loss) per common share:
Net income (loss)	$	(262,914	)	$	82,886	$	(425,753	)	$	(4,811	)
Preferred stock dividends	35,000			51,099		70,000			52,235
Net income (loss) available to common shareholders	$	(297,914	)	$	31,787	$	(495,753	)	$	(57,046	)

Shares:
Weighted average number of common shares outstanding	105,253			104,313		104,968			104,258

Basic income (loss) per common share:
Net income (loss) available to common shareholders per common share	$	(2.83	)	$	0.30	$	(4.72	)	$	(0.55	)

Diluted income (loss) per share:
Net income (loss) available to common shareholders	$	(297,914	)	$	31,787	$	(495,753	)	$	(57,046	)

Shares:
Weighted average number of common shares outstanding	105,253			104,313		104,968			104,258
Dilutive effect of stock options	—			2,596		—			—
Weighted average common shares and common stock equivalent shares outstanding	105,253			106,909		104,968			104,258

Diluted income (loss) per share:
Net income (loss) available to common shareholders per common share	$	(2.83	)	$	0.30	$	(4.72	)	$	(0.55	)

8. Stock options

We account for stock options in accordance with SFAS No. 123(R), “Share-Based Compensation,” or SFAS No. 123(R). As required by SFAS No. 123(R), the granting of options to our employees under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Volatility is determined based on the combination of the weighted average volatility of our common stock price and the daily closing prices from five comparable public companies during the period when we were privately held. For the three and six months ended June 30, 2008, total share-based compensation was $4.3 million and $8.0 million, respectively, of which $3.7 million and $6.7 million, respectively, is included in general and administrative and lease operating expense and $0.6 million and $1.3 million, respectively, was capitalized as part of proved developed and undeveloped oil and natural gas properties. Total share-based compensation to be recognized on unvested awards as of June 30, 2008 is $21.5 million over a weighted average period of 1.1 years.

During the six months ended June 30, 2008, options to purchase 832,000 shares were granted under the 2005 Incentive Plan at prices ranging from $15.15 to $27.00 per share with fair values ranging from $5.39 to $10.04 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of June 30, 2008 and December 31, 2007, there were 6,346,725 and 7,022,375 shares available to be granted under the 2005 Incentive Plan, respectively.

9. Derivative financial instruments and fair value measurements

In September 2006, the FASB issued SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States and provides for expanded disclosure of information about fair value measurements. We adopted the provisions of SFAS No. 157 on January 1, 2008 for our derivative financial instruments’ assets and liabilities.

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SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. This fair value may be different than the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities. Prior to January 1, 2008, our derivative financial instruments were recorded at settlement value.

SFAS No. 157 also establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include:

Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.

As of June 30, 2008, our oil and natural gas derivative financial instruments and interest rate swaps are required to be measured at their fair value pursuant to SFAS No. 157. The following presents a summary of our derivative financial instruments at June 30, 2008:

(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(1,003,871	)	$	—	$	(1,003,871	)
Interest rate swaps	—		7,370			—		7,370
	$	—	$	(996,501	)	$	—	$	(996,501	)

Oil and natural gas derivatives

The following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value subject to the disclosure requirements of SFAS No. 157 as of June 30, 2008:

		Weighted
	Volume	average strike		Fair value at
(in thousands, except prices)	Mmbtu/Bbl	price		June 30, 2008
Natural Gas:
Swaps (NYMEX):
Remainder of 2008	53,810	$	8.34	$	(277,110	)
2009	100,530	8.18		(411,736		)
2010	40,748	8.03		(118,550		)
2011	9,125	7.97		(21,820		)
2012	1,830	4.51		(9,121		)
2013	1,825	4.51		(8,726		)
Total Natural Gas	207,868			(847,063		)

Oil:
Swaps (NYMEX):
Remainder of 2008	716	68.18		(51,474		)
2009	1,215	69.11		(82,582		)
2010	473	84.85		(22,752		)
Total Oil	2,404			(156,808		)
Total Oil and Natural Gas				$	(1,003,871	)

In measuring fair value of financial assets and liabilities pursuant to SFAS No. 157, we utilize quoted NYMEX futures for period prices applicable to our derivatives and other relevant information generated by market transactions. Our derivative financial instruments and their related fair value tier have been classified as Level 2. The significant observable

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inputs for our oil and natural gas derivatives are based principally on NYMEX strip prices, London Inter Bank Offered Rate, or LIBOR, and credit risk assessment which affects the discount rate to be utilized to compute fair value.

At June 30, 2008, the average forward NYMEX oil prices per Bbl for the remainder of 2008 and for 2009 were $141.05 and $140.64, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2008 and for 2009 was $13.54 and $12.47, respectively.

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBOR rates ranging from 2.45% to 2.8%. During the three and six months ended June 30, 2008, we recognized $11.4 million and $8.1 million as a reduction to interest expense on our interest rate swaps. The impact of SFAS No. 157 was not material to our interest rate swaps. As of June 30, 2008, the fair value of our interest rate swaps was an asset of $7.4 million.

10. Long-term debt

Long-term debt is summarized as follows:

	June 30,		December 31,
(in thousands)	2008		2007
EXCO credit agreement	$	994,000	$	560,500
EXCO Operating credit agreement	1,170,000		1,083,000
7 1/4% senior notes due 2011	444,720		444,720
Unamortized premium on 7 1/4 % senior notes due 2011	9,293		10,951
Total	$	2,618,013	$	2,099,171

Credit agreements

EXCO Resources Credit Agreement

On February 20, 2008, we entered into the first amendment to our Second Amended and Restated Credit Agreement, or, as amended to date, the EXCO Resources Credit Agreement. The primary change to the EXCO Resources Credit Agreement included an increase in the borrowing base from $0.9 billion to approximately $1.2 billion, principally to reflect the assets acquired in the Appalachian Acquisition. On July 14, 2008, we entered into the second amendment to the EXCO Resources Credit Agreement. This amendment, which was effective June 30, 2008, permitted the payment of cash dividends in connection with the exercise of any right to convert our preferred stock into common stock without compliance with certain limitations on restricted payments. In addition, the leverage ratio covenant, as defined in the agreement, was changed to provide that EXCO will not permit such ratio (i) as of the end of any fiscal quarter ending on or after June 30, 2008 and on or before December 31, 2008 to be greater than 4.00 to 1.00, (ii) as of the end of the fiscal quarter ending on March 31, 2009 to be greater than 3.75 to 1.00 and (iii) as the end of any fiscal quarter ending on or after June 30, 2009 to be greater than 3.50 to 1.00. Prior to the amendment, the leverage ratio was not permitted to be greater than 3.50 to 1.00. The other financial covenants and all other terms, including maturity date and borrowing base, contained within the EXCO Resources Credit Agreement remained unchanged. As of June 30, 2008, EXCO was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement.

At June 30, 2008 and December 31, 2007, the six month LIBOR rates were 3.1% and 4.6%, respectively, which resulted in interest rates of approximately 4.6% and 5.8%, respectively. At June 30, 2008 and December 31, 2007, we had $994.0 million and $560.5 million, respectively, of outstanding indebtedness under the EXCO Resources Credit Agreement. The next scheduled borrowing base redetermination date is October 1, 2008.

EXCO Operating credit agreement

The EXCO Operating credit agreement has a borrowing base of $1.3 billion. On July 14, 2008, EXCO Operating entered into a second amendment to the EXCO Operating credit agreement to (i) allow EXCO Operating to incur up to $500.0 million of indebtedness under an unsecured term credit agreement and (ii) exclude drawings under such unsecured term credit agreement from the consolidated current ratio, as defined in the EXCO Operating credit agreement, through December 31, 2008. The other financial covenants and all other terms, including maturity date and borrowing base contained within the EXCO Operating credit agreement remained unchanged. As of June 30, 2008, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating credit agreement.

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At June 30, 2008 and December 31, 2007, the six month LIBOR rates were 3.1% and 4.6%, respectively, which resulted in interest rates of approximately 4.9% and 6.1%, respectively. At June 30, 2008 and December 31, 2007, we had $1.2 billion and $1.1 billion, respectively, of outstanding indebtedness under the EXCO Operating credit agreement. The next scheduled borrowing base redetermination date is October 1, 2008.

7 1/4% senior notes due January 15, 2011

As of June 30, 2008 and December 31, 2007, $444.7 million and $444.7 million, respectively, in principal was outstanding on our 7 1/4% senior notes due January 15, 2011, or Senior Notes. The unamortized premium on the Senior Notes at June 30, 2008 and December 31, 2007 was $9.3 million and $11.0 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $438.6 million on June 30, 2008.

11. Operating segments

We follow SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information,” or SFAS No. 131. Identification of operating segments is based principally upon differences in the types and distribution channel of products. In prior periods, we only had operations in one industry segment, that being the oil and natural gas exploration and production industry. Beginning in the second quarter of 2008, we made a strategic shift in the focus on and allocation of resources to our midstream division. The decision to designate our midstream division as a separate business segment was due primarily to recent pipeline acquisitions and increased third party throughput resulting from capital projects specifically designed to grow this segment of our business. Our reportable segments now consist of exploration and production and midstream. Our exploration and production operational segment and midstream segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment is responsible for purchasing, gathering, transporting, processing and treating natural gas. We evaluate the performance of our operating segments based on segment profits, which includes segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and segment costs and expenses.

Summarized financial information concerning our reportable segments is shown in the following table:

	Exploration and					Intercompany			Consolidated
(in thousands)	production		Midstream			eliminations			total
For the three months ended June 30, 2008:
Total revenues	$	430,900	$	39,574		$	(12,618	)	$	457,856
Intersegment revenues	—		(12,618		)	12,618			—
Third party revenues	$	430,900	$	26,956		$	—		$	457,856

Segment profit	$	365,142	$	11,951		$	(7,819	)	$	369,274

For the three months ended June 30, 2007:
Total revenues	$	263,435	$	13,303		$	(8,092	)	$	268,646
Intersegment revenues	—		(8,092		)	8,092			—
Third party revenues	$	263,435	$	5,211		$	—		$	268,646

Segment profit	$	214,086	$	7,532		$	(6,460	)	$	215,158

For the six months ended June 30, 2008:
Total revenues	$	757,270	$	56,657		$	(21,809	)	$	792,118
Intersegment revenues	—		(21,809		)	21,809			—
Third party revenues	$	757,270	$	34,848		$	—		$	792,118

Segment profit	$	635,900	$	19,067		$	(15,070	)	$	639,897

For the six months ended June 30, 2007:
Total revenues	$	387,073	$	21,329		$	(11,572	)	$	396,830
Intersegment revenues	—		(11,572		)	11,572			—
Third party revenues	$	387,073	$	9,757		$	—		$	396,830

Segment profit	$	306,825	$	10,981		$	(8,327	)	$	309,479

As of June 30, 2008:
Total assets	$	6,504,801	$	396,785		$	—		$	6,901,586

As of December 31, 2007:
Total assets	$	5,640,034	$	315,737		$	—		$	5,955,771

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The following table reconciles the segment profits reported above to income (loss) before income taxes:

	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2008			2007			2008			2007
Segment profits	$	369,274		$	215,158		$	639,897		$	309,479
Gain (loss) on derivative financial instruments	(662,653		)	77,897			(1,003,847		)	(18,122		)
Depreciation, depletion and amortization	(111,281		)	(105,148		)	(220,498		)	(156,472		)
Accretion of discount on asset retirement obligations	(1,473		)	(1,267		)	(2,789		)	(2,210		)
General and administrative	(19,657		)	(14,990		)	(42,284		)	(29,165		)
Interest	(20,273		)	(33,543		)	(56,293		)	(110,252		)
Income (loss) before income taxes	$	(446,063	)	$	138,107		$	(685,814	)	$	(6,742	)

12. Subsequent events

Senior Unsecured Term Credit Agreement and related acquisition

On July 15, 2008, EXCO Operating entered into a senior unsecured term credit agreement, or the Term Credit Agreement, and drew $300.0 million, resulting in net proceeds of $289.4 million after transaction fees and administrative expenses. Proceeds from the Term Credit Agreement were used to acquire producing oil and natural gas properties, acreage and other assets in Gregg, Rusk and Upshur counties in Texas from private sellers for approximately $218.6 million, net of a $25.0 million deposit paid early in the second quarter of 2008 and preliminary closing adjustments, provide working capital to EXCO Operating and reduce debt on the EXCO Operating credit agreement.

The Term Credit Agreement balance of $300.0 million was borrowed in a single draw on July 15, 2008. Thereafter through October 15, 2008, EXCO Operating may request additional term loans of up to $200.0 million in the aggregate, which are available in up to four separate advances of at least $50.0 million or increments of $5.0 million in excess thereof, but the lenders have no obligation to provide the requested additional funding. The Term Credit Agreement is due and payable on December 15, 2008 and is guaranteed by all existing and future direct or indirect subsidiaries of EXCO Operating, including any guarantor of the EXCO Operating credit agreement.

Financial covenants governing the Term Credit Agreement include a minimum current ratio of 1.00 to 1.00, a maximum leverage ratio of 3.50 to 1.00 and a minimum interest coverage ratio of 2.50 to 1.00. At the borrower’s election, term loans under Term Credit Agreement may bear interest at a rate per annum equal to: (a) the Alternate Base Rate, or ABR (defined as the higher of (i) the rate of interest publicly announced by JPMorgan as its prime rate in effect at its principal office in New York City and (ii) the federal funds effective rate from time to time plus 0.50%), plus 4.75% or (b) the LIBO Rate (defined as the greater of (i) the rate at which eurodollar deposits in the London interbank market for one, two or three months, as selected by the borrower, are quoted on the Telerate screen and (ii) 3.50%), as adjusted for actual statutory reserve requirements for Eurocurrency liabilities, plus 6.00%. In the case of term loans bearing interest based upon ABR, interest is payable quarterly in arrears. In the case of terms loans bearing interest based upon the LIBO Rate, interest is payable on the last day of each relevant interest period and, in the case of any interest period longer than three months, on each successive date three months after the first day of such interest period. The Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities that are customary for agreements of this type and are substantially the same as the terms included in EXCO Operating credit agreement.

Preferred Stock conversion

On July 18, 2008, we converted all outstanding shares of our Preferred Stock into a total of approximately 105.2 million shares of our common stock. The conversion of the Preferred Stock has the effect of increasing the book value of shareholders’ equity by approximately $2.0 billion. We also paid all accrued dividends in cash totaling approximately $12.8 million to the holders of the converted shares of Preferred Stock. After July 18, 2008, dividends ceased to accrue on the Preferred Stock and all rights of the holders with respect to the Preferred Stock terminated, except for the right to receive the whole shares of common stock issuable upon conversion, accrued dividends through July 18, 2008 and cash in lieu of any fractional shares. The conversion of all outstanding shares of Preferred Stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.

13. Condensed consolidating financial statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The Senior Notes are jointly and severally guaranteed by some of our subsidiaries (referred to as

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Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of EXCO Resources, or Resources, and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. In 2007, certain subsidiaries, previously Guarantor Subsidiaries, were merged into and with Resources.

In connection with the 2007 mergers discussed above, the condensed consolidating balance sheet as of December 31, 2007 and the condensed consolidating statements of operations for the three and six months ended June 30, 2007 and condensed consolidating statements of cash flows for the six months ended June 30, 2007 have been restated to reflect the Guarantor Subsidiaries as if they had been part of Resources for all periods presented. In addition, we have adjusted the 2007 consolidating financial information to reflect our designation of a midstream business segment in the second quarter of 2008 and certain prior year amounts have been reclassified to conform to the current year presentation. All of the entities comprising our midstream segment are subsidiaries of EXCO Operating, which is a non-guarantor subsidiary. The columns designated as “Non-guarantor subsidiaries” in the accompanying condensed consolidating financial statements represent EXCO Operating and its subsidiaries. There are no other non-guarantor subsidiaries.

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

· Resources;

· the guarantor subsidiaries on a combined basis;

· the non-guarantor subsidiaries;

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

· EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the guarantor and non-guarantor subsidiaries are presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

June 30, 2008

(in thousands)	Resources				Guarantor subsidiaries				Non- guarantor subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	10,799			$	9,979			$	13,364			$	—			$	34,142
Other current assets	281,921				41,172				170,149				—				493,242
Total current assets	292,720				51,151				183,513				—				527,384
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	97,702				106,205				249,773				—				453,680
Proved developed and undeveloped oil and natural gas properties	1,316,122				1,275,576				3,075,921				—				5,667,619
Allowance for depreciation, depletion and amortization	(162,901			)	(114,290			)	(432,381			)	—				(709,572			)
Oil and natural gas properties, net	1,250,923				1,267,491				2,893,313				—				5,411,727
Gas gathering, office and field equipment, net	8,459				53,135				380,933				—				442,527
Advance on pending acquisition	25,206				—				—				—				25,206
Deferred financing costs	7,400				—				11,305				—				18,705
Derivative financial instruments	2,419				—				2,143				—				4,562
Goodwill	110,800				164,469				194,808				—				470,077
Investments in and advances to affiliates	2,174,722				—				—				(2,174,722			)	—
Other assets, net	(25,205			)	729				25,874				—				1,398
Total assets	$	3,847,444			$	1,536,975			$	3,691,889			$	(2,174,722		)	$	6,901,586

Liabilities and stockholders’ equity
Current liabilities	$		337,590		$		92,566		$		495,454		$		—		$		925,610
Long-term debt	1,448,013				—				1,170,000				—				2,618,013
Deferred income taxes	57,096				156,895				—				—				213,991
Other liabilities	225,601				95,533				189,576				—				510,710
Payable to parent	(854,118			)	875,047				(20,929			)	—				—
Commitments and contingencies	—				—				—				—				—
Preferred stock	1,992,278				—				—				—				1,992,278
Stockholders’ equity	640,984				316,934				1,857,788				(2,174,722			)	640,984
Total liabilities and stockholders’ equity	$	3,847,444			$	1,536,975			$	3,691,889			$	(2,174,722		)	$	6,901,586

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2007

(in thousands)	Resources			Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	23,069		$	7,250		$	25,191		$	—		$	55,510
Other current assets	76,261			31,601			147,928			—			255,790
Total current assets	99,330			38,851			173,119			—			311,300
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	92,680			17,142			224,981			—			334,803
Proved developed and undeveloped oil and natural gas properties	1,192,337			899,745			2,833,971			—			4,926,053
Allowance for depreciation, depletion and amortization	(112,548		)	(84,288		)	(303,657		)	—			(500,493		)
Oil and natural gas properties, net	1,172,469			832,599			2,755,295			—			4,760,363
Gas gathering, office and field equipment, net	7,449			32,665			305,294			—			345,408
Advance on pending acquisition	39,500			—			—			—			39,500
Deferred financing costs	7,619			—			12,787						20,406
Derivative financial instruments	851			—			1,640			—			2,491
Goodwill	110,800			164,469			194,808			—			470,077
Investments in and advances to affiliates	2,525,487			—			—			(2,525,487		)	—
Other assets, net	—			668			5,558			—			6,226
Total assets	$	3,963,505		$	1,069,252		$	3,448,501		$	(2,525,487	)	$	5,955,771

Liabilities and shareholders’ equity
Current liabilities	$	118,522		$	35,959		$	123,686		$	—		$	278,167
Long-term debt	1,016,171			—			1,083,000			—			2,099,171
Deferred income taxes	105,531			165,867			—			—			271,398
Other liabilities	77,189			67,197			54,629			—			199,015
Payable to parent	(461,928		)	468,607			(6,679		)	—			—
Commitments and contingencies	—			—			—			—			—
Preferred stock	1,992,278			—			—			—			1,992,278
Shareholders’ equity	1,115,742			331,622			2,193,865			(2,525,487		)	1,115,742
Total liabilities and shareholders’ equity	$	3,963,505		$	1,069,252		$	3,448,501		$	(2,525,487	)	$	5,955,771

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2008

							Non-
				Guarantor			guarantor
(in thousands)	Resources			subsidiaries			subsidiaries			Eliminations		Consolidated
Revenues and other income:
Oil and natural gas	$	120,175		$	64,731		$	243,745		$	—	$	428,651
Midstream	—			—			26,956			—		26,956
Loss on derivative financial instruments	(302,263		)	(33,362		)	(327,028		)	—		(662,653		)
Other income (loss)	7,695			(6,097		)	651			—		2,249
Equity in earnings of subsidiaries	(198,395		)	—			—			198,395		—
Total revenues and other income	(372,788		)	25,272			(55,676		)	198,395		(204,797		)

Costs and expenses:
Oil and natural gas production	19,868			9,367			32,823			—		62,058
Midstream operating expenses	—			—			22,824					22,824
Gathering and transportation	58			808			2,834			—		3,700
Depreciation, depletion and amortization	26,451			16,926			67,904			—		111,281
Accretion of discount on asset retirement obligations	419			712			342			—		1,473
General and administrative	10,657			4,460			4,540			—		19,657
Interest	12,194			—			8,079			—		20,273
Total costs and expenses	69,647			32,273			139,346			—		241,266
Income (loss) before income taxes	(442,435		)	(7,001		)	(195,022		)	198,395		(446,063		)
Income tax expense	(179,521		)	(3,628		)	—			—		(183,149		)
Net income (loss)	(262,914		)	(3,373		)	(195,022		)	198,395		(262,914		)
Preferred stock dividends	(35,000		)	—			—			—		(35,000		)
Net income (loss) available to common shareholders	$	(297,914	)	$	(3,373	)	$	(195,022	)	$	198,395	$	(297,914	)

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2008

							Non-
				Guarantor			guarantor
(in thousands)	Resources			subsidiaries			subsidiaries			Eliminations		Consolidated
Revenues and other income:
Oil and natural gas	$	219,964		$	109,346		$	424,284		$	—	$	753,594
Midstream	—			—			34,848			—		34,848
Loss on derivative financial instruments	(413,750		)	(59,934		)	(530,163		)	—		(1,003,847		)
Other income (loss)	15,137			(12,648		)	1,187			—		3,676
Equity in earnings of subsidiaries	(350,765		)	—			—			350,765		—
Total revenues and other income	(529,414		)	36,764			(69,844		)	350,765		(211,729		)

Costs and expenses:
Oil and natural gas production	38,109			17,180			59,250			—		114,539
Midstream operating expenses	—			—			30,851					30,851
Gathering and transportation	117			1,414			5,300			—		6,831
Depreciation, depletion and amortization	51,537			32,110			136,851			—		220,498
Accretion of discount on asset retirement obligations	815			1,291			683			—		2,789
General and administrative	24,855			8,429			9,000			—		42,284
Interest	31,995			—			24,298			—		56,293
Total costs and expenses	147,428			60,424			266,233			—		474,085
Income (loss) before income taxes	(676,842		)	(23,660		)	(336,077		)	350,765		(685,814		)
Income tax expense	(251,089		)	(8,972		)	—			—		(260,061		)
Net income (loss)	(425,753		)	(14,688		)	(336,077		)	350,765		(425,753		)
Preferred stock dividends	(70,000		)	—			—			—		(70,000		)
Net income (loss) available to common shareholders	$	(495,753	)	$	(14,688	)	$	(336,077	)	$	350,765	$	(495,753	)

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2007

							Non-
				Guarantor			guarantor
(in thousands)	Resources			subsidiaries			subsidiaries		Eliminations			Consolidated
Revenues and other income:
Oil and natural gas	$	58,037		$	32,756		$	170,759	$	—		$	261,552
Midstream	—			—			5,211		—			5,211
Loss on derivative financial instruments	14,795			8,165			54,937		—			77,897
Other income (loss)	8,475			(7,251		)	659		—			1,883
Equity in earnings of subsidiaries	98,315			—			—		(98,315		)	—
Total revenues and other income	179,622			33,670			231,566		(98,315		)	346,543

Costs and expenses:
Oil and natural gas production	12,726			5,972			28,348		—			47,046
Midstream operating expenses	—			—			4,139		—			4,139
Gathering and transportation	159			434			1,710		—			2,303
Depreciation, depletion and amortization	13,938			10,473			80,737		—			105,148
Accretion of discount on asset retirement obligations	387			480			400		—			1,267
General and administrative	8,130			2,293			4,567		—			14,990
Interest	12,847			—			20,696		—			33,543
Total costs and expenses	48,187			19,652			140,597		—			208,436
Income (loss) before income taxes	131,435			14,018			90,969		(98,315		)	138,107
Income tax expense	48,549			6,672			—		—			55,221
Net income (loss)	82,886			7,346			90,969		(98,315		)	82,886
Preferred stock dividends	(51,099		)	—			—		—			(51,099		)
Net income (loss) available to common shareholders	$	31,787		$	7,346		$	90,969	$	(98,315	)	$	31,787

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2007

							Non-
				Guarantor			guarantor
(in thousands)	Resources			subsidiaries			subsidiaries			Eliminations		Consolidated
Revenues and other income:
Oil and natural gas	$	86,964		$	62,056		$	232,891		$	—	$	381,911
Midstream	—			—			9,757			—		9,757
Gain (loss) on derivative financial instruments	1,207			(14,505		)	(4,824		)	—		(18,122		)
Other income (loss)	18,213			(14,639		)	1,588			—		5,162
Equity in earnings of subsidiaries	(19,629		)	—			—			19,629		—
Total revenues and other income	86,755			32,912			239,412			19,629		378,708

Costs and expenses:
Oil and natural gas production	19,429			11,425			46,119			—		76,973
Midstream operating expenses	—			—			7,103					7,103
Gathering and transportation	304			572			2,399			—		3,275
Depreciation, depletion and amortization	26,080			20,371			110,021			—		156,472
Accretion of discount on asset retirement obligations	635			954			621			—		2,210
General and administrative	15,163			5,333			8,669			—		29,165
Interest	29,549			—			80,703			—		110,252
Total costs and expenses	91,160			38,655			255,635			—		385,450
Income (loss) before income taxes	(4,405		)	(5,743		)	(16,223		)	19,629		(6,742		)
Income tax expense (benefit)	406			(2,337		)	—			—		(1,931		)
Net income (loss)	(4,811		)	(3,406		)	(16,223		)	19,629		(4,811		)
Preferred stock dividends	(52,235		)	—			—			—		(52,235		)
Net loss available to common shareholders	$	(57,046	)	$	(3,406	)	$	(16,223	)	$	19,629	$	(57,046	)

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2008

(in thousands)	Resources			Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	138,381		$	61,773		$	312,080		$	—	$	512,234
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(494,608		)	(75,396		)	(340,481		)	—		(910,485		)
Proceeds from dispositions of property and equipment	1,287			95			150			—		1,532
Advance on pending acquisition	—			—			(25,205		)	—		(25,205		)
Advances/investments with affiliates	(1,479		)	16,258			(14,779		)	—		—
Net cash used in investing activities	(494,800		)	(59,043		)	(380,315		)	—		(934,158		)
Financing Activities:
Borrowings under credit agreements	635,000			—			177,200			—		812,200
Repayments under credit agreements	(201,500		)	—			(90,200		)	—		(291,700		)
Settlements of derivative financial instruments with a financing element	(31,532		)	—			(30,567		)	—		(62,099		)
Proceeds from issuance of common stock	12,929			—			—			—		12,929
Payment of preferred stock dividends	(70,000		)	—			—			—		(70,000		)
Deferred financing costs and other	(749		)	—			(25		)	—		(774		)
Net cash provided by financing activities	344,148			—			56,408			—		400,556
Net increase (decrease) in cash	(12,271		)	2,730			(11,827		)	—		(21,368		)
Cash at beginning of the period	23,069			7,250			25,191			—		55,510
Cash at end of period	$	10,798		$	9,980		$	13,364		$	—	$	34,142

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2007

(in thousands)	Resources			Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	33,521		$	32,540		$	103,065		$	—	$	169,126
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(791,987		)	(21,123		)	(1,540,597		)	—		(2,353,707		)
Proceeds from dispositions of property and equipment	374,008			—			2,033			—		376,041
Advance on pending sale	5,000			—			—			—		5,000
Advances/investments with affiliates	(1,661,810		)	(6,200		)	1,668,010			—		—
Net cash provided by (used in) investing activities	(2,074,789		)	(27,323		)	129,446			—		(1,972,666		)
Financing Activities:
Borrowings under credit agreements	758,000			—			1,170,000			—		1,928,000
Repayments under credit agreements	(653,000		)	—			(1,370,532		)	—		(2,023,532		)
Settlement of derivative financial instrument with a financing element	(1,041		)	—			(2,637		)	—		(3,678		)
Proceeds from issuance of common stock	2,228			—			—			—		2,228
Proceeds from issuance of preferred stock	2,000,000			—			—			—		2,000,000
Payments for preferred stock issuance costs	(7,498		)	—			—			—		(7,498		)
Payment of preferred stock dividends	(43,717		)	—			—			—		(43,717		)
Deferred financing costs and other	(7,989		)	—			(9,815		)	—		(17,804		)
Net cash provided by (used in) financing activities	2,046,983			—			(212,984		)	—		1,833,999
Net increase in cash	5,715			5,217			19,527			—		30,459
Cash at the beginning of the period	6,522			6,233			10,067			—		22,822
Cash at end of period	$	12,237		$	11,450		$	29,594		$	—	$	53,281

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

Forward-looking statements

This quarterly report contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

· our future financial and operating performance and results;

· our business strategy;

· market prices;

· our future derivative financial instrument activities; and

· our plans and forecasts.

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

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

· fluctuations in prices of oil and natural gas;

· imports of foreign oil and natural gas, including liquefied natural gas;

· future capital requirements and availability of financing;

· estimates of reserves and economic assumptions used in connection with our acquisitions;

· geological concentration of our reserves;

· risks associated with drilling and operating wells;

· exploratory risks, including our Marcellus and Huron shale plays in Appalachia and the Haynesville/Bossier shale play in East Texas/North Louisiana;

· risks associated with the operation of natural gas pipelines and gathering systems;

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

· cash flow and liquidity;

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

· availability of drilling and production equipment;

· marketing of oil and natural gas;

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

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· title to our properties;

· litigation;

· competition;

· general economic conditions, including costs associated with drilling and operations of our properties;

· governmental regulations;

· receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;

· deciding whether or not to enter into derivative financial instruments;

· events similar to those of September 11, 2001;

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

· fluctuations in interest rates; and

· our ability to effectively integrate companies and properties that we acquire.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. We expect to continue to grow by leveraging our management team’s experience, exploiting our multi-year inventory of development drilling locations and exploitation projects, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt and equity along with a comprehensive derivative financial instrument program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our return on investments, and manage our capital structure.

Oil and natural gas prices have been volatile. Significant factors that will impact near-term commodity prices include political developments in Iraq, Iran and other oil producing countries, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators. A substantial portion of our estimated production is currently covered by derivative financial instruments through 2009, and we have adopted a commodity price risk management program under which we intend to enter into additional derivative financial instruments that will cover substantial percentages of our estimated production to mitigate the impact of price volatility on our oil and natural gas reserves.

The increases in commodity prices in recent years has resulted in increased drilling activity and demand for drilling, oil country tubular goods and operating services and equipment in our operating areas. In addition, the costs of leasing acreage in our East Texas/North Louisiana and Appalachia operating areas have increased significantly during the past year.

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Competition for this acreage is increasing and demands from land owners for higher royalties or other forms of compensation is also increasing. Due to the expected continued favorable commodity price environment and related demand pressures, we anticipate drilling, service and labor costs, as well as costs of equipment and raw materials, to remain at or exceed the levels experienced in 2007.

Our 2008 capital expenditure budget totals $943.0 million and includes $905.0 million for drilling, exploitation, leasing and production operations, $19.0 million for midstream projects and $19.0 million for corporate projects. The increase in our exploration and production segment’s operations capital expenditure budget reflects expected significant acreage acquisitions and drilling in the Haynesville/Bossier shales in East Texas and North Louisiana and the Marcellus and Huron shales in Appalachia. In addition, we supplemented our development drilling budget for our February 2008 acquisition of shallow producing and undeveloped oil and natural gas properties from EOG Resources, Inc., or the Appalachian Acquisition. We do not budget for acquisitions as these transactions are opportunistic in nature. Our future earnings and cash flows are dependent upon our ability to manage our overall cost structure to a level that allows for profitable production.

Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to develop and identify additional reserves and by acquisitions. Our future growth will depend upon our ability to continue to add oil and natural gas reserves in excess of production at a reasonable cost. We will maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

On February 20, 2008, we acquired oil and natural gas properties including approximately 2,500 producing wells, 2,000 shallow undrilled locations and 16 Mmcfe/d of net production in the Appalachian Acquisition. The purchase price, after preliminary closing adjustments of $7.4 million, was $388.4 million and was financed with the EXCO Resources credit agreement.

On March 11, 2008, we acquired a gathering system in East Texas, or the New Waskom Acquisition, for approximately $55.6 million, net of preliminary purchase price adjustments.

On July 15, 2008, we acquired producing oil and natural gas properties, acreage and other assets in Gregg, Rusk and Upshur counties of Texas for approximately $243.6 million, net of preliminary closing adjustments. Funding for this acquisition was provided by a senior unsecured term loan, which matures on December 15, 2008. The assets include producing properties with approximately 12 Mmcfe per day on stabilized net production from 83 producing wells and approximately 11,000 gross acres. Also included in the assets is a 50 mile gathering system with compressors, a dehydration unit and a refrigeration plant. We estimate there are over 500 drilling locations in the Cotton Valley and Travis Peak formations, of which 92 are proved.

We continue to face the challenge of financing future acquisitions. In connection with our 2007 and 2008 acquisitions, we amended our credit agreements in February 2008 to increase our borrowing capacity to an aggregate of approximately $2.5 billion. On July 14, 2008, we revised certain covenant provisions and amended our credit agreements to allow for up to $500.0 million of senior unsecured term loans. The credit agreement of our wholly-owned unrestricted subsidiary, EXCO Operating Company, LP, or EXCO Operating (formerly EXCO Partners Operating Partnership, LP), which holds all of our assets located in East Texas/North Louisiana, or the EXCO Operating Credit Agreement, as amended on July 14, 2008, provides for an aggregate borrowing base of $1.3 billion, of which approximately $1.2 billion and $1.1 billion was drawn as of June 30, 2008 and August 1, 2008, respectively. The EXCO Resources credit agreement as amended on July 14, 2008, but effective on June 30, 2008 has a borrowing base of approximately $1.2 billion, of which approximately $994.0 million and $1.1 billion was drawn as of June 30, 2008 and August 1, 2008, respectively. With these credit agreements, we believe our unused borrowing capacity as of August 1, 2008 of approximately $255.6 million will be sufficient to meet our commitments. Funding for future acquisitions may require additional sources of financing, which may not be available.

Critical accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, proved reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2007.

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We adopted Financial Accounting Standards Board, or FASB, Statement of Financial Accounting Standards, or SFAS, No. 157, “Fair Value Measurements,” or SFAS No. 157 on January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and provides for expanded disclosure of information about fair value measurements. Beginning with the first quarter of 2008, we revised our computations of the fair value of our derivative financial instruments related to oil and natural gas sales to reflect the requirements outlined in SFAS No. 157. As the impact of SFAS No. 157 affects only our non-cash mark-to-market activities, we do not consider the adoption of the statement to be material to our results of operations or resources and liquidity.

Recent accounting pronouncements

In September 2006, FASB, issued SFAS, No. 157 which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years for financial instruments. FASB Financial Staff Position No. FAS 157-2 deferred implementation for other non-financial assets and liabilities for one year. Examples of non-financial assets and liabilities are asset retirement obligations and non-financial assets and liabilities initially measured at fair value in a business combination. We adopted SFAS No. 157 on January 1, 2008.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be adopted by us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 161 on our financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” or SFAS No. 162. SFAS No. 162 identifies the sources of accounting principles and the frame work for selecting the principles to be used in the preparation of financial statements. We do not expect SFAS No. 162 to have an impact on our financial statements.

Our results of operations

A summary of key financial data for the three and six months ended June 30, 2008 and 2007 related to our results of operations is presented below:

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	Three months ended June 30,						Quarter change			Six months ended June 30,						Year change
(dollars in thousands, except prices and per unit expenses)	2008			2007			2008 - 2007			2008			2007			2008 - 2007
Production:
Oil (Mbbls)	545			426			119			1,053			701			352
Natural gas (Mmcf)	32,621			32,320			301			64,670			47,983			16,687
Total production (Mmcfe)	35,891			34,876			1,015			70,988			52,189			18,799

Oil and natural gas revenues before derivative financial instrument activities:
Oil revenues	$	65,982		$	26,057		$	39,925		$	114,998		$	41,162		$	73,836
Natural gas sales	362,669			235,495			127,174			638,596			340,749			297,847
Total oil and natural gas sales	$	428,651		$	261,552		$	167,099		$	753,594		$	381,911		$	371,683

Midstream operations:
Midstream revenues (before intercompany eliminations)	$	39,574		$	13,303		$	26,271		$	56,657		$	21,329		$	35,328
Midstream operating expenses (before intercompany eliminations)	27,623			5,771			21,852			37,590			10,348			27,242
Midstream operating profit (before intercompany eliminations)	11,951			7,532			4,419			19,067			10,981			8,086
Intercompany eliminations	(7,819		)	(6,460		)	(1,359		)	(15,070		)	(8,327		)	(6,743		)
Midstream operating profit (after intercompany eliminations)	$	4,132		$	1,072		$	3,060		$	3,997		$	2,654		$	1,343

Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	(90,380	)	$	6,630		$	(97,010	)	$	(87,364	)	$	38,702		$	(126,066	)
Non-cash change in fair value of derivative financial instruments	(572,273		)	71,267			(643,540		)	(916,483		)	(56,824		)	(859,659		)
Total derivative financial instrument activities	$	(662,653	)	$	77,897		$	(740,550	)	$	(1,003,847	)	$	(18,122	)	$	(985,725	)

Average sales price (before cash settlements of derivative financial instruments):
Oil (Bbl)	$	121.07		$	61.17		$	59.90		$	109.21		$	58.72		$	50.49
Natural gas (per Mcf)	11.12			7.29			3.83			9.87			7.10			2.77
Natural gas equivalent (per Mcfe)	11.94			7.50			4.44			10.62			7.32			3.30

Oil and natural gas production costs:
Oil and natural gas operating costs	$	40,625		$	30,047		$	10,578		$	73,796		$	51,598		$	22,198
Gathering and transportation	3,700			2,303			1,397			6,831			3,275			3,556
Production and ad valorem taxes	21,433			16,999			4,434			40,743			25,375			15,368
Depletion	105,166			100,788			4,378			209,079			149,204			59,875
Depreciation and amortization	6,115			4,360			1,755			11,419			7,268			4,151
General and administrative	19,657			14,990			4,667			42,284			29,165			13,119
Interest expense, including impacts of interest rate swaps	20,273			33,543			(13,270		)	56,293			110,252			(53,959		)

Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs	$	1.13		$	0.86		$	0.27		$	1.04		$	0.99		$	0.05
Gathering and transportation	0.10			0.07			0.03			0.10			0.06			0.04
Production and ad valorem taxes	0.60			0.49			0.11			0.57			0.49			0.08
Depletion	2.93			2.89			0.04			2.95			2.86			0.09
Depreciation and amortization	0.17			0.13			0.04			0.16			0.14			0.02
General and administrative	0.55			0.43			0.12			0.60			0.56			0.04

Net income (loss)	$	(262,914	)	$	82,886		$	(180,028	)	$	(425,753	)	$	(4,811	)	$	(420,942	)

The following is a discussion of our financial condition and results of operations for the three and six months ended June 30, 2008 and 2007.

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

· properties acquired in the Vernon Field of Louisiana, or the Vernon Acquisition, on March 30, 2007, properties acquired in the Mid-Continent region in May 2007, or the Southern Gas Acquisition, the additional 45% interest acquired in the Canyon Sand field in West Texas on October 9, 2007, or the Canyon Sand Acquisition, and the Appalachian Acquisition in February 2008;

· dispositions of oil and natural gas properties, primarily the sale of our non-operating interests in the Cement Field in Oklahoma in July 2007;

· significant changes in the amount of our long-term debt and the issuance of $2.0 billion of preferred stock related to our acquisition efforts;

· changes in proved reserves and their impact on depletion; and

· fluctuations in oil and natural gas prices which impact our oil and natural gas reserves, revenues, net income or loss and ceiling test results and the mark-to-market accounting used for our derivative financial instruments gains or losses.

General

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

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· the level of domestic production and economic activity;

· 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 oil and natural gas from any producing well in which we have or may acquire an interest.

Marketing arrangements

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

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

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

We may not be able to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may not be able to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas 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.

Summary

For the three months ended June 30, 2008, we reported a net loss available to common shareholders of $297.9 million, compared to a net income available to common shareholders of $31.8 million for the quarter ended June 30, 2007. For the six months ended June 30, 2008, we reported a net loss available to common shareholder of $495.8 million, compared to a net loss available to common shareholders of $57.0 million for the six months ended June 30, 2007.

The impact of our Appalachian Acquisition in 2008 and the Vernon Acquisition, the Southern Gas Acquisition and other acquisitions in 2007 increased our production, revenues, operating expenses and also general and administrative expenses when compared to the prior year. Derivative financial instruments have a significant impact both on our revenues

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and on our results of operations, since we do not designate our derivative financial instruments as hedges and are required to mark the non-cash changes in the fair value of our derivatives to market at the end of each reporting period. As further discussed below, this can cause our reported oil and natural gas revenues, total revenue and net income to decline, as was the case in the first half of 2008, or increase significantly when oil and natural gas prices experience significant decreases.

Total revenues

Our revenues are comprised of sales of oil and natural gas, revenues from our midstream operations, cash settlements and changes in the fair value of our derivative financial instruments and other income. Our total revenues for the six months ended June 30, 2008 and 2007 were a negative $211.7 million and a positive $378.7 million, respectively. Excluding the impact of derivative financial instruments, our total revenues for the six month-periods would have been $792.1 million and $396.8 million, respectively. The significant increases in the prices of oil and natural gas during the first two quarters of 2008 compared with 2007 and changes in the fair value of our derivative financial instruments resulted in negative revenue adjustments of $1.0 billion and $18.1 million for the six months ended June 30, 2008 and 2007, respectively.

Total revenues for the three months ended June 30, 2008 and 2007 were negative $204.8 million and positive $346.5 million, respectively. Excluding the impact on revenues from derivative financial instruments, total revenues for such three-month periods would have been $457.9 million and $268.6 million. The negative revenue adjustment due to changes in the fair value of the derivative financial instruments was $662.7 million for the three months ended June 30, 2008 and a positive $77.9 million for the comparable period for 2007.

Oil and natural gas revenues, production and prices

For the three months ended June 30, 2008, total oil and natural gas revenues, excluding the impact of derivative financial instruments, were $428.7 million, a 63.9% increase over the three months ended June 30, 2007 total oil and natural gas revenues of $261.6 million. Total equivalent production volumes were 35.9 Bcfe for the three months ended June 30, 2008, a 2.9% increase over the prior year’s comparable period production of 34.9 Bcfe. Increased volumes attributable to the Southern Gas Acquisition in May 2007, the Canyon Sand Acquisition in November 2007 and the Appalachian Acquisition in February 2008 were partially offset by normal production declines, particularly in the Vernon field where production declined by approximately 3.0 Bcfe from the prior year’s comparable quarter, and reduced volumes of approximately 0.8 Bcfe arising from the sale of our Cement Field in Oklahoma in July 2007. While the decline of 3.0 Bcfe from our Vernon field for the three months ended June 30, 2008 compared to the prior year’s period is offsetting other production increases, we have been successful in mitigating production decline which has resulted in our current production rate from the Vernon field exceeding our original expectations.

For the six months ended June 30, 2008, total oil and natural gas revenues, excluding the impact of derivative financial instruments, were $753.6 million, a 97.3% increase over the six months ended June 30, 2007 total oil and natural gas revenues of $381.9 million. Total equivalent production volumes were 71.0 Bcfe for the six months ended June 30, 2008, a 36.0% increase over the prior year’s comparable period production of 52.2 Bcfe. The increased volumes are primarily attributable to the Vernon Acquisition and the Southern Gas Acquisition, with a smaller contribution from the Canyon Sand Acquisition and the Appalachian Acquisition. The increased volumes from development drilling activities and acquisitions were partially offset by property sales of our Cement field and other divestitures. The increase in production volumes for the six months ended June 30, 2008 compared to the same period in 2007 is presented below:

· the Vernon Acquisition which closed on March 30, 2007, produced 22.6 Bcfe for the six months ended June 30, 2008 compared with 14.2 Bcfe in the prior year period, an increase of 8.4 Bcfe;

· the Southern Gas Acquisition which closed on May 2, 2007, contributed an increase of 5.7 Bcfe for the six months ended June 30, 2008;

· increased volumes of 2.5 Bcfe from our Canyon Sand Acquisition;

· the Appalachian Acquisition on February 20, 2008, which increased production by 1.9 Bcfe in our Appalachian region.

These increases were partially offset by reduced volumes relating to normal declines and sales of producing properties during 2007, particularly from the Cement Field in Oklahoma, which had net production of 1.4 Bcfe during the six months ended June 30, 2007.

The average sales price per Bbl, excluding the impact of derivative financial instruments, increased for oil during the six months ended June 30, 2008 compared to the six months ended June 30, 2007 from $58.72 per Bbl to $109.21 per Bbl, or

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86.0%. The average natural gas sales price, excluding the impact of derivative financial instruments, was $9.87 per Mcf, an increase of 39.0% for the six months ended June 30, 2008 compared with $7.10 per Mcf for the six months ended June 30, 2007.

Midstream revenues

Our Midstream assets are principally comprised of gathering systems and an intrastate pipeline system. The principle assets are discussed below:

· TGG Pipeline, or TGG, is a 53-mile intrastate pipeline. TGG has access to 12 markets for natural gas and transports natural gas for third-party producers. The current transported volumes are approximately 130 Mmcf per day, of which approximately 20% is natural gas delivered from our exploration and production operating segment. Currently, we are expanding our TGG Pipeline in East Texas, adding 57 miles of pipeline to the original TGG system at a cost of approximately $37.6 million. As of June 30, 2008, approximately 20 miles of the 57 miles of this expansion is available for service. Upon completion of this expansion, which we expect to become fully operational in the second half of 2008, TGG will have 110 miles of pipeline and add an incremental throughput of 100 Mmcf per day without compression. With compression, incremental throughput volumes could exceed 200 Mmcf per day.

· our Talco midstream gathering system, or Talco, is a network of six natural gas gathering systems comprised of approximately 300 miles of pipeline, gathers natural gas produced from the Holly/Caspiana, Longwood/Waskom fields and other fields in East Texas and North Louisiana. The assets of Talco include the New Waskom Acquisition. Average throughput in Talco, including the New Waskom Acquisition volumes is approximately 200 Mmcf per day, of which approximately 57% is natural gas produced by our exploration and production operating segment.

· a gathering system and treating facility in the area of our Vernon field operations, or Vernon Gathering. This system gathers and transports gas from our Vernon field and, to a lesser extent, gas from third-party producers. The gathering system transports natural gas to our Caney Lake treating facility where the natural gas is sweetened and delivered to interstate pipeline systems. Average throughput in Vernon Gathering is approximately 170 Mmcf per day, of which 98% was natural gas produced by our exploration and production operating segment.

We evaluate our midstream operations as if they were a stand alone operation. Accordingly, the results of operations discussed below are prior to intercompany eliminations.

For the three months ended June 30, 2008, midstream revenues, were $39.6 million, a 198% increase over the three months ended June 30, 2007 midstream revenues of $13.3 million. Increases in the sales of natural gas purchased from third-party producers and then resold account for 83.5% of the increase in the midstream revenues and are primarily attributable to the New Waskom Acquisition. This asset, which was not in our portfolio in 2007, has several contracts whereby we purchase and resell natural gas produced by third-parties. The remaining increase in revenues was attributable to increases in drip sales and gathering fees associated with the New Waskom Acquisition, as well as increased throughput on our midstream assets.

For the six months ended June 30, 2008, midstream revenues were $56.7 million, a 166% increase over the six months ended June 30, 2007 midstream revenues of $21.3 million. Increases in the sales of natural gas purchased from third-party producers and then resold account for 67.8% of the increase in midstream revenues and are primarily attributable to the New Waskom Acquisition as discussed above. The remaining 32.2% of the increase in revenues is attributable to increases in drip sales and gathering fees associated with the New Waskom Acquisition, as well as increased throughput on our midstream assets.

Derivative financial instruments

We use oil and natural gas derivatives and financial risk management instruments to manage our exposures to commodity price and interest rate fluctuations. We do not designate these instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instrument’s fair value currently in earnings, as a gain or loss on oil and natural gas derivatives and as interest expense on financial risk management instruments. When oil and natural gas prices increase significantly, as they did during the first six months of 2008, the impact of such increases result in decreases in reported revenues and results of operations. Conversely, when oil and natural gas prices decrease, our

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revenues and results of operations can increase significantly.

A significant portion of the revenue and net earnings impact of our derivative financial instruments relates to non-cash mark-to-market adjustments, which do not affect our cash flows, capital resources or liquidity. The non-cash portion of the impact on revenues and results of operations of derivative financial instruments was negative $572.3 million and negative $916.5 million, respectively, for the three and six months ended June 30, 2008. For the three and six months ended June 30, 2007, the non-cash impact of derivatives was a positive $71.3 million and negative $56.8 million, respectively.

We expect that our revenues will continue to be significantly impacted in future periods by changes in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices. In addition, prices for oil and natural gas have been increasing during 2008 and in the upcoming months we expect our cash settlements on our derivatives to decrease revenues as a result of increases in oil and natural gas prices that have occurred during the second quarter of 2008. For the remainder of 2008, approximately 78.0% of our expected production volumes are subject to oil and natural gas derivative contracts. In addition to our oil and natural gas derivative financial instruments, we entered into interest rate swaps in February 2008. The impact of these derivative financial instruments are presented on the following table:

	Three months ended					Six months ended
	June 30,					June 30,
(in thousands)	2008			2007		2008			2007
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	(90,380	)	$	6,630	$	(87,364	)	$	38,702
Non-cash change in fair value of derivative financial instruments	(572,273		)	71,267		(916,483		)	(56,824		)
Total oil and natural gas derivative loss on financial instruments	$	(662,653	)	$	77,897	$	(1,003,847	)	$	(18,122	)

Interest rate swaps:
Interest rate swaps settlement receipts	$	383		$	—	$	761		$	—
Fair market value adjustment on interest rate swaps	11,001			—		7,370			—
Total interest rate swaps	$	11,384		$	—	$	8,131		$	—

Other income

Other income consists of interest earned on our cash balances, miscellaneous gathering income which is not designated as a component of our midstream segment and income or losses resulting from periodic re-evaluation from natural gas imbalances. Our other income increased to $2.2 million for the three months ended June 30, 2008 from $1.9 million for the same period in the prior year. For the six months ended June 30, 2008, our other income decreased to $3.7 million compared with $5.2 million in the same period in 2007. The decrease in other income for the six months ended June 30, 2008 compared to the same period in 2007 is related to slightly lower than average cash balances and lower interest rates on our invested cash.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and six months ended June 30, 2008 were $40.6 million and $73.8 million, respectively, and represent increases of $10.6 million and $22.2 million, respectively, or 35.2% and 43%, from the same periods in 2007. The increase in oil and natural gas operating costs for the six months ended June 30, 2008, was primarily attributable to:

· the Vernon Acquisition, which closed on March 30, 2007 and added direct production expenses of $7.6 million for the six months ended June 30, 2008 when compared to the same period in 2007;

· the Southern Gas Acquisition, which closed on May 2, 2007 and added $6.5 million of production expenses for the six months ended June 30, 2008;

· the Appalachian Acquisition on February 20, 2008, added $2.1 million of production expenses for the six months ended June 30, 2008;

· increased direct production expenses of approximately $2.1 million in our Sugg Ranch area primarily due to the acquisition of incremental working interests in that area and incremental operating costs resulting from our development of this field;

· increases of $1.4 million of non-cash stock-based compensation expenses;

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· a general increase in the cost of goods and services used in our oil and natural gas operations, most notably motor fuel and utility costs during the second quarter of 2008; and

· increases from new well additions through our development and exploitation capital program.

The oil and natural gas operating costs per unit increased to $1.04 per Mcfe for the six months ended June 30, 2008 from $0.99 per Mcfe, or 5.1%, for the six months ended June 30, 2007. This increase is attributable to the aforementioned increases in motor fuel, utilities, the general increase in the costs of goods and services used in our operations and an increase in workover activities.

Midstream operating expenses

Our midstream operating expenses for the three and six months ended June 30, 2008 increased $21.9 million and $27.2 million, respectively, or 378.7% and 263.2%, respectively, from the same periods in 2007. The increase in midstream operating expenses for the six months ended June 30, 2008 were primarily attributable to:

· increased cost of purchased gas of approximately $21.6 million due primarily to purchased natural gas for resale from our March 2008 New Waskom Acquisition; and

· increased operating expenses of approximately $4.9 million related to the March 2008 New Waskom Acquisition and increased Vernon Gathering operating expenses due to 2008 containing six months of operating costs and 2007 containing only three months of operating costs.

Gathering and transportation

We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments, contain revenues which are reported under two separate bases. Gathering and transportation expenses totaled $3.7 million and $6.8 million for the three and six months ended June 30, 2008, respectively, compared to $2.3 million and $3.3 million for the three and six months ended June 30, 2007, respectively. As our marketing efforts expand, we expect our gathering and transportation expenses will also increase.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended June 30, 2008 increased by $4.4 million, or 26.1%, over the same period in 2007. Production and ad valorem taxes for the six months ended June 30, 2008 increased by $15.4 million, or 60.6%, over the same period in 2007. These increases are primarily attributable to higher oil and natural gas volumes and prices resulting from acquisitions and our development drilling. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 5.0% and 5.4% of gross oil and natural gas sales for the three and six months ended June 30, 2008, compared with 6.5% and 6.6 % during the same periods in the prior year. The decrease in the overall tax rate is primarily the result of a statutory severance tax rate reduction in the state of Louisiana, which lowered the rate from $0.37 per Mcf for 2007 to $0.27 per Mcf for 2008. The lower severance tax rate in Louisiana contributed to our consolidated decreased severance tax rate in 2008 when measured as a percentage of revenue due to a significant increase in Louisiana production volume resulting from the Vernon Acquisition and development drilling in North Louisiana. Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. Further, ad valorem taxes in Texas and other states are based partially on the value of oil and natural gas reserves, which have increased significantly since the beginning of 2007 due to acquisitions. These taxes are generally based upon the price received for production.

Depletion

Our depletion expense for the three and six months ended June 30, 2008 increased by $4.4 million and $59.9 million, or 4.3% and 40.1%, from the same periods in 2007. The primary reason for the increases were from increases in equivalent oil and natural gas sales volumes for the three months and six months ended June 30, 2008 of 2.9% and 36.0%, respectively. This

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increase in equivalent sales volumes for the six months ended June 30, 2008 compared with the six months ended June 30, 2007 is largely due to the Vernon Acquisition, the Southern Gas Acquisition, the Appalachian Acquisition and the Canyon Sand Acquisition. These acquisitions also increased our per unit depletion rate from $2.89 and $2.86 per Mcfe for the three and six months ended June 30, 2007 to $2.93 and $2.95 per Mcfe for the three and six months ended June 30, 2008.

Depreciation and amortization

Our depreciation and amortization costs for the three and six months ended June 30, 2008 increased by $1.8 million and $4.2 million, or 40.3% and 57.1%, from the same periods in 2007. The primary reasons for the increases were from the increases in our depreciable asset base for the three and six months ended June 30, 2008, which was directly related to our 2007 acquisition of Vernon gathering assets and the March 2008 New Waskom Acquisition gathering assets.

General and administrative

Our general and administrative costs for the three months ended June 30, 2008 were $19.6 million, or $0.55 per Mcfe compared to $15.0 million, or $0.43 per Mmcfe for the same period in 2007. Our general and administrative costs for the six months ended June 30, 2008 were $42.3 million, or $0.60 per Mcfe, compared to $29.2 million, or $0.56 per Mcfe, for the same period in 2007, an increase of $13.1 million, or 45.0%. Significant components of the increase for the six months ended June 30, 2008, include the following items:

· increased personnel costs of $11.1 million due to additional headcount of 176 employees related primarily to our acquisitions and expanding our technical and managerial staff to fully exploit our asset base;

· an increase in share-based compensation costs of $0.9 million due primarily to additional headcount;

· increased consulting and contract labor costs of $1.2 million due primarily to acquisitions and information technology-related support;

· increased information technology related costs of $1.3 million primarily due to the information technology requirements attributable to our increased headcount;

· increased legal fees of $2.5 million including $3.7 million attributable to a write-off of our proposed master limited partnership offering, which was withdrawn in January 2008. The increase associated with this write-off was partially offset by lower external legal fees of approximately $1.0 million during the six months ended June 30, 2008 when compared with the prior year;

· increased occupancy costs of $0.4 million resulting from expansion of corporate facilities;

· increased franchise tax of $1.1 million due to changes in the jurisdictional make-up of our properties; and

· other expenses related to the overall growth of our business.

Partially offsetting the above increases in general and administrative costs were increased operator overhead recoveries of $11.7 million for the six months ended June 30, 2008, a $4.2 million increase from the same period in the prior year. Additionally, we capitalized approximately $4.6 million in salary costs to our full cost pool, which was $2.3 million higher than the amount capitalized in the same period in 2007. These increases from the same period in the prior year are the result of the increased personnel, primarily attributable to the acquisitions in 2007 and 2008.

The following table presents the components of our general and administrative expenses:

	For the three months ended						For the six months ended
	June 30,						June 30,
(in thousands)	2008			2007			2008			2007
Gross general and administrative expenses	$	28,045		$	20,933		$	58,566		$	38,981
Capitalized general and administrative expenses	(2,362		)	(1,353		)	(4,581		)	(2,319		)
Reimbursed general and administrative expenses	(6,026		)	(4,590		)	(11,701		)	(7,497		)
Net general and administrative expenses	$	19,657		$	14,990		$	42,284		$	29,165

Interest expense

Our interest expense for the three and six months ended June 30, 2008 decreased $13.3 million and $54.0 million

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from the same periods in 2007. The decrease is primarily due to $32.1 million of interest-related charges taken in the first quarter of 2007 associated with the amendment of the EXCO Operating Credit Agreement and costs attributable to early paydown on the EXCO Operating term loan, a loan which was initiated in October 2006 and paid in full in March 2007. The following table presents the components of our interest expense:

	Three months ended					Six months ended
	June 30,					June 30,
(in thousands)	2008			2007		2008			2007
Interest expense:
7 1/4% senior notes due 2011	$	7,225		$	7,276	$	14,463		$	14,565
EXCO Resources Credit Agreement	11,140			5,316		20,662			11,675
EXCO Operating Credit Agreement	12,362			19,505		27,131			31,541
EXCO Operating term loan	—			91		—			18,140
Amortization of deferred financing costs on EXCO Resources Credit Agreement	494			249		970			310
Amortization and write-off of deferred financing costs on EXCO Operating term loan	753			25		1,506			32,100
Amortization and write-off of deferred financing costs on EXCO Operating loan	—			1,073		—			1,906
Interest rate swaps settlements	(383		)	—		(761		)	—
Fair market value adjustment on interest rate swaps	(11,001		)	—		(7,370		)	—
Capitalized interest	(316		)	—		(316		)	—
Other interest expense	(1		)	8		8			15
Total interest expense	$	20,273		$	33,543	$	56,293		$	110,252

On July 15, 2008, we entered into a $500.0 million Senior Unsecured Term Credit Agreement, or Term Credit Agreement, and incurred financing costs of approximately $10.6 million. The loan matures on December 15, 2008. As a result, our amortization of deferred financing costs will increase by approximately $2.1 million per month beginning in July 2008. In addition, interest on the loan will be approximately $2.5 million per month.

Income taxes

Our effective income tax rate for the six months ended June 30, 2008 and 2007 was a benefit of 37.9% and 28.6%, respectively. A substantial portion of our stock-based compensation included in our results of operations for the six months ended June 30, 2008 and 2007 are in the form of incentive stock options which are not deductible for tax purposes until a disqualifying event occurs. The increase in the tax rate from the prior year is a result of a state rate change last year in our state 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, cash received from the sale of oil and natural gas properties and the sale or issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. As of August 1, 2008, the aggregate borrowing base under our credit agreements totaled approximately $2.5 billion, of which $2.2 billion was outstanding. We do not establish a budget for acquisitions, as these tend to be opportunity driven. On July 15, 2008, we entered into the Term Credit Agreement, of which $300.0 million was drawn as of August 1, 2008. The funds drawn under the Term Credit Agreement were used to close a producing oil and natural gas property acquisition, provide capital for general operations of EXCO Operating and reduce debt under the EXCO Operating Credit Agreement. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders. In addition, our indenture governing our Senior Notes contains restrictions on incurring indebtedness and pledging our assets.

Net cash provided by operating activities was $512.2 million for the six months ended June 30, 2008 compared with $169.1 million for the six months ended June 30, 2007. The increase is attributable primarily to net cash provided from the oil and natural gas properties acquired. At June 30, 2008, our cash and cash equivalents balance was $34.1 million, a decrease of $21.4 million from December 31, 2007 primarily as a result of payments

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to reduce debt. On January 15, 2008, we made an interest payment on our Senior Notes of $16.1 million. We made dividend payments to our preferred shareholders of $35.0 million on March 14, 2008 and $35.0 million on June 16, 2008.

Recent events affecting liquidity

During the first six months of 2008, we expanded our activities in two of our core operating areas, East Texas/North Louisiana and Appalachia, to exploit the Haynesville, Marcellus and Huron shales. In Appalachia, our existing production areas and newly acquired leasehold interests hold deep rights in the Marcellus and Huron shales. Similarly, in East Texas and North Louisiana, our existing production areas and newly acquired leasehold interests hold deep rights in the Haynesville/Bossier shale. We estimate that our net acreage holdings exceed 119,800 acres in the Haynesville/Bossier shale and approximately 395,000 acres in the Marcellus and Huron shales.

As a result of our leasing and drilling programs, we increased our capital expenditure budget for 2008 by $175.0 million in March 2008, of which $150.0 million was allocated to acreage acquisition and drilling in the Marcellus and Huron shales in Appalachia. In May 2008, we again increased our 2008 capital expenditures budget by $143.0 million, which included approximately $90.0 million for acreage acquisition and exploitation of the Haynesville/Bossier shale in East Texas/North Louisiana. We also reallocated certain capital expenditures in East Texas and North Louisiana and Appalachia, which decreased the number of wells originally planned to be drilled in the second half of 2008, to focus more time and capital on our shale assets. Our 2008 capital expenditures budget is $943.0 million.

These capital expenditure increases have had the following impacts on our liquidity and capital resources:

· the acquisition of acreage differs from our traditional acquisitions of producing oil and natural gas assets since the acquisitions cause an increase in borrowings under our credit agreements, but do not provide immediate cash flows with which to service the debt;

· the EXCO Resources Credit Agreement was used to fund approximately $41.3 million of Marcellus acreage purchases during the second quarter of 2008. We also have acreage acquisition commitments totaling $40.0 million as of June 30, 2008. As a result of the anticipated increase in indebtedness, without the corresponding immediate cash flows, we requested and received from our lenders a temporary increase in the leverage ratio covenant (from not greater than 3.5 to 1.0 to not greater than 4.0 to 1.0);

· the EXCO Operating Credit Agreement was similarly impacted by acreage acquisitions in the Haynesville/Bossier shale play, where we spent $36.4 million on acreage acquisitions during the second quarter of 2008. We also have acreage acquisition commitments totaling approximately $7.6 million as of June 30, 2008;

· we incurred $300.0 million of unsecured debt to fund the producing property acquisition on July 15, 2008; and

· our decision to exploit the shale plays has resulted in increases to our drilling and leasehold acquisition expenditures. Consequently, substantial cash flows from operations that were previously used to reduce debt or fund acquisitions have been redeployed to these capital projects.

Oil and natural gas prices increased significantly during the first half of 2008 and we paid approximately $87.4 million to settle oil and natural gas derivatives for the six months ended June 30, 2008. While our revenues benefit from the increased prices, we do not receive full benefit as approximately 80% of our sold volumes are subject to derivative financial instruments. In addition, we are required to settle our derivative financial contracts prior to receiving the payments for production, which is typically collected 30 to 60 days after our derivative settlements are closed. The rapid increase in oil and natural gas prices, particularly in the second quarter of 2008, created a short term borrowing requirement of approximately $70.0 million.

Finally, on July 18, 2008, we forced the conversion of all outstanding shares of our preferred stock into our common stock, which will result in dividend savings of $35.0 million per quarter, or $140.0 million annually.

We believe that our capital resources from existing cash balances, cash flow from operating activities, including savings from dividends previously associated with our preferred stock and borrowing capacity under our credit agreements are adequate to meet the cash requirements to fund our operations and capital expenditure programs. 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 may be required to reduce our capital expenditure budget, which in turn may affect our production in future periods. Our operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. We have experienced increased costs for personnel, tubular goods and other services during 2008. Further, we have encountered increased demand for drilling rigs, tubular goods, fuel, utilities and other services. Currently, we do not

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believe that these conditions have had a significant impact upon our capital expenditure 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.

Our decision to exploit the recent shale opportunities in our core operating areas of East Texas/North Louisiana and Appalachia represents an important corporate commitment. We expect to manage these opportunities, and the related debt management including repayment or refinancing of our Term Credit Agreement, by pursuing, among other things, joint venture partners in our shale plays, evaluating the sale of non-strategic assets, pursuing consolidation of our two revolving credit facilities to maximize our borrowing capacity, or seeking other financing alternatives.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the three and six months ended June 30, 2008 and 2007.

	Three months ended				Six months ended
	June 30,				June 30,
(in thousands)	2008		2007		2008		2007
Capital expenditures:
Property acquisitions	$	62,659	$	813,682	$	477,178	$	2,260,964
Lease purchases	92,369		3,879		102,657		11,498
Development capital expenditures	136,178		104,139		288,337		180,032
Midstream acquisitions	—		455		55,667		117,452
Midstream capital additions	14,479		2,863		25,658		5,592
Corporate and other	14,774		9,073		25,123		13,537
Total capital expenditures	$	320,459	$	934,091	$	974,620	$	2,589,075

On February 20, 2008, we closed the Appalachian Acquisition for $388.4 million in cash, net of preliminary purchase price adjustments. The assets include producing oil and natural gas properties, undeveloped oil and natural gas properties, undeveloped acreage and related facilities in the Appalachia region. The Appalachian Acquisition was financed by the EXCO Resources Credit Agreement.

In March 2008 we closed the New Waskom Acquisition, which contained 230 miles of pipeline and a gathering system at a cost of approximately $55.6 million. The New Waskom system is located primarily in Harrison and Panola Counties in East Texas and Caddo Parish in North Louisiana. The system has access to one plant and three interstate pipelines.

Currently, we are expanding TGG, adding 57 miles of predominantly 20-inch diameter pipe at a cost of approximately $37.6 million. Upon completion of this expansion, which we expect to become fully operational in the second half of 2008, TGG will have 110 miles of pipeline with an incremental throughput of 100 Mmcf per day without compression. With compression, incremental throughput volumes could exceed 200 Mmcf per day.

Additionally, we are contemplating other Midstream projects in East Texas and North Louisiana to expand our transport capabilities for our own production as well as production from unaffiliated producers.

Beginning with the second quarter of 2008, we initiated aggressive acreage acquisition programs and spent approximately $36.4 million in the Haynesville/Bossier shale plays in East Texas and North Louisiana and approximately $41.3 million in the Marcellus and Huron shale plays in the Appalachia region of the United States. These acreage acquisition programs have significantly increased our capital expenditures for leaseholds and resulted in increases to our 2008 capital expenditures budget. In addition to our acreage acquisition program, we plan to drill three horizontal wells and 17 vertical wells in the Haynesville/Bossier shale area. We plan to drill four horizontal wells and seven vertical wells in the Marcellus shale area and approximately eight horizontal wells in the Huron shale area during 2008.

During 2008, we have increased our budgeted capital expenditures from approximately $625.0 million to approximately $943.0 million for our development, exploitation, exploration, midstream and corporate activities, of which $243.0 million and $427.0 million was spent during the three and six months ended June 30, 2008, respectively, exclusive of property acquisitions. As of June 30, 2008, we were contractually obligated to spend approximately $85.0 million for our development, exploitation and exploration activities for the remainder of 2008 and approximately $47.6 million for additional Haynesville and Marcellus acreage acquisitions. The increase in the capital expenditures budget is largely the result of acreage acquisitions and drilling in the Haynesville and Marcellus shale plays, additional drilling in our Vernon Field and capital expenditures associated with our Appalachian Acquisition and East Texas acquisition.

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On July 15, 2008, we acquired producing oil and natural gas properties, acreage and other assets in Gregg, Rusk and Upshur counties of Texas for approximately $243.6 million, including a $25.0 million deposit paid early in the second quarter of 2008 and net of preliminary closing adjustments. Funding for this acquisition was provided by a senior unsecured term loan, which matures on December 15, 2008.

7 1/4% senior notes due January 15, 2011

As of June 30, 2008, $444.7 million in principal was outstanding on our 7 1/4% senior notes due January 15, 2011, or Senior Notes. The unamortized premium on the Senior Notes at June 30, 2008 was $9.3 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $438.6 million on June 30, 2008.

Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year. Effective January 15, 2007, we may redeem some or all of the Senior Notes for the redemption price set forth in the Senior Notes. On July 15, 2008, we paid $16.1 million of interest on the Senior Notes.

The indenture governing the Senior Notes contains covenants, which limit our ability and the ability of our guarantor 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.

Credit agreements

EXCO Resources Credit Agreement

On February 20, 2008, we entered into the first amendment to the EXCO Resources Credit Agreement. The primary change to the EXCO Resources Credit Agreement was an increase in the borrowing base from $900.0 million to approximately $1.2 billion, principally to reflect the assets acquired in the Appalachian Acquisition. On July 14, 2008, we entered into the second amendment to the EXCO Resources Credit Agreement. This amendment, which was effective June 30, 2008, permitted the payment of cash dividends in connection with the exercise of any right to convert our preferred stock into common stock without compliance with certain limitations on restricted payments. In addition, the leverage ratio covenant, as defined in the agreement, was increased to provide that EXCO will not permit such ratio (i) as of the end of any fiscal quarter ending on or after June 30, 2008 and on or before December 31, 2008 to be greater than 4.00 to 1.00, (ii) as of the end of the fiscal quarter ending on March 31, 2009 to be greater than 3.75 to 1.00 and (iii) as the end of any fiscal quarter ending on or after June 30, 2009 to be greater than 3.50 to 1.00. The other financial covenants and all other terms, including maturity date and borrowing base, contained within the EXCO Resources Credit Agreement remained unchanged.

The borrowing base is redetermined semi-annually with EXCO and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are on or about April 1 and October 1 of each year. The interest rate ranges from LIBOR plus 100 basis points, or bps, to LIBOR plus 175 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus

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0 bps to ABR plus 75 bps depending upon borrowing base usage. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO has also agreed to have in place derivative financial instruments covering no more than 80% of its forecasted production from total proved reserves (as defined) for 2008 and 70% in 2009 through 2011. EXCO will have in place mortgages covering 80% of the engineered value of its Borrowing Base Properties (as defined). The foregoing description is not complete and is qualified in its entirety by the EXCO Resources Credit Agreement. As of June 30, 2008, EXCO was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement which require that we:

· maintain a Consolidated Current Ratio (as defined) of at least 1.0 to 1.0 as of the end of any fiscal quarter ending on or after September 30, 2007;

· not permit our ratio of Consolidated Funded Indebtedness (as defined) to Consolidated EBITDAX (as defined) to be greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after June 30, 2008 and on or before December 31, 2008, 3.75 to 1.0 at the end of the fiscal quarter ending on March 31, 2009 and 3.5 to 1.0 beginning with the quarter ending June 30, 2009 and each quarter thereafter; and

· maintain a Consolidated EBITDAX to Consolidated Interest Expense (as defined) ratio of at least 2.5 to 1.0 at the end of any fiscal quarter ending on or after September 30, 2007.

At August 1, 2008, the six month LIBOR rate was 3.1%, which would result in an interest rate of approximately 4.8% on any new indebtedness we may incur under the EXCO Resources Credit Agreement. At August 1, 2008 we had $1.1 billion of outstanding indebtedness under the EXCO Resources Credit Agreement.

EXCO Operating Credit Agreement

The EXCO Operating Credit Agreement has a borrowing base of $1.3 billion. The borrowing base is scheduled to be redetermined on a semi-annual basis, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each year. The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating has agreed to have in place derivative financial instruments covering no more than 80% of the “forecasted production from total proved reserves” (as defined) for 2008 and 70% of the forecasted production from total proved reserves for 2009 through 2011. On July 14, 2008, EXCO Operating entered into a second amendment to the EXCO Operating Credit Agreement to (i) allow EXCO Operating to incur up to $500.0 million of indebtedness under the Term Credit Agreement and (ii) exclude drawings under the Term Credit Agreement from the consolidated current ratio, as defined in the EXCO Operating Credit Agreement through December 31, 2008. The foregoing description is not complete and is qualified in its entirety by the EXCO Operating Credit Agreement. As of June 30, 2008, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:

· maintain a consolidated current ratio (as defined) of at least 1.0 to 1.0 at the end of any fiscal quarter, beginning with the quarter ended June 30, 2007;

· not permit our ratio of consolidated indebtedness to consolidated EBITDAX (as defined) to be greater than 3.5 to 1.0 at the end of each fiscal quarter, beginning with the quarter ended June 30, 2007; and

· not permit our interest coverage ratio (as defined) to be less than 2.5 to 1.0 at the end of each fiscal quarter, beginning with the quarter ended June 30, 2007.

The EXCO Operating Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The EXCO Operating Credit Agreement matures March 30, 2012. Interest under the EXCO Operating Credit Agreement ranges from LIBOR plus 100 bps to 175 bps. The facility also includes an ABR pricing alternative ranging from ABR plus 0 bps to ABR plus 75 bps.

At August 1, 2008, the six month LIBOR rate was 3.1%, which would result in an interest rate of approximately 4.6% on any new indebtedness we may incur under the EXCO Operating Credit Agreement. At August 1, 2008 we had $1.1 billion of outstanding indebtedness under the EXCO Operating Credit Agreement.

Senior Unsecured Term Credit Agreement

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expenses. Proceeds from the Term Credit Agreement were used to fund an acquisition of developed and undeveloped oil and natural gas properties and gathering and treating facilities located in East Texas from private sellers for approximately $218.6 million, net of a $25.0 million deposit paid early in the second quarter of 2008 and preliminary purchase price adjustments, provide working capital for general corporate purposes and to reduce indebtedness under the EXCO Operating Credit Agreement.

A term loan in the amount of $300.0 million was made in a single draw on July 15, 2008. Thereafter through October 15, 2008, EXCO Operating may request additional term loans of up to $200.0 million in the aggregate, which are available in up to four separate advances of at least $50.0 million or increments of $5.0 million in excess thereof, but the lenders have no obligation to provide the requested additional funding. The Term Credit Agreement is due and payable on December 15, 2008 and is guaranteed by all existing and future direct or indirect subsidiaries of EXCO Operating, including any guarantor of the EXCO Operating Credit Agreement.

Preferred stock

The Series A-1, Series B and Series C 7.0% Cumulative Convertible Perpetual Preferred Stock, or the 7.0% Preferred Stock and Series A-1 Hybrid Preferred Stock, or the Hybrid Preferred Stock, and together with the 7.0% Preferred Stock, the Preferred Stock, were issued in several series at a purchase price of $10,000 per share on March 30, 2007. The Preferred Stock was convertible into common stock at any time by the holder at a price of $19.00 per share. We were entitled to force the conversion of the Preferred Stock at any time if the common stock traded for 20 days within a period of 30 consecutive days at a price (i) above 175% of the then effective conversion price ($33.25 per share at the final conversion price of $19.00 per share) at any time during the 24 months after issuance, (ii) above 150% of the then effective conversion price ($28.50 per share at the final conversion price of $19.00 per share) thereafter through the 48th month after issuance and (iii) above 125% of the then effective conversion price ($23.75 per share at the final conversion price of $19.00 per share) at any time thereafter. Cash dividends accrued at the rate of 7.0% per annum prior to March 30, 2013 and at the rate of 9.0% per annum thereafter. Upon the occurrence of a change of control, holders of our Preferred Stock were able to force us to repurchase their shares for cash at the liquidation preference plus accumulated dividends. Holders of our Preferred Stock had the right to vote with the holders of common stock as a single class on all matters submitted to our shareholders (except the election of directors) on an as-converted basis. Holders of Preferred Stock had the right to separately elect up to four directors, subject to the rights of the holders of Series B 7.0% Preferred Stock and Series C 7.0% Preferred Stock to vote as separate classes to each elect one of such preferred directors. In addition, upon the occurrence of specified defaults in the Statements of Designation for the Preferred Stock, the holders of the Preferred Stock, voting together as a class, had the right to elect four additional directors, or default directors, until such default was cured. In connection with the mandatory conversion of our Preferred Stock into common stock on July 18, 2008, the right to designate Preferred Stock directors terminated. However, pursuant to letter agreements entered into with each of Ares Management, LLC and Oaktree Capital Management, L.P. each of those entities continue to have the right to nominate one director for election at any annual meeting of shareholders so long as each entity beneficially owns at least 10,000,000 shares of common stock. The remaining two Preferred Stock directors currently serving on our Board of Directors are entitled to serve until the next annual meeting of shareholders.

As of June 30, 2008, the liquidation preference of the 7.0% Preferred Stock and the Hybrid Preferred Stock was $0.4 billion and $1.6 billion, respectively.

We paid cash dividends totaling $35.0 million on June 16, 2008 to the holders of our Preferred Stock. We had accrued dividends of $5.8 million as of June 30, 2008.

On July 18 2008, we converted all outstanding shares of our Preferred Stock into a total of approximately 105.2 million shares of our common stock. The conversion of the Preferred Stock has the effect of increasing the book value of

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shareholders’ equity by approximately $2.0 billion. We also paid all accrued but unpaid dividends in cash totaling approximately $12.8 million to the holders of the converted shares of Preferred Stock as of July 18, 2008. After July 18, 2008, dividends ceased to accrue on the Preferred Stock and all rights of the holders with respect to the Preferred Stock terminated, except for the right to receive the whole shares of common stock issuable upon conversion, accrued dividends through July 18, 2008 and cash in lieu of any fractional shares. The conversion of all outstanding shares of Preferred Stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.

Derivative financial instruments

We use oil and natural gas derivatives and financial risk management instruments to manage our exposure to commodity price and interest rate fluctuations. We do not designate these instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings, as a gain or loss on oil and natural gas derivatives and interest expense on financial risk management instruments.

Oil and natural gas derivatives

Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas 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 oil and natural gas 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 June 30, 2008, we had contracts in place for the volumes and prices shown below:

	Natural gas	Weighted			Weighted
	volume/	average strike		Oil	average strike
(in thousands, except prices)	Mmbtu	price per Mmbtu		volume/Bbl	price per Bbl
Natural Gas:
Swaps (NYMEX):
Q3 2008	26,900	$	8.29	358	$	68.20
Q4 2008	26,910	8.39		358	68.16
2009	100,530	8.18		1,215	69.11
2010	40,748	8.03		473	84.85
2011	9,125	7.97		—	—
2012	1,830	4.51		—	—
2013	1,825	4.51		—	—

Interest rate swaps

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at June 30, 2008:

	Less than one		One to three		Three to five		More than five
(in thousands)	year		years		years		years		Total
Contractual obligations:
Long-term debt - senior notes (1)	$	—	$	444,720	$	—	$	—	$	444,720
Long-term debt - EXCO Resources Credit Agreement (2)	—		—		994,000		—		994,000
Long-term debt - EXCO Operating Credit Agreement (3)	—		—		1,170,000		—		1,170,000
Term Credit Agreement (4)	—		—		—		—		—
Operating leases (5)	11,787		10,630		9,456		4,029		35,902
Pending property and lease acquisition commitments (6)	226,850		—		—		—		226,850
Drilling/work commitments	44,292		31,380		12,723		—		88,395
Total contractual cash obligations (7)	$	282,929	$	486,730	$	2,186,179	$	4,029	$	2,959,867

(1)

Our Senior Notes are due on January 15, 2011. The annual interest obligation is $32.2 million.

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(2)		The EXCO Resources Credit Agreement matures on March 30, 2012.
(3)		The EXCO Operating Credit Agreement matures on March 30, 2012.
(4)		The Term Credit Agreement for $300.0 million was entered into on July 15, 2008 and matures on December 15, 2008.
(5)		Excludes month-to-month rental expense on compressors.
(6)		Represents an executed purchase and sale agreement, dated June 5, 2008, to purchase oil and natural gas properties and other undeveloped lease acquisitions. The transaction closed on July 15, 2008.
(7)		Excludes annual dividends of $140.0 million on our Preferred Stock. Such dividends no longer accrue due to the mandatory conversion of all outstanding shares of our Preferred Stock into our common stock on July 18, 2008.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity price risk

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

The following table sets forth our oil and natural gas derivatives management activities as of June 30, 2008.

		Weighted
	Volume	average strike		Fair value at
(in thousands, except prices)	Mmbtu/Bbl	price		June 30, 2008
Natural Gas:
Swaps (NYMEX):
Remainder of 2008	53,810	$	8.34	$	(277,110	)
2009	100,530	8.18		(411,736		)
2010	40,748	8.03		(118,550		)
2011	9,125	7.97		(21,820		)
2012	1,830	4.51		(9,121		)
2013	1,825	4.51		(8,726		)
Total Natural Gas	207,868			(847,063		)

Oil:
Swaps (NYMEX):
Remainder of 2008	716	68.18		(51,474		)
2009	1,215	69.11		(82,582		)
2010	473	84.85		(22,752		)
Total Oil	2,404			(156,808		)
Total Oil and Natural Gas				$	(1,003,871	)

At June 30, 2008, the average forward NYMEX oil prices per Bbl for the remainder of 2008 and for calendar year 2009 were $141.05 and $140.64, respectively and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2008 and for calendar 2009 were $13.54 and $12.47, respectively.

During July 2008, the average forward NYMEX oil prices per barrel for the remainder of 2008 and calendar year 2009 decreased by $16.10 per barrel and $15.95 per barrel, respectively. The natural gas prices for the same periods decreased by $4.12 per Mcf and $2.71 per Mcf, respectively. The impact on our mark-to-market liability, as of June 30, 2008, using these July 2008 NYMEX strip prices would result in a net liability of $443.8 million, or a decrease of $560.1 million. Our reported earnings and assets or liabilities for derivative financial instruments will continue to be subject to significant

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fluctuations in value due to price volatility.

Realized gains or losses from the settlement of our oil and natural gas derivatives are recorded in our financial statements as increases or decreases in oil and gas revenue. For example, using the oil swaps in place at June 30, 2008, for the remainder of 2008, if the settlement price exceeds the actual weighted average strike price of $68.18 per Bbl, then a reduction in oil and natural gas revenue would be recorded for the difference between the settlement price and $68.18 per Bbl, multiplied by the hedged volume of 716 Mbbls. Conversely, if the settlement price is less than $68.18 per Bbl, then an increase in oil and natural gas revenue would be recorded for the difference between the settlement price and $68.18 per Bbl, multiplied by the hedged volume of 716 Mbbls. For example, for a hedged volume of 716 Mbbls, if the settlement price is $67.18 per Bbl then oil and natural gas revenue would decrease by $0.7 million. Conversely, if the settlement price is $69.18 per Bbl, oil and natural gas revenue would increase by $0.7 million.

Interest rate risk

At June 30, 2008, our exposure to interest rate changes related primarily to borrowings under our credit agreements and interest earned on our short-term investments. The interest rate is fixed at 7 1/4% on the $444.7 million in Senior Notes we have outstanding. Interest is payable on borrowings under our credit agreements and the Term Credit Agreements is based on a floating rate as more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity, capital resources and capital commitments.” At June 30, 2008, we had $2.2 billion in outstanding borrowings under our credit agreements. A 1% change in interest rates based on the variable borrowings as of June 30, 2008 would result in an increase or decrease in our interest costs of $22.0 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

In January 2008, we entered into financial risk management instruments to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBOR rates ranging from 2.45% to 2.8%. As of June 30, 2008, we had $7.4 million of unrealized gains on our interest rate swaps.

Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures

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

Our management evaluated, under the supervision and with the participation of our CEO, CFO and CAO, the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2008 and concluded our controls were effective.

Changes in internal control over financial reporting

No changes in EXCO’s internal control over financial reporting occurred during the current quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal proceedings

Effective March 18, 2008, we entered into an agreement to settle all claims arising under a putative royalty owner class action filed against our subsidiaries, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., styled PRC Holdings, LLC, et al. v. North Coast Energy, Inc. for $40,000. In connection with this settlement, all claims alleged by the plaintiffs were dismissed with prejudice by the federal district court on July 11, 2008.

Item 4. Submission of Matters to a Vote of Security Holders

On May 15, 2008, EXCO held its annual meeting of shareholders. At the annual meeting, shareholders acted upon the matters outlined in EXCO’s definitive Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 8, 2008. The matter voted upon and approved solely by the holders of our common stock was the election of seven directors to the Board of Directors, each for a one-year term. The matter voted upon and approved by the holders of our common stock and Preferred Stock, voting together as a single class, was the ratification of the appointment of KPMG LLP as our independent registered public accounting firm.

Our common shareholders approved all of the common stock directors nominated for election at the annual meeting pursuant to the following voting results:

	Number of	Number of
Name	Votes Cast For	Votes Withheld
Douglas H. Miller	96,659,275	449,100
Stephen F. Smith	96,806,448	301,927
Jeffrey D. Benjamin	94,105,245	3,003,120
Earl E. Ellis	94,105,745	3,002,630
Robert H. Niehaus	94,105,945	3,002,430
Boone Pickens	96,786,468	321,907
Robert L. Stillwell	96,806,134	302,241

The holders of our Preferred Stock did not have the right to vote with the holders of our common stock to elect the common stock directors set forth above. Instead, the holders of our Preferred Stock were previously entitled to designate and elect the other four members of our Board of Directors, Vincent J. Cebula, B. James Ford, Jeffrey S. Serota and Rajath Shourie, pursuant to the Statements of Designation governing the Preferred Stock. In connection with the mandatory conversion of our Preferred Stock into common stock on July 18, 2008, the right to designate Preferred Stock directors terminated. However, pursuant to letter agreements entered into with Ares Management, LLC and Oaktree Capital Management, L.P. each of those entities continue to have the right to nominate one director for election at any annual meeting of shareholders so long as each entity beneficially owns at least 10,000,000 shares of common stock. The remaining two Preferred Stock directors currently serving on our Board of Directors are entitled to serve until the next annual meeting of shareholders.

Our common shareholders and the holders of our Preferred Stock, voting together as a single class, approved the ratification of KPMG LLP as our independent registered public accounting firm at the annual meeting pursuant to the following voting results:

	Number of	Number of	Number of
Proposal	Votes Cast For	Votes Cast Against	Abstentions
Ratification of KPMG	162,150,201	411,377	8,902

Item 6. Exhibits

See “Index to Exhibits” for a description of our exhibits.

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SIGNATURES

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

	EXCO RESOURCES, INC.
	(Registrant)

Date: August 6, 2008	By:	/s/ DOUGLAS H. MILLER
		Douglas H. Miller
		Chairman and Chief Executive Officer

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

	By:	/s/ MARK E. WILSON
		Mark E. Wilson Vice President, Chief Accounting Officer
		and Controller

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Index to Exhibits

Exhibit Number		Description of Exhibits
2.1		Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.

2.2		First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.

2.3		Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.

2.4		Purchase and Sale Agreement by and among EXCO Resources, Inc., as Purchaser, Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation and Kerr-McGee Oil & Gas Onshore LP, as Seller, dated February 1, 2007, filed as an Exhibit to EXCO’s Annual Report on Form 10-K filed on March 19, 2007 and incorporated by reference herein.

2.5		First Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement by and among Anadarko Petroleum Corporation, Anadarko Gathering Company, EXCO Partners Operating Partnership, LP (successor by merger to Vernon Holdings, LLC) and Vernon Gathering, LLC, dated March 30, 2007, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

2.6		First Amendment Letter Agreement by and among EXCO Resources, Inc., Southern G Holdings, LLC, Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated April 13, 2007, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

2.7		Second Amendment to Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P Company LP, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

2.8		Third Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P Company LP, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

2.9		Membership Interest Purchase and Sale Agreement, dated May 8, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Crimson Exploration Inc. and Crimson Exploration Operating, Inc., filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

2.10		Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search, Incorporated, as sellers, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

2.11		First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and Energy Search, Incorporated,

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		as sellers, filed as an exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

3.1		Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.

3.2		Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.

3.3		Statement of Designation of Series A-1 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.4		Statement of Designation of Series A-2 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.5		Statement of Designation of Series B 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.6		Statement of Designation of Series C 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.7		Statement of Designation of Series A-1 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

3.8		Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

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

4.2		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004, filed as an Exhibit to EXCO’s Registration Statement on Form S-4 filed March 25, 2004 and incorporated by reference herein.

4.3		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

4.4		Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.

4.5		Form of 71/4% Global Note Due 2011, filed as an Exhibit to EXCO’s Pre-effective Amendment No. 1 to its Registration Statement on Form S-4 filed April 20, 2004 and incorporated by reference herein.

4.6		Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-1 (File No. 333- 129935) filed on January 27, 2006 and incorporated by reference herein.

4.7		Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s

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		Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.

4.8		Fifth Supplemental Indenture, dated as of May 2, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

4.9		Sixth Supplemental Indenture, dated as of February 12, 2008, by and among EXCO Resources, Inc., EXCO Services, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.

4.10		First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.

4.11		Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

4.12		Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

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

10.2		First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004, filed as an Exhibit to EXCO’s Registration Statement on Form S-4 filed March 25, 2004 and incorporated by reference herein.

10.3		Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.

10.4		Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.

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

10.6		Form of 71/4% Global Note Due 2011, filed as an Exhibit to EXCO’s Pre-effective Amendment No. 1 to its Registration Statement on Form S-4 filed April 20, 2004 and incorporated by reference herein.

10.7		Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.8		Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.9		Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive

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		Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

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

10.11		Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.

10.12		First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.

10.13		Senior Revolving Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.

10.14		First Amendment to Credit Agreement, dated October 2, 2006, among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.

10.15		Amended and Restated Equity Contribution Agreement, dated October 4, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.

10.16		Senior Term Credit Agreement, dated October 2, 2006, as amended and restated as of October 13, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.

10.17		Second Amended and Restated Equity Contribution Agreement, dated October 13, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.

10.18		Third Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*

10.19		Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.

10.20		Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.

10.21		First Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement by and among Anadarko Petroleum Corporation, Anadarko Gathering Company, EXCO Partners Operating Partnership, LP (successor by merger to Vernon Holdings, LLC) and Vernon Gathering, LLC,

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		dated March 30, 2007, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.22		Guaranty dated December 22, 2006 by EXCO Resources, Inc. in favor of Anadarko Petroleum Corporation and Anadarko Gathering Company, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.

10.23		Purchase and Sale Agreement by and among EXCO Resources, Inc., Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated February 1, 2007, filed as an Exhibit to EXCO’s Annual Report on Form 10-K filed on March 19, 2007 and incorporated by reference herein.

10.24		First Amendment to Credit Agreement effective as of December 31, 2006 among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated March 8, 2007 and filed March 13, 2007 and incorporated by reference herein.

10.25		Preferred Stock Purchase Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.26		Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.*

10.27		Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, ACOF EXCO, L.P., ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares EXCO 892 Investors, L.P, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.28		Amended and Restated Credit Agreement, dated as of March 30, 2007, among EXCO Partners Operating Partnership, LP, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.29		Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.30		Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.31		First Amendment to Letter Agreement by and among EXCO Resources, Inc., Southern G Holdings, LLC, Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated April 13, 2007, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

10.32		Second Amended and Restated Credit Agreement, dated as of May 2, 2007, among EXCO Resources, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

10.33		Fifth Supplemental Indenture, dated as of May 2, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on

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		Form 8-K, dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

10.34		Second Amendment to Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P Company LP, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

10.35		Third Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P Company LP, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

10.36		Membership Interest Purchase and Sale Agreement, dated May 8, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC, Crimson Exploration Inc. and Crimson Exploration Operating, Inc., filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.

10.37		Purchase Agreement, effective August 15, 2007, between OCM GW Holdings, LLC and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 15, 2007 and filed on August 21, 2007 and incorporated by reference herein.

10.38		Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search, Incorporated, as sellers, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

10.39		Sixth Supplemental Indenture, dated as of February 12, 2008, by and among EXCO Resources, Inc., EXCO Services, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.

10.40		Counterpart Agreement, dated February 4, 2008, to that Certain Second Amended and Restated Credit Agreement, dated May 2, 2007, among EXCO Resources, Inc., as Borrower, and certain subsidiaries of Borrower and the lender parties thereto, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.

10.41		First Amendment to Second Amended and Restated Credit Agreement, dated as of February 20, 2008, by and among EXCO Resources, Inc., as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined herein, and JP Morgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

10.42		First Amendment to Amended and Restated Credit Agreement, dated as of February 20, 2008, by and among EXCO Partners Operating Partnership, LP, as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein and JP Morgan Chase Bank, N.A., as Administrative Agent, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

10.43		First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and Energy Search, Incorporated, as sellers, filed as an exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

10.44		Seventh Supplemental Indenture, dated as of June 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed herewith.

10.45		Senior Unsecured Term Credit Agreement, dated as of July 15, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries, as guarantors, and JP Morgan Chase Bank, N.A., as administrative agent, and the Lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K dated

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		July 14, 2008 and filed on July 16, 2008 and incorporated by reference herein.

10.46		Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries as guarantors, and JP Morgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K dated July 14, 2008 and filed on July 16, 2008 and incorporated by reference herein.

10.47		Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 14, 2008 and effective as of June 30, 2008, among EXCO Resources, Inc., as borrower, and certain of its subsidiaries, as guarantors, and JP Morgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K dated July 14, 2008 and filed on July 16, 2008 and incorporated by reference herein.

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

31.2		Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer 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.

99.1		Audit Committee Charter, filed herewith.

* These exhibits are management contracts.