Exco Resources (EXCO) 10-Q 2008 Q1 Quarterly report

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 March 31, 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 May 5, 2008 was 105,154,824.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Balance Sheets at December 31, 2007 and March 31, 2008
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2007 and 2008
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2008
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2007 and 2008
	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 6.	Exhibits
	Signatures
	Index to Exhibits

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	December 31,			March 31,
(in thousands)	2007			2008
Assets
Current assets:
Cash and cash equivalents	$	55,510		$	9,113
Accounts receivable:
Oil and natural gas	146,297			180,029
Joint interest	21,614			22,871
Interest and other	2,151			5,296
Derivative financial instruments	66,632			—
Deferred income taxes	6,764			—
Other	12,332			11,671
Total current assets	311,300			228,980
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	334,803			372,066
Proved developed and undeveloped oil and natural gas properties	4,926,053			5,447,621
Accumulated depletion	(500,493		)	(604,406		)
Oil and natural gas properties, net	4,760,363			5,215,281
Gas gathering assets	340,706			428,057
Accumulated depreciation and amortization	(16,142		)	(19,614		)
Gas gathering assets, net	324,564			408,443
Office and field equipment, net	20,844			21,800
Advance on pending acquisition	39,500			3,500
Derivative financial instruments	2,491			4,561
Deferred financing costs, net	20,406			19,949
Other assets	6,226			3,422
Goodwill	470,077			470,077
Total assets	$	5,955,771		$	6,376,013

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	December 31,		March 31,
(in thousands, except per share and share data)	2007		2008
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	106,305	$	111,851
Accrued interest payable	21,835		15,563
Revenues and royalties payable	100,978		120,120
Income taxes payable	87		87
Deferred income taxes	—		66,617
Current portion of asset retirement obligations	1,656		1,850
Derivative financial instruments	47,306		268,781
Total current liabilities	278,167		584,869
Long-term debt	2,099,171		2,479,048
Asset retirement obligations and other long-term liabilities	89,810		102,514
Deferred income taxes	271,398		121,105
Derivative financial instruments	109,205		171,008
Commitments and contingencies	—		—
7.0% Cumulative Convertible Perpetual Preferred Stock, par value $0.001 per share, 39,008 shares outstanding at December 31, 2007 and March 31, 2008, liquidation preference of $391,218 at December 31, 2007 and March 31, 2008	388,574		388,574
Hybrid Preferred Stock, par value $0.001 per share, 160,992 shares outstanding at December 31, 2007 and March 31, 2008, liquidation preference of $1,614,616 at December 31, 2007 and March 31, 2008	1,603,704		1,603,704
Shareholders’ equity:
Preferred stock, par value $0.001 per share; 10,000,000 shares authorized at March 31, 2008, of which 200,000 shares have been designated for each series of 7.0% Cumulative Convertible Perpetual Preferred Stock and 200,000 shares have been designated for each series of Hybrid Preferred Stock; no shares of preferred stock other than the 7.0% Cumulative Convertible Perpetual and Hybrid Preferred Stock (presented above) are issued and outstanding at March 31, 2008	—		—
Common stock, $0.001 par value; Authorized shares - 350,000,000; issued and outstanding shares - 104,578,941 at December 31, 2007 and 104,887,915 at March 31, 2008	105		105
Additional paid-in capital	1,043,645		1,050,933
Retained earnings (deficit)	71,992		(125,847		)
Total shareholders’ equity	1,115,742		925,191
Total liabilities and shareholders’ equity	$	5,955,771	$	6,376,013

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended
	March 31,
(in thousands, except per share data)	2007			2008
Revenues and other income:
Oil and natural gas	$	118,495		$	317,690
Loss on derivative financial instruments	(96,019		)	(341,194		)
Other income	6,725			8,545
Total revenues and other income	29,201			(14,959		)
Costs and expenses:
Oil and natural gas production	30,078			52,481
Gathering and transportation	821			3,131
Depreciation, depletion and amortization	51,324			109,217
Accretion of discount on asset retirement obligations	943			1,316
General and administrative	14,175			22,627
Interest	76,709			36,020
Total costs and expenses	174,050			224,792
Loss before income taxes	(144,849		)	(239,751		)
Income tax benefit	(57,152		)	(76,912		)
Net loss	(87,697		)	(162,839		)
Preferred stock dividends	1,136			35,000
Net loss available to common shareholders	$	(88,833	)	$	(197,839	)
Net loss per common share:
Net loss per common share - basic	$	(0.85	)	$	(1.89	)
Net loss per common share - diluted	$	(0.85	)	$	(1.89	)
Weighted average shares:
Basic	104,202			104,683
Diluted	104,202			104,683

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended
	March 31,
(in thousands)	2007			2008
Operating Activities:
Net loss	$	(87,697	)	$	(162,839	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	51,324			109,217
Stock option compensation expense	1,910			3,004
Accretion of discount on asset retirement obligations	943			1,316
Non-cash change in fair value of derivatives	128,092			347,840
Cash settlements of assumed derivatives	—			(10,467		)
Deferred income taxes	(56,037		)	(76,912		)
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt	9,355			406
Loss on sale of fixed assets	—			31
Effect of changes in:
Accounts receivable	8,494			(38,133		)
Other current assets	361			2,389
Accounts payable and other current liabilities	(24,194		)	23,658
Net cash provided by operating activities	32,551			199,510
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(1,489,950		)	(602,667		)
Advance on pending acquisition	(43,000		)	(3,500		)
Proceeds from disposition of property and equipment and other	131,594			1,298
Net cash used in investing activities	(1,401,356		)	(604,869		)
Financing Activities:
Borrowings under credit agreements	1,198,000			500,700
Repayments under credit agreements	(1,672,532		)	(120,000		)
Proceeds from issuance of common stock	817			3,527
Proceeds from issuance of preferred stock	2,000,000			—
Payment of preferred stock dividends	—			(35,000		)
Payments for preferred stock issuance costs	(525		)	—
Settlements of derivative financial instruments with a financing element	—			10,467
Deferred financing costs	(10,099		)	(732		)
Net cash provided by financing activities	1,515,661			358,962
Net increase (decrease) in cash	146,856			(46,397		)
Cash at beginning of period	22,822			55,510
Cash at end of period	$	169,678		$	9,113
Supplemental Cash Flow Information:
Interest paid	$	92,695		$	38,627
Derivative financial instruments assumed in Vernon Acquisition	$	60,015		$	—
Supplemental non-cash investing and financing activities:
Capitalized stock compensation	$	368		$	675
Issuance of common stock for director services	$	—		$	82

See accompanying notes.

6

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, 2006	104,162	$	104	$	1,024,442	$	155,304		$	1,179,850
Issuance of common stock	79	—		817		—			817
Preferred stock dividends	—	—		—		(1,136		)	(1,136		)
Share-based compensation	—	—		2,277		—			2,277
Net loss	—	—		—		(87,697		)	(87,697		)
Balance at March 31, 2007	104,241	$	104	$	1,027,536	$	66,471		$	1,094,111
Balance at December 31, 2007	104,579	$	105	$	1,043,645	$	71,992		$	1,115,742
Issuance of common stock	309	—		3,609		—			3,609
Preferred stock dividends	—	—		—		(35,000		)	(35,000		)
Share-based compensation	—	—		3,679		—			3,679
Net loss	—	—		—		(162,839		)	(162,839		)
Balance at March 31, 2008	104,888	$	105	$	1,050,933	$	(125,847	)	$	925,191

See accompanying notes.

7

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 Partners Operating Partnership, LP and its subsidiaries and are collectively referred to as EPOP. Organizationally, EPOP is an indirect wholly-owned subsidiary of EXCO Resources. EPOP’s debt is not guaranteed by EXCO Resources and EPOP does not guarantee EXCO Resources’ debt.

The accompanying condensed consolidated balance sheets as of December 31, 2007 and March 31, 2008, the results of operations, cash flows and the changes in shareholders’ equity for the three months ended March 31, 2007 and 2008, 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 March 31, 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.

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 on the following table:

8

(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 was approximately $772.5 million and the purchase price allocation 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 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 March 31,
(in thousands, except per share data)	2007			2008
Revenues and other income	$	168,826		$	(8,605	)
Net loss	$	(34,477	)	$	(162,919	)
Preferred stock dividends	(34,521		)	(35,000		)
Net loss available to common shareholders	$	(68,998	)	$	(197,919	)
Basic loss per share	$	(0.66	)	$	(1.89	)
Diluted loss per share	$	(0.66	)	$	(1.89	)

9

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.

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.

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.

We adopted 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.  See “Note 9.  Derivative financial instruments and fair value measurements” for a discussion of the impacts of the adoption of SFAS No. 157.

5.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2008:

(in thousands)
Asset retirement obligation at January 1, 2008	$	84,370
Activity during the three months ended March 31:
Liabilities incurred during the period	1,275
Liabilities settled during the period	(2,260		)
Additions to asset retirement obligations due to acquisitions	12,647
Accretion of discount	1,316
Asset retirement obligations as of March 31	97,348
Less current portion	(1,850		)
Long-term portion	$	95,498

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 $334.8 million and $372.1 million as of December 31, 2007 and March 31, 2008, 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.

10

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. In addition, in July 2007, we sought, and received, an exemption from the SEC to exclude the Vernon Acquisition and the Southern Gas Acquisition from our ceiling test for a period of 12 months from the closing date of each acquisition, provided that we could demonstrate beyond a reasonable doubt that the fair value of the oil and natural gas reserves exceeded their unamortized carrying costs. The exemption related to the Vernon Acquisition expired March 30, 2008 and was included in our March 31, 2008 ceiling test calculation. The exemption related to the Southern Gas Acquisition expired on May 2, 2008.  At March 31, 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 months ended March 31, 2007 and 2008 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 months ended March 31, 2007 and 2008 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 7.0% Convertible Preferred Stock and Hybrid Preferred Stock, whether exercisable or not.  Since we incurred net losses for the three months ended March 31, 2007 and 2008, we have excluded the potential common stock equivalents from the assumed conversion of stock options of 2,245,500 and 1,791,867, respectively, and 105,263,158 shares of common stock from the assumed conversion of the 7.0% Convertible Preferred Stock and Hybrid Preferred Stock from the computation of earnings per share as they are antidilutive.

11

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

	Three months ended March 31,
(in thousands, except per share amounts)	2007			2008
Basic loss per common share:
Net loss	$	(87,697	)	$	(162,839	)
Preferred stock dividends	1,136			35,000
Net loss available to common shareholders	$	(88,833	)	$	(197,839	)
Shares:
Weighted average number of common shares outstanding	104,202			104,683
Basic loss per common share:
Net loss available to common shareholders per common share	$	(0.85	)	$	(1.89	)
Diluted loss per share:
Net loss available to common shareholders	$	(88,833	)	$	(197,839	)
Shares:
Weighted average number of common shares outstanding	104,202			104,683
Dilutive effect of stock options	—			—
Weighted average common shares and common stock equivalent shares outstanding	104,202			104,683
Diluted loss per share:
Net loss available to common shareholders per common share	$	(0.85	)	$	(1.89	)

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 months ended March 31, 2008, total share-based compensation was $3.7 million, of which $3.0 million is included in general administrative and lease operating expense and $0.7 million 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 March 31, 2008 is $22.6 million over a weighted average period of 1.26 years.

During the three months ended March 31, 2008, options to purchase 426,900 shares were granted under the 2005 Incentive Plan at prices ranging from $15.15 to $16.96 per share with fair values ranging from $5.39 to $5.98 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant.  As of December 31, 2007 and March 31, 2008, there were 7,022,375 and 6,671,675 shares available to be granted under the 2005 Incentive Plan, respectively.

9.Derivative financial instruments and fair value measurements

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 instruments’ fair value currently in earnings, as gains or losses on oil and natural gas derivatives and interest expense on interest rate swaps.

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.

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 principle 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.  The impact on our assets and liabilities related to these derivative financial instruments was not material to our balance sheet.

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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 March 31, 2008, our oil and natural gas and interest rate derivative financial instruments 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 March 31, 2008:

(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(431,598	)	$	—	$	(431,598	)
Interest rate swaps	—		(3,631		)	—		(3,631		)
	$	—	$	(435,229	)	$	—	$	(435,229	)

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 March 31, 2008:

		Weighted
	Volume	average strike		Fair value at
(in thousands, except prices)	Mmbtu/Bbl	price		March 31, 2008
Natural Gas:
Swaps (NYMEX):
Remainder of 2008	80,505	$	8.32	$	(157,334	)
2009	100,530	8.18		(149,764		)
2010	40,748	8.03		(37,808		)
2011	9,125	7.97		(6,282		)
2012	1,830	4.51		(6,356		)
2013	1,825	4.51		(6,069		)
Total Natural Gas	234,563			(363,613		)
Oil:
Swaps (NYMEX):
Remainder of 2008	1,071	68.20		(33,000		)
2009	1,215	69.11		(30,972		)
2010	473	84.85		(4,013		)
Total Oil	2,759			(67,985		)
Total Oil and Natural Gas				$	(431,598	)

In measuring fair value of financial assets and liabilities pursuant to SFAS No. 157, we utilized 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 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 March 31, 2008, the average forward NYMEX oil prices per Bbl for the remainder of 2008 and for 2009 were $99.55 and $95.93, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2008 and for 2009 were $10.30 and $9.75, respectively.

13

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 months ended March 31, 2008, we recognized $3.3 million of additional interest expense on our interest rate swaps.  The impact of SFAS No. 157 was not material to our interest rate swaps.  As of March 31, 2008, the fair value of our interest rate swaps was a liability of $3.6 million.

10.Long-term debt

Long-term debt is summarized as follows:

	December 31,		March 31,
(in thousands)	2007		2008
EXCO credit agreement	$	560,500	$	855,500
EPOP credit agreement	1,083,000		1,168,700
7¼% senior notes due 2011	444,720		444,720
Unamortized premium on 7 1/4 % senior notes due 2011	10,951		10,128
Total	$	2,099,171	$	2,479,048

Credit agreements

EXCO Resources credit agreement

On February 20, 2008, we amended the EXCO Resources credit agreement to reflect the assets acquired in the Appalachian Acquisition.  This amendment to the EXCO Resources credit agreement increased the borrowing base from $900.0 million to $1.2 billion, of which $855.5 million was drawn as of March 31, 2008.  Financial covenants and all other terms, including maturity date, contained within the EXCO Resources credit agreement remained unchanged.

At December 31, 2007 and March 31, 2008, the six month LIBOR rates were 4.6% and 2.6%, respectively, which resulted in interest rates of approximately 5.8% and 3.9%, respectively. At December 31, 2007 and March 31, 2008, we had $560.5 million and $855.5 million, respectively, of outstanding indebtedness under the EXCO Resources credit agreement.  The next scheduled borrowing base redetermination date is October 1, 2008.

EPOP credit agreement

The EPOP credit agreement has a borrowing base of $1.3 billion.  At December 31, 2007 and March 31, 2008, the six month LIBOR rates were 4.6% and 2.6%, respectively, which resulted in interest rates of approximately 6.1% and 4.4%, respectively. At December 31, 2007 and March 31, 2008, we had approximately $1.1 billion and $1.2 billion, respectively, of outstanding indebtedness under the EPOP credit agreement.  The next scheduled borrowing base redetermination date is October 1, 2008.

7¼% senior notes due January 15, 2011

As of March 31, 2008, $444.7 million in principal was outstanding on our 7 ¼% senior notes due January 15, 2011, or Senior Notes. The unamortized premium on the Senior Notes at March 31, 2008 was $10.1 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $433.6 million on March 31, 2008.

11.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 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.

14

In connection with the 2007 mergers discussed above, the consolidating balance sheet as of December 31, 2007 and the consolidated statements of operations and consolidating statements of cash flows for the three months ended March 31, 2007 have been restated to reflect the Guarantor Subsidiaries as if they had been part of Resources for all periods presented.

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.

15

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 BALANCE SHEET

(Unaudited)

March 31, 2008

(in thousands)	Resources			Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	10,419		$	3,380		$	(4,686	)	$	—		$	9,113
Other current assets	47,568			32,577			139,722			—			219,867
Total current assets	57,987			35,957			135,036			—			228,980
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	92,789			61,640			217,637			—			372,066
Proved developed and undeveloped oil and natural gas properties	1,246,790			1,243,591			2,957,240			—			5,447,621
Allowance for depreciation, depletion and amortization	(137,066		)	(98,521		)	(368,819		)	—			(604,406		)
Oil and natural gas properties, net	1,202,513			1,206,710			2,806,058			—			5,215,281
Gas gathering, office and field equipment, net	7,597			52,687			369,959			—			430,243
Advance on pending acquisition	3,500			—			—			—			3,500
Deferred financing costs	7,890			—			12,059			—			19,949
Derivative financial instruments	1,964			—			2,597			—			4,561
Goodwill	110,800			164,469			194,808			—			470,077
Investments in and advances to affiliates	2,373,117			—			—			(2,373,117		)	—
Other assets, net	—			682			2,740			—			3,422
Total assets	$	3,765,368		$	1,460,505		$	3,523,257		$	(2,373,117	)	$	6,376,013
Liabilities and stockholders’ equity
Current liabilities	244,771			47,453			292,645			—			584,869
Long-term debt	1,310,348			—			1,168,700			—			2,479,048
Deferred income taxes	(39,418		)	160,523			—			—			121,105
Other liabilities	100,249			84,141			89,132			—			273,522
Payable to parent	(768,051		)	848,081			(80,030		)	—			—
Commitments and contingencies	—			—			—			—			—
Preferred stock	1,992,278			—			—			—			1,992,278
Stockholders’ equity	925,191			320,307			2,052,810			(2,373,117		)	925,191
Total liabilities and stockholders’ equity	$	3,765,368		$	1,460,505		$	3,523,257		$	(2,373,117	)	$	6,376,013

17

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2007

							Non-
				Guarantor			guarantor
(in thousands)	Resources			subsidiaries			subsidiaries			Eliminations		Consolidated
Revenues and other income:
Oil and natural gas	$	28,928		$	29,300		$	60,267		$	—	$	118,495
Loss on derivative financial instruments	(13,588		)	(22,670		)	(59,761		)	—		(96,019		)
Other income (loss)	9,737			(7,388		)	4,376			—		6,725
Equity in earnings of subsidiaries	(117,943		)	—			—			117,943		—
Total revenues and other income	(92,866		)	(758		)	4,882			117,943		29,201
Costs and expenses:
Oil and natural gas production	6,704			5,454			17,920			—		30,078
Gathering and transportation	144			138			539			—		821
Depreciation, depletion and amortization	12,142			9,898			29,284			—		51,324
Accretion of discount on asset retirement obligations	248			474			221			—		943
General and administrative	7,034			3,039			4,102			—		14,175
Interest	16,702			—			60,007			—		76,709
Total costs and expenses	42,974			19,003			112,073			—		174,050
Income (loss) before income taxes	(135,840		)	(19,761		)	(107,191		)	117,943		(144,849		)
Income tax benefit	(48,143		)	(9,009		)	—			—		(57,152		)
Net income (loss)	(87,697		)	(10,752		)	(107,191		)	117,943		(87,697		)
Preferred stock dividends	1,136			—			—			—		1,136
Net income (loss) available to common shareholders	$	(88,833	)	$	(10,752	)	$	(107,191	)	$	117,943	$	(88,833	)

18

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2008

							Non-
				Guarantor			guarantor
(in thousands)	Resources			subsidiaries			subsidiaries			Eliminations		Consolidated
Revenues and other income:
Oil and natural gas	$	99,789		$	44,614		$	173,287		$	—	$	317,690
Loss on derivative financial instruments	(111,487		)	(26,572		)	(203,135		)	—		(341,194		)
Other income (loss)	7,443			(6,551		)	7,653			—		8,545
Equity in earnings of subsidiaries	(152,370		)	—			—			152,370		—
Total revenues and other income	(156,625		)	11,491			(22,195		)	152,370		(14,959		)
Costs and expenses:
Oil and natural gas production	18,243			7,813			26,425			—		52,481
Gathering and transportation	58			606			2,467			—		3,131
Depreciation, depletion and amortization	25,086			15,184			68,947			—		109,217
Accretion of discount on asset retirement obligations	395			579			342			—		1,316
General and administrative	14,198			3,969			4,460			—		22,627
Interest	19,801			—			16,219			—		36,020
Total costs and expenses	77,781			28,151			118,860			—		224,792
Income (loss) before income taxes	(234,406		)	(16,660		)	(141,055		)	152,370		(239,751		)
Income tax benefit	(71,567		)	(5,345		)	—			—		(76,912		)
Net income (loss)	(162,839		)	(11,315		)	(141,055		)	152,370		(162,839		)
Preferred stock dividends	(35,000		)	—			—			—		(35,000		)
Net income (loss) available to common shareholders	$	(197,839	)	$	(11,315	)	$	(141,055	)	$	152,370	$	(197,839	)

19

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2007

(in thousands)	Resources			Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	5,663		$	19,939		$	6,949		$	—	$	32,551
Investing Activities:
Additions to oil and natural gas properties,
gathering systems and equipment	(19,108		)	(10,764		)	(1,460,078		)	—		(1,489,950		)
Proceeds from dispositions of property and equipment	129,561			—			2,033			—		131,594
Advance on pending acquisition	(43,000		)	—			—			—		(43,000		)
Advances/investments with affiliates	(1,653,258		)	(6,253		)	1,659,511			—
Net cash provided by (used in) investing activities	(1,585,805		)	(17,017		)	201,466			—		(1,401,356		)
Financing Activities:
Borrowings under credit agreements	68,000			—			1,130,000			—		1,198,000
Repayments under credit agreements	(352,000		)	—			(1,320,532		)	—		(1,672,532		)
Proceeds from issuance of common stock	817			—			—			—		817
Proceeds from issuance of preferred stock	2,000,000			—			—					2,000,000
Payments for preferred stock issuance costs	(525		)	—			—			—		(525		)
Deferred financing costs and other	(349		)	—			(9,750		)	—		(10,099		)
Net cash provided by (used in) financing activities	1,715,943			—			(200,282		)	—		1,515,661
Net increase (decrease) in cash	135,801			2,922			8,133			—		146,856
Cash at the beginning of the period	6,522			6,233			10,067			—		22,822
Cash at end of period	$	142,323		$	9,155		$	18,200		$	—	$	169,678

20

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2008

(in thousands)	Resources			Guarantor subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	55,745		$	19,522		$	124,243		$	—	$	199,510
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(420,017		)	(13,730		)	(168,920		)	—		(602,667		)
Proceeds from dispositions of property and equipment	1,073			44			181			—		1,298
Advance on pending acquisition	(3,500		)	—			—			—		(3,500		)
Advances/investments with affiliates	83,291			(9,706		)	(73,585		)	—
Net cash used in investing activities	(339,153		)	(23,392		)	(242,324		)	—		(604,869		)
Financing Activities:
Borrowings under credit agreements	405,000			—			95,700			—		500,700
Repayments under credit agreements	(110,000		)	—			(10,000		)	—		(120,000		)
Settlements of derivative financial instruments with a financing element	7,937			—			2,530			—		10,467
Proceeds from issuance of common stock	3,527			—			—			—		3,527
Payment of preferred stock dividends	(35,000		)	—			—			—		(35,000		)
Deferred financing costs and other	(707		)	—			(25		)			(732		)
Net cash provided by financing activities	270,757			—			88,205			—		358,962
Net decrease in cash	(12,651		)	(3,870		)	(29,876		)	—		(46,397		)
Cash at beginning of the period	23,069			7,250			25,191			—		55,510
Cash at end of period	$	10,418		$	3,380		$	(4,685	)	$	—	$	9,113

21

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

Forward-looking statements

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

·impacts of our March 2007 private placement of preferred stock and the impact of dividends on our capital resources and liquidity;

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

·availability of drilling and production equipment;

22

·marketing of oil and natural gas;

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

·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 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

23

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 for the next three years to mitigate the impact of price volatility on our oil and natural gas reserves.

The volatility of 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. 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, as amended in March 2008, totals $800.0 million, which includes $763.0 million for drilling, exploitation and production operations, $19.0 million for midstream projects and $18.0 million for corporate projects.  The increase in the upstream operations capital expenditure budget reflects expected significant acreage acquisitions and drilling in 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 also plan to seek Board approval for an increase in our capital budget for acreage acquisition and drilling in the Haynesville shale in East Texas/North Louisiana. 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 Gathering System Acquisition, for approximately $55.6 million, net of preliminary purchase price adjustments.

We continue to face the challenge of financing future acquisitions. In connection with our 2007 and 2008 acquisitions, we amended our credit agreements to increase our borrowing capacity to an aggregate of approximately $2.5 billion as of March 31, 2008.  The credit agreement of our wholly-owned unrestricted subsidiary, EXCO Partners Operating Partnership, or EPOP, which holds all of our assets located in East Texas/North Louisiana, or the EPOP Credit Agreement, provides for an aggregate borrowing base of $1.3 billion, of which approximately $1.2 billion and $1.1 billion was drawn as of March 31, 2008 and May 1, 2008, respectively. The EXCO Resources credit agreement as amended and restated on March 20, 2008, or the EXCO Resources Credit Agreement, to reflect the Appalachian Acquisition, increased the borrowing base to approximately $1.2 billion.  As of March 31, 2008, outstanding borrowings on the EXCO Resources Credit Agreement were $855.5 million and $1.0 billion as of May 1, 2008. With these credit agreements, we believe our unused borrowing capacity as of May 1, 2008 of approximately $365.2 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, the 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.

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.

Our results of operations

A summary of key financial data for the three months ended March 31, 2007 and 2008 related to our results of operations is presented below:

	Three months ended						Quarter to
	March 31,						quarter change
(dollars in thousands, except prices and per unit expenses)	2007			2008			2007 - 2008
Production:
Oil (Mbbls)	275			507			232
Natural gas (Mmcf)	15,663			32,049			16,386
Total production (Mmcfe)	17,313			35,091			17,778
Oil and natural gas revenues before derivative financial instrument activities:
Oil revenues	$	15,105		$	49,017		$	33,912
Natural gas sales	103,390			268,673			165,283
Total oil and natural gas sales	$	118,495		$	317,690		$	199,195
Other income:
Pipeline and marketing	$	5,345		$	7,427		$	2,082
Interest and other	1,380			1,118			(262		)
Total other income	$	6,725		$	8,545		$	1,820
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	32,073		$	3,015		$	(29,058	)
Non-cash change in fair value of derivative financial instruments	(128,092		)	(344,209		)	(216,117		)
Total derivative financial instrument activities	$	(96,019	)	$	(341,194	)	$	(245,175	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (Bbl)	$	54.93		$	96.68		$	41.75
Natural gas (per Mcf)	6.60			8.38			1.78
Natural gas equivalent (per Mcfe)	6.84			9.05			2.21
Oil and natural gas production costs:
Oil and natural gas operating costs	$	21,702		$	33,171		$	11,469
Gathering and transportation	821			3,131			2,310
Production and ad valorem taxes	8,376			19,310			10,934
Depletion	48,416			103,912			55,496
Depreciation and amortization	2,908			5,305			2,397
General and administrative	14,175			22,627			8,452
Interest expense, including impacts of interest rate swaps	76,709			36,020			(40,689		)
Oil and natural gas production costs (per Mcfe):
Oil and natural gas operating costs	$	1.25		$	0.95		$	(0.30	)
Gathering and transportation	0.05			0.09			0.04
Production and ad valorem taxes	0.48			0.55			0.07
Depletion	2.80			2.96			0.16
Depreciation and amortization	0.17			0.15			(0.02		)
General and administrative	0.82			0.64			(0.18		)
Net loss	$	(87,697	)	$	(162,839	)	$	(75,142	)

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The following is a discussion of our financial condition and results of operations for the three months ended March 31, 2007 and 2008.

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

·property acquisitions in the Vernon Field of Louisiana, or the Vernon Acquisition, on March 30, 2007, properties located in the Mid-Continent region in May 2007, or the Southern Gas 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 the Vernon Acquisition, the Southern Gas Acquisition and the Appalachian Acquisition;

·changes in proved reserves and their impact on depletion;

·fluctuations in prices of oil and natural gas due to the use of mark-to-market accounting for our derivative financial instruments; and

·fluctuations in oil and natural gas prices which impact our oil and natural gas reserves, revenues and ceiling test results and our derivative financial instruments.

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:

·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

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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 March 31, 2008, we reported a net loss available to common shareholders of $197.8 million compared to a net loss available to common shareholders of $88.8 million for the quarter ended March 31, 2007.

The impact of the Vernon Acquisition, the Southern Gas Acquisition and other acquisitions in 2007 increased our production, revenues, operating expenses and general and administrative expenses when compared to the prior year. Derivative financial instruments also have a significant impact on our results of operations, as we do not designate our derivative financial instruments as hedges. As a result, we mark the non-cash changes in the fair value of our derivatives to market at the end of each reporting period, which can cause our reported net income to fluctuate dramatically when oil and natural gas prices experience significant increases, as was the case in the first quarter of 2008, or significant decreases.  While net income is affected by this mark-to-market treatment, a substantial portion of these gains or losses are non-cash so the impact on our capital resources and liquidity is typically minimal. For the three months ended March 31, 2007, we incurred losses from our derivative financial instruments of $96.0 million, representing income from cash settlements of $32.1 million and $128.1 million of unrealized losses.  For the three months ended March 31, 2008, we recognized losses of $341.2 million on our derivative financial instruments, representing income from cash settlements of $3.0 million and $344.2 million of unrealized losses.

Total revenues

Our total revenues are comprised of sales of oil and natural gas, settlements and changes in the fair value of our derivative financial instruments and other income.  Due to significant increases in the prices of oil and natural gas during the first quarters of 2007 and 2008 our changes in the fair value of our derivative financial instruments resulted in negative revenue adjustments of $96.0 million and $341.2 million for the three months ended March 31, 2007 and 2008, respectively.  For the first quarter of 2008, the impact of our derivative financial instruments resulted in our total revenues being a negative $15.0 million.  The $341.2 million negative adjustment for the 2008 quarter includes $3.0 million of cash received from our counterparties to settle derivatives and $344.2 million of non-cash changes in the fair value of our derivative financial instruments.  Excluding the non-cash components resulting from mark-to-market changes in the fair value of our derivative financial instruments, our total revenues for the three months ended March 31, 2007 and 2008 were $157.3 million and $329.3 million, respectively.

Oil and natural gas revenues, production and prices

For the three months ended March 31, 2008, total oil and natural gas revenues, excluding the impact of derivative financial instruments, were $317.7 million, a 168.1% increase over the three months ended March 31, 2007 total oil and natural gas revenues of $118.5 million. Total equivalent production volumes were 35.1 Bcfe for the three months ended March 31, 2008, a 102.7% increase over the prior years comparable period production of 17.3 Bcfe. The increased volumes are primarily attributable to the Vernon Acquisition and the Southern Gas Acquisition, with a smaller contribution from the Appalachian Acquisition. The increased volumes from acquisitions were partially offset by property sales of our Cement

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field and other divestitures.  The increase in production volumes for the three months ended March 31, 2008 compared to the same period in 2007 is presented below:

·the Vernon Acquisition which closed on March 30, 2007, produced 11.4 Bcfe for the three months ended March 31, 2008 compared with 0.3 Bcfe in the prior year’s quarter, an increase of 11.1 Bcfe;

·the Southern Gas Acquisition which closed on May 2, 2007, contributed an increase of 4.3 Bcfe for the three months ended March 31, 2008;

·increased volumes of 1.1 Bcfe from our incremental acquisitions in the Sugg Ranch area in West Texas;

·organic growth from our drilling and other producing regions of approximately 1.9 Bcfe; and

·the Appalachian Acquisition on February 20, 2008, which increased production by 0.6 Bcfe in our Appalachian region.

The aforementioned increases were partially offset by reduced volumes of 1.2 Bcfe resulting from sales of producing properties during 2007, particularly from the Cement Field in Oklahoma.

The average sales price, excluding the impact of derivative financial instruments, increased for oil during the three months ended March 31, 2008 compared to the three months ended March 31, 2007 by $41.75 per Bbl (to $96.68 from $54.93) or 76.0%. The average natural gas sales prices, excluding the impact of derivative financial instruments, were $8.38, an increase of 27.0% for the three months ended March 31, 2008 compared with $6.60 per Mcf for the three months ended March 31, 2007.

Derivative financial instruments

We use oil and natural gas derivatives and financial risk management instruments to manage 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 interest expense on financial risk management instruments.

Our cash settlements from derivative financial instruments increased revenue by $3.0 million for the three months ended March 31, 2008 compared with an increase of $32.1 million from cash settlements for the three months ended March 31, 2007.

For the three months ended March 31, 2008, we recognized a decrease in revenue of $344.2 million from the change in the fair value of our oil and natural gas derivative financial instruments.  For the three months ended March 31, 2007, we recognized a decrease in revenue of $128.1 million from the change in the fair value of our oil and natural gas derivative financial instruments. We expect that our revenues will continue to be significantly impacted in future periods by changes in the fair value of our derivative financial instruments as a result of the volatility in oil and natural gas prices.  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% 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:

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	Three months ended
	March 31,
(in thousands)	2007			2008
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	32,073		$	3,015
Non-cash change in fair value of derivative financial instruments	(128,092		)	(344,209		)
Total oil and natural gas derivative loss on financial instruments	$	(96,019	)	$	(341,194	)
Interest rate swaps:
Interest rate swaps settlement receipts	$	—		$	378
Fair market value adjustment on interest rate swaps	—			(3,631		)
Total interest rate swaps	$	—		$	(3,253	)

Other income

Our other income increased to $8.5 million for the three months ended March 31, 2008 from $6.7 million for the same period in the prior year. Our income from natural gas gathering and transportation activities for the three month period ended March 31, 2008 increased approximately $2.1 million when compared to the same period in the prior year, which is due primarily to mid-stream activities from the Vernon Acquisition which closed in March 2007. We closed an acquisition of a gathering system in March 2008 and are constructing an extension to our existing pipeline system which we expect to begin a portion of operations during the second quarter of 2008 and become fully operational by the end of 2008.  We anticipate this recent acquisition, combined with additional third party throughput from the pipeline extension to increase our other income from our gathering and transportation assets in the upcoming quarters.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three months ended March 31, 2008 increased $11.5 million, or 52.8% from the same period in 2007. The increase in oil and natural gas operating costs was primarily attributable to:

·the Vernon Acquisition, which closed on March 30, 2007, added production expenses of $3.7 million for the three months ended March 31, 2008 when compared to an insignificant amount of expenses during the same period in 2007;

·the Southern Gas Acquisition, which closed on May 2, 2007, added $5.3 million of production expenses for the three months ended March 31, 2008;

·the Appalachian Acquisition on February 20, 2008, added $0.6 million of production expenses for the three months ended March 31, 2008;

·increased production expenses of approximately $1.2 million in our Sugg Ranch area primarily due to the acquisition of incremental working interests in that area;

·$1.0 million of non-cash stock-based compensation expenses;

·a general increase in the cost of goods and services used in our oil and natural gas operations; and

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

The oil and natural gas operating costs per unit decreased from $1.25 per Mcfe for the three months ended March 31, 2007 to $0.95 per Mcfe, or 24%, for the three months ended March 31, 2008.  This decrease in operating costs per unit reflects the impact of significant volumes from the Vernon Acquisition, which has relatively low operating expenses.  This per unit decrease in operating costs is partially offset by the general increase in the costs of goods and services used in our operations and an increase in workover activities.

Gathering and transportation

We generally sell oil and natural gas under two types of agreements which are common in our industry.  Both types

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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.  Transportation and gathering expenses totaled $3.1 million for the three months ended March 31, 2008 and $0.8 million for the three months ended March 31, 2007, or $0.09 and $0.05 per Mcfe, respectively.  As our marketing efforts expand, our total gathering and transportation expenses will also increase.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended March 31, 2008 increased by $10.9 million, or 130.5%, over the same period in 2007. This increase is primarily attributable to higher oil and natural gas volumes and prices resulting from acquisitions and our organic growth. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 6.1% of gross oil and natural gas sales for the three months ended March 31, 2008, compared with 7.1% during the same period 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 and ad valorem tax rate in Louisiana impacted our consolidated 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 costs for the three months ended March 31, 2008 increased by $55.5 million, or 114.6%, from the same period in 2007. The primary reason for the increase was a 102.7% increase in oil and natural gas sales volumes for the three months ended March 31, 2008.  This increase was directly related to the Vernon Acquisition and the Southern Gas Acquisition which caused an increase in the per unit depletion rate from $2.80 per Mcfe for the three months ended March 31, 2007 to $2.96 per Mcfe for the three months ended March 31, 2008.

Depreciation and amortization

Our depreciation and amortization costs for the three months ended March 31, 2008 increased by $2.4 million, or 82.4%, from the same period in 2007. The primary reason for the increase was from the increase in our depreciable asset base for the three months ended March 31, 2008, which was directly related to our 2007 acquisitions.

General and administrative

Our general and administrative costs for the three months ended March 31, 2008 was $22.6 million, or $0.64 per Mcfe compared to $14.2 million, or $0.82 per Mcfe for the same period in 2007, an increase of $8.5 million, or 59.6%. Significant components of the increase include the following items:

·increased personnel costs of $6.1 million due to additional headcount of 227 employees related primarily to our acquisitions;

·an increase in share-based compensation costs of $0.1 million due primarily to additional headcount;

·increased consulting and contract labor costs of $0.5 million due primarily to acquisitions and Sarbanes-Oxley compliance;

·increased information technology related costs of $0.9 million primarily due to the information technology requirements attributable to our increased headcount;

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·increased legal fees, including $3.7 million attributable to our proposed master limited partnership offering, which was withdrawn in January 2008;

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

·increased franchise tax of $1.0 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 $5.7 million for the three months ended March 31, 2008, a $2.8 million increase from the same period in the prior year.  Additionally, we capitalized approximately $2.2 million in salary costs to our full cost pool, which was $1.3 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 Vernon Acquisition and the Southern Gas Acquisition.

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

	For the three months ended
	March 31,
(in thousands)	2007			2008
Gross general and administrative expenses	$	18,048		$	30,521
Capitalized general and administrative expenses	(966		)	(2,219		)
Reimbursed general and administrative expenses	(2,907		)	(5,675		)
Net general and administrative expenses	$	14,175		$	22,627

Interest expense

Our interest expense for the three months ended March 31, 2008 decreased $40.7 million from the same period in 2007. The decrease is primarily due to the one-time charges taken in 2007 that were associated with the amended credit agreements used to fund the Vernon Acquisition and the Southern Gas Acquisition.  The following table presents the components of our interest expense:

	Three months ended
	March 31,
(in thousands)	2007		2008
Interest expense:
7 1/4% senior notes due 2011	$	7,289	$	7,238
EXCO Credit Agreement	6,302		9,263
EPOP Credit Agreement	11,504		14,566
EPOP term loan	18,049		—
Amortization of deferred financing costs on EXCO Credit Agreement	2,989		476
Amortization and write-off of deferred financing costs on EPOP loans	29,111		753
Interest rate swaps settlements	—		(378		)
Fair market value adjustment on interest rate swaps	—		3,631
Other interest expense	1,465		471
Total interest expense	$	76,709	$	36,020

Income taxes

Our effective income tax rate for the three months ended March 31, 2008 was a benefit of 32.1%. Our effective income tax rate for the three months ended March 31, 2007 was a benefit of 39.5%. A substantial portion of our stock-based compensation included in our results of operations for the three months ended March 31, 2008 are in the form of incentive stock options which are not deductible for tax purposes until a disqualifying event occurs. The decrease in the tax rate from the prior year is a result of changes in the jurisdictional make up of our state income taxes and the impact of incentive stock options (including disqualifying dispositions).

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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 May 1, 2008, the aggregate borrowing base under our credit agreements totaled approximately $2.5 billion, of which $2.1 billion was outstanding. We do not have a set budget for acquisitions, as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit 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 $199.5 million for the three months ended March 31, 2008 compared with $32.6 million for the three months ended March 31, 2007. The increase is attributable primarily to net cash provided from the oil and natural gas properties acquisitions which were partially offset by higher interest costs. At March 31, 2008, our cash and cash equivalents balance was $9.1 million, a decrease of $46.4 million from December 31, 2007 primarily as a result of payments to reduce debt. On January 15, 2008, we made an interest payment on our Senior Notes of $16.1 million and we made a dividend payment to our preferred shareholders of $35.0 million on March 14, 2008.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the three months ended March 31, 2007 and 2008.

	Three months ended
	March 31,
(in thousands)	2007		2008
Capital expenditures:
Property acquisitions	$	1,447,281	$	470,186
Lease purchases	7,619		10,288
Development capital expenditures	75,892		152,159
Corporate and other	3,037		21,533
Total capital expenditures	$	1,533,829	$	654,166

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.

For the year 2008, we have budgeted capital expenditures of approximately $800.0 million for our development, exploitation and exploration activities, of which $184.0 million was spent during the three months ended March 31, 2008, exclusive of property acquisitions. As of March 31, 2008, we were contractually obligated to spend approximately $90.2 million for our development, exploitation and exploration activities for the remainder of 2008.

We expect to utilize our current cash balance, cash flow from operations and available funds under our credit agreements to fund our acquisitions, capital expenditures and working capital. In order to meet strategic objectives, we may also sell assets to provide liquidity.

We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreements are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes and oil and natural gas prices. If cash flows decline we 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 tubular goods and for certain services during 2007 and 2008. Further, we have encountered difficulties in contracting for drilling rigs and other services due to high demand. Currently, we

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do not believe that these conditions have had a significant impact upon our capital expenditures programs or our results of operations. If the conditions continue, however, projects may be delayed due to lack of services or materials or we may have to delay projects to stay within our capital budget.

7¼% senior notes due January 15, 2011

As of March 31, 2008, $444.7 million in principal was outstanding on our 7 ¼% senior notes due January 15, 2011, or Senior Notes. The unamortized premium on the Senior Notes at March 31, 2008 was $10.1 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $433.6 million on March 31, 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.

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 second amendment to our Amended and Restated Credit Agreement.  The primary change to the EXCO Credit Agreement included 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.  Financial covenants and all other terms, including maturity date, contained within the EXCO 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 next scheduled borrowing base redetermination date is October 1, 2008. The interest rate ranges from LIBOR plus 100 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 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 the 2009 - 2011 years.  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

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Agreement. As of March 31, 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 3.5 to 1.0 at the end of any fiscal quarter ending on or after September 30, 2007; 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 May 1, 2008, the six month LIBOR rate was 2.9%, which would result in an interest rate of approximately 4.2% on any new indebtedness we may incur under the EXCO Resources Credit Agreement. At May 1, 2008 we had $1.0 billion of outstanding indebtedness under the EXCO Resources Credit Agreement.

EPOP Credit Agreement

The EPOP Credit Agreement has a borrowing base of $1.3 billion. The borrowing base is scheduled to be redetermined on a semi-annual basis, with EPOP 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 next scheduled borrowing base redetermination date is October 1, 2008.The EPOP Credit Agreement is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EPOP. EPOP 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 - 2011. The foregoing description is not complete and is qualified in its entirety by the EPOP Credit Agreement. As of March 31, 2008, EPOP was in compliance with the financial covenants contained in the EPOP Credit Agreement, which require that EPOP:

·maintain a consolidated current ratio (as defined under the EPOP Credit Agreement) 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 under the EPOP Credit Agreement) 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 under the EPOP Credit Agreement) 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 EPOP Credit Agreement contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Credit Agreement matures March 30, 2012. Interest under the EPOP Credit Agreement ranges from LIBOR plus 100 basis points (bps) to 175 bps ABR, as defined, ranging from ABR plus 0 bps to ABR plus 75 bps.

At May 1, 2008, the six month LIBOR rate was 2.9%, which would result in an interest rate of approximately 4.7% on any new indebtedness we may incur under the EPOP Credit Agreement. At May 1, 2008 we had $1.1 billion of outstanding indebtedness under the EPOP Credit Agreement.

Preferred stock

The 7.0% Preferred Stock and Hybrid Preferred Stock were issued in several series at a purchase price of $10,000 per share on March 30, 2007.  The 7.0% Preferred Stock and the Hybrid Preferred Stock are convertible into common stock at any time by the holder at a price of $19.00 per share, as may be adjusted.  We may force the conversion of the 7.0% Preferred Stock and the Hybrid Preferred Stock at any time if the common stock trades 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 current conversion price of $19.00 per share) at any time during the 24 months after issuance, (ii) above 150% of the then effective conversion

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price ($28.50 per share at the current conversion price of $19.00 per share) thereafter through the 48^th month after issuance and (iii) above 125% of the then effective conversion price ($23.75 per share at the current conversion price of $19.00 per share) at any time thereafter. Cash dividends will accrue at the rate of 7.0% per annum prior to March 30, 2013 and at the rate of 9.0% per annum thereafter. In lieu of paying cash dividends, we may, under certain circumstances prior to March 30, 2013, pay dividends at a rate of 9.0% per annum by adding the dividends to the liquidation preference of the shares of preferred stock. Upon the occurrence of a change of control, holders of our preferred stock may require us to repurchase their shares for cash at the liquidation preference plus accumulated dividends. Holders of our preferred stock have 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 7.0% Preferred Stock and Hybrid Preferred Stock have 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 7.0% Preferred Stock and the Hybrid Preferred Stock, the holders of the 7.0% Preferred Stock and Hybrid Preferred Stock, voting together as a class, have the right to elect four additional directors, or default directors, until such default is cured.

As of March 31, 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 dividends totaling $35.0 million on March 14, 2008 to the holders of our preferred stock. We have accrued dividends of $5.8 million as of March 31, 2008. As a result of the of the shareholder vote in 2007 in favor of the transformation of the Hybrid Preferred Stock into terms identical to the 7.0% Preferred Stock, the annual dividend requirement on the Hybrid Preferred Stock and the 7.0% Preferred Stock is $140.0 million per annum.

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 March 31, 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):
Q2 2008	26,695	$	8.27	355	$	68.23
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		—	—

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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 months ended March 31, 2008, we had $3.6 million of unrealized losses on our interest rate swaps.

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at March 31, 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)	—		—		855,500		—		855,500
Long-term debt - EPOP Credit Agreement (3)	—		—		1,168,700		—		1,168,700
Operating leases (4)	16,277		8,486		4,944		1,161		30,868
Pending property and lease acquisition commitments (5)	31,500		—		—		—		31,500
Drilling/work commitments	23,988		10,035		—		—		34,023
Total contractual cash obligations (6)	$	71,765	$	463,241	$	2,029,144	$	1,161	$	2,565,311

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

(2)The EXCO Resources Credit Agreement matures on March 30, 2012.

(3)The EPOP Credit Agreement matures on March 30, 2012.

(4)Excludes month-to-month rental expense on compressors.

(5)Represents an executed purchase and sale agreement, dated March 11, 2008, to purchase oil and natural gas properties and other undeveloped lease acquisitions.

(6)Excludes annual dividends of $140.0 million on our 7.0% Preferred and Hybrid Preferred Stock.  Such dividends are      payable when, and as, declared by the Board of Directors.

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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 March 31, 2008.

		Weighted
	Volume	average strike		Fair value at
(in thousands, except prices)	Mmbtu/Bbl	price		March 31, 2008
Natural Gas:
Swaps (NYMEX):
Remainder of 2008	80,505	$	8.32	$	(157,334	)
2009	100,530	8.18		(149,764		)
2010	40,748	8.03		(37,808		)
2011	9,125	7.97		(6,282		)
2012	1,830	4.51		(6,356		)
2013	1,825	4.51		(6,069		)
Total Natural Gas	234,563			(363,613		)
Oil:
Swaps (NYMEX):
Remainder of 2008	1,071	68.20		(33,000		)
2009	1,215	69.11		(30,972		)
2010	473	84.85		(4,013		)
Total Oil	2,759			(67,985		)
Total Oil and Natural Gas				$	(431,598	)

At March 31, 2008, the average forward NYMEX oil prices per Bbl for the remainder of 2008 and for calendar year 2009 were $99.55 and $95.93, respectively and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2008 and for calendar 2009 were $10.30 and $9.75, respectively.

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 March 31, 2008, for the remainder of 2008, if the settlement price exceeds the actual weighted average strike price of $68.20, then a reduction in oil and natural gas revenue would be recorded for the difference between the settlement price and $68.20, multiplied by the hedged volume of 1,071 Mbbls. Conversely, if the settlement price is less than $68.20, then an increase in oil and natural gas revenue would be recorded for the difference between the settlement price and $68.20, multiplied by the hedged volume of 1,071 Mbbls. For example, for a hedged volume of 1,071 Mbbls, if the settlement price is $69.20, then oil and natural gas revenue would decrease by $1.1 million. Conversely, if the settlement price is $67.20, oil and natural gas revenue would increase by $1.1 million.

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Interest rate risk

At March 31, 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 71/4% on the $444.7 million in Senior Notes we have outstanding. Interest is payable on borrowings under our credit agreements 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 March 31, 2008, we had $2.0 billion in outstanding borrowings under our credit agreements. A 1% change in interest rates based on the borrowings as of March 31, 2008 would result in an increase or decrease in our interest costs of $20.2 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%.  During the three months ended March 31, 2008, we had $3.6 million of unrealized losses on our interest rate swaps.

Preferred stock liquidated damages risk

In connection with the Private Placement, we entered into a registration rights agreement, or 7.0% Registration Rights Agreement, with the Preferred Stock investors. If any shares of 7.0% Preferred Stock or Hybrid Preferred Stock are outstanding on March 30, 2011, we agreed to file a registration statement with the SEC by June 28, 2011 registering such shares for resale and to use our best efforts to have such registration statement declared effective by September 26, 2011.

If we are unable to meet the registration deadlines described above, if a registration statement ceases to remain effective or if we restrict sales under a registration statement under certain “blackout provisions” for longer than the contractually permitted period, we must pay liquidated damages at a rate of 0.5% per annum of the Preferred Stock liquidation preference for the first 90 days and thereafter for each subsequent 90-day period at an additional rate of 0.25% up to a maximum of 2.0% per annum during any default period.  If we become obligated to pay the aforementioned liquidated damages under the 7.0% Registration Rights Agreement, the initial 0.5% increase of liquidated damages would be approximately $2.5 million for the first 90 days and an additional $1.3 million for each successive 90 day period. The maximum amount of potential liquidated damages under the 7.0% Registration Rights Agreement would total $40.0 million per annum.

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 March 31, 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 are scheduled to be dismissed with prejudice. This settlement is awaiting a hearing and final approval by the federal district court before a dismissal can be entered.

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:  May 7, 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.

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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, 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.

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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 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.

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10.7	Amended and Restated Credit Agreement, dated as of March 17, 2006, among EXCO Resource, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Manager, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 17, 2006 and filed on March 23, 2006 and incorporated by reference herein.
10.8	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.*
10.9	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.*
10.10	Form of Nonqualified 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.*
10.11	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.*
10.12	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.
10.13	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.
10.14	Payment Performance Guaranty, dated July 22, 2006, by and between Progress Fuels Corporation and EXCO Resources, Inc., filed as an exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 24, 2006 and incorporated by reference herein.
10.15	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.
10.16	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.
10.17	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.
10.18	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.

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10.19	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.
10.20	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.*
10.21	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.
10.22	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.
10.23	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.
10.24	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.
10.25	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.
10.26	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.
10.27	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.
10.28	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.*
10.29	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.
10.30	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.

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10.31	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.
10.32	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.
10.33	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.
10.34	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.
10.35	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.
10.36	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.
10.37	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.
10.38	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.
10.39	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.
10.40	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.
10.41	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.
10.42	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.

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10.43	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.
10.44	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.
10.45	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.
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 as an Exhibit to EXCO’s Registration Statement on Form S-1 Amendment No. 3 filed February 6, 2006 and incorporated by reference herein.

* These exhibits are management contracts.

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