Exco Resources (EXCO) 10-Q 2009 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, 2009

OR

¨ 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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files).

YES  ¨    NO  ¨

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

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

YES  ¨    NO  x

The number of shares of common stock, par value $0.001 per share, outstanding as of April 30, 2009 was 211,063,818.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at March 31, 2009 and December 31, 2008	3
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008	5
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2009 and 2008	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	47
PART II.	OTHER INFORMATION	48
Item 6.	Exhibits	48
	Signatures	48
	Index to Exhibits	49

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	March 31, 2009			December 31, 2008
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	45,508		$	57,139
Accounts receivable:
Oil and natural gas		89,133			130,970
Joint interest		19,398			22,807
Interest and other		7,046			5,895
Inventory		60,189			42,479
Derivative financial instruments		355,093			247,614
Other		5,712			6,136
Total current assets		582,079			513,040
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		473,200			481,596
Proved developed and undeveloped oil and natural gas properties		2,423,937			3,578,344
Accumulated depletion		(1,011,072	)		(936,088	)
Oil and natural gas properties, net		1,886,065			3,123,852
Gas gathering assets		498,965			485,201
Accumulated depreciation and amortization		(36,811	)		(32,232	)
Gas gathering assets, net		462,154			452,969
Office and field equipment, net		25,910			25,647
Derivative financial instruments		192,281			173,003
Deferred financing costs, net		55,717			62,884
Other assets		2,457			880
Goodwill		470,077			470,077
Total assets	$	3,676,740		$	4,822,352

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	March 31, 2009			December 31, 2008
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	126,094		$	172,400
Accrued interest payable		9,664			28,746
Revenues and royalties payable		88,424			108,130
Income taxes payable		160			160
Current portion of asset retirement obligations		1,748			1,830
Current maturities of long-term debt		300,000			—
Derivative financial instruments		5,329			11,607
Total current liabilities		531,419			322,873
Long-term debt, net of current maturities		2,753,825			3,019,738
Asset retirement obligations and other long-term liabilities		127,101			125,279
Deferred income taxes		10,427			9,371
Derivative financial instruments		16,884			12,590
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; authorized shares - 10,000,000; none issued and outstanding		—			—
Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 211,029,417 at March 31, 2009 and 210,968,931 at December 31, 2008		211			211
Additional paid-in capital		3,074,960			3,070,766
Accumulated deficit		(2,838,087	)		(1,738,476	)
Total shareholders’ equity		237,084			1,332,501
Total liabilities and shareholders’ equity	$	3,676,740		$	4,822,352

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended March 31,
(in thousands, except per share data)	2009			2008
Revenues:
Oil and natural gas	$	172,208		$	324,843
Midstream		17,013			7,892
Total revenues		189,221			332,735
Costs and expenses:
Oil and natural gas production		53,118			52,381
Midstream operating expenses		18,450			8,027
Gathering and transportation		3,897			3,131
Depreciation, depletion and amortization		81,794			109,217
Write-down of oil and natural gas properties		1,293,579			—
Accretion of discount on asset retirement obligations		2,071			1,316
General and administrative		20,547			22,627
Total costs and expenses		1,473,456			196,699
Operating income (loss)		(1,284,235	)		136,036
Other income (expense):
Interest expense		(36,132	)		(36,020	)
Gain (loss) on derivative financial instruments		221,384			(341,194	)
Other income		427			1,427
Total other income (expense)		185,679			(375,787	)
Loss before income taxes		(1,098,556	)		(239,751	)
Income tax expense (benefit)		1,055			(76,912	)
Net loss		(1,099,611	)		(162,839	)
Preferred stock dividends		—			(35,000	)
Net loss available to common shareholders	$	(1,099,611	)	$	(197,839	)
Earnings (loss) per common share:
Basic and diluted
Net loss available to common shareholders	$	(5.21	)	$	(1.89	)
Weighted average number of common shares outstanding		210,995			104,683

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended March 31,
(in thousands)	2009			2008
Operating Activities:
Net loss	$	(1,099,611	)	$	(162,839	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		81,794			109,217
Stock option compensation expense		3,223			3,004
Write-down of oil and natural gas properties		1,293,579			—
Accretion of discount on asset retirement obligations		2,071			1,316
Non-cash change in fair value of derivatives		(128,741	)		347,840
Cash settlements of assumed derivatives		(37,616	)		(10,467	)
Deferred income taxes		1,055			(76,912	)
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt		11,758			406
Loss on sale of fixed assets		—			31
Effect of changes in:
Accounts receivable		43,862			(38,133	)
Other current assets		(1,152	)		2,389
Accounts payable and other current liabilities		(64,896	)		23,658
Net cash provided by operating activities		105,326			199,510
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(189,992	)		(253,782	)
Property and Midstream acquisitions		—			(348,885	)
Advance on pending acquisition		—			(3,500	)
Proceeds from disposition of property and equipment and other		5,477			1,298
Net cash used in investing activities		(184,515	)		(604,869	)
Financing Activities:
Borrowings under credit agreements		34,963			500,700
Repayments under credit agreements		—			(120,000	)
Proceeds from issuance of common stock		447			3,527
Payment of preferred stock dividends		—			(35,000	)
Settlements of derivative financial instruments with a financing element		37,616			10,467
Deferred financing costs		(5,468	)		(732	)
Net cash provided by financing activities		67,558			358,962
Net decrease in cash		(11,631	)		(46,397	)
Cash at beginning of period		57,139			55,510
Cash at end of period	$	45,508		$	9,113
Supplemental Cash Flow Information:
Interest paid	$	48,933		$	38,627
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	507		$	675
Capitalized interest	$	1,361		$	—
Issuance of common stock for director services	$	17		$	82

See accompanying notes.

6

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common Stock			Additional paid-in capital		Retained earnings (deficit)			Total shareholders’ equity
(in thousands)	Shares	Amount
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
Balance at December 31, 2008	210,969	$	211	$	3,070,766	$	(1,738,476	)	$	1,332,501
Issuance of common stock	60		—		464		—			464
Share-based compensation	—		—		3,730		—			3,730
Net loss	—		—		—		(1,099,611	)		(1,099,611	)
Balance at March 31, 2009	211,029	$	211	$	3,074,960	$	(2,838,087	)	$	237,084

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. In addition to our oil and natural gas producing operations, we have midstream operations in the East Texas/North Louisiana area. Our assets in East Texas/North Louisiana are owned by our subsidiary, EXCO Operating Company, LP (formerly EXCO Partners Operating Partnership, LP), and its subsidiaries and together they are collectively referred to as EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt.

The accompanying condensed consolidated balance sheets as of March 31, 2009 and December 31, 2008, statements of operations, statements of cash flows and changes in shareholders’ equity for the three months ended March 31, 2009 and 2008, are for EXCO and its subsidiaries. The consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America, or GAAP, and therefore, all intercompany transactions have been eliminated.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the 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, 2009 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 GAAP 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, 2008.

Prior to and for the three months ended March 31, 2008, we reported the net results of our midstream operations as a component of other income. Beginning in the second quarter of 2008, we made a strategic shift in the focus on and allocation of resources to our midstream division, primarily as a result of midstream asset acquisitions, which significantly increased our third party natural gas purchases and gathering and transportation throughput. We also increased emphasis on capital projects specifically designed to grow the midstream segment of our business. Our consolidated statements of operations now present midstream revenues and operating expenses along with oil and natural gas revenues and operating expenses. We have reclassified prior year amounts related to our midstream segment to conform to current year reporting. We have also reclassified our derivative financial instrument activities and other income items to the other income (expense) caption on our consolidated statements of operations. Previously, we reported these items as a component of revenues.

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

2. Recent accounting pronouncements

On April 9, 2009, the Financial Accounting Standards Board, or the FASB, issued Staff Position FAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 amends Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. The staff position also amends APB Opinion No. 28, “Interim Financial Reporting” to require fair value disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 are effective for interim periods ending after June 15, 2009. Adoption of FSP FAS 107-1 and APB 28-1 will not affect our financial position, operating results or cash flows.

On April 1, 2009, the FASB issued FASB Staff Position No. 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” or FSP 141(R)-1. FSP 141(R)-1 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business

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Combinations,” or SFAS No. 141, to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the pronouncement upon issuance. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “–Note 8. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:

• Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

• Permits the use of new technologies for determining oil and natural gas reserves;

• Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

• Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

• Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

• Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

We are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and disclosures.

3. 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, 2008.

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4. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2009:

(in thousands)
Asset retirement obligation at January 1, 2009	$	120,671
Activity during the three months ended March 31, 2009:
Liabilities incurred during the period		238
Liabilities settled during the period		(569	)
Accretion of discount		2,071
Asset retirement obligations at March 31, 2009		122,411
Less current portion		1,748
Long-term portion	$	120,663

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

5. Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives; the full cost method or the successful efforts method. 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 $473.2 million and $481.6 million as of March 31, 2009 and December 31, 2008, respectively, are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to the depletable full cost pool as a result of extensions or discoveries from drilling operations. We expect these costs to be evaluated in one to ten years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs related to Proved Reserves are divided by the total quantities of Proved Reserves to determine the unit amortization rate. 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 full cost ceiling, computed as the sum of the estimated future net revenues from our Proved Reserves using current period-end prices discounted at 10%, and 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 based on price changes that occur after the balance sheet date to assess impairment as currently permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results.

For the three months ended March 31, 2009, we recognized a ceiling test write-down of $1.3 billion to our proved oil and natural gas properties. Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. On March 31, 2009, the spot price for natural gas at Henry Hub was $3.63 per Mmbtu and the spot oil price at Cushing, Oklahoma was $49.64 per Bbl. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance.

10

The pre-tax ceiling test write-down of $1.3 billion would have resulted in income tax benefits of $507.0 million. However, we are required to establish a deferred tax valuation allowance against this tax benefit as a result of the operating losses which have resulted from such write-downs. As a result, no income tax benefit was recognized.

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, production and changes in economics related to the properties 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.

6. 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, 2009 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, 2009 and 2008 is computed in the same manner as basic earnings (loss) per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, including our preferred stock outstanding during the first quarter of 2008, whether exercisable or not. Since we incurred net losses for the three months ended March 31, 2009 and 2008, we have excluded the potential common stock equivalents from the assumed conversion of stock options of 14,889,280 and 12,515,302, respectively. We have also excluded 105,263,158 shares of common stock equivalents from the assumed conversion of the preferred stock from the computation of loss per share for the three months ended March 31, 2008, as they were antidilutive.

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

	Three months ended March 31,
(in thousands, except per share amount)	2009			2008
Basic and diluted loss per share:
Net loss available to common shareholders	$	(1,099,611	)	$	(197,839	)
Shares:
Weighted average number of common shares outstanding		210,995			104,683
Basic and diluted loss per share:
Total basic and diluted loss per share	$	(5.21	)	$	(1.89	)

7. 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, 2009, total share-based compensation was $3.7 million, of which $2.5 million is included in general and administrative expense, $0.7 million is included in lease operating expense and $0.5 million is capitalized in proved developed and undeveloped oil and natural gas properties. For the three months ended March 31, 2008, total share-based compensation was $3.7 million, of which $2.0 million is included in general and administrative expense, $1.0 million is included in lease operating expense and $0.7 million is capitalized in proved developed and undeveloped oil and natural gas properties. Total share-based compensation to be recognized on unvested awards as of March 31, 2009 is $23.3 million over a weighted average period of 1.25 years.

During the three months ended March 31, 2009, options to purchase 88,100 shares were granted under the 2005 Incentive Plan at prices ranging from $7.89 to $9.80 per share with fair values ranging from $4.89 to $5.97 per share. 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 March 31, 2009 and December 31, 2008, there were 3,526,575 and 3,342,450 shares available to be granted under the 2005 Incentive Plan, respectively.

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8. Derivative financial instruments and fair value measurements

Our objective in entering into derivative financial instruments is to manage exposure to commodity price and interest rate fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits we would realize if prices increase or interest rates decrease. When prices for oil and natural gas or interest rates are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

We account for our derivative financial instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS No. 133. SFAS No. 133 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by SFAS No. 133 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes, and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with SFAS No. 161, the table below outlines the location of our derivative financial instruments on our condensed consolidated balance sheets and their financial impact in our condensed consolidated statement of operations.

Fair Value of Derivative Financial Instruments
(in thousands)	Balance Sheet location	March 31, 2009			December 31, 2008
Commodity contracts	Derivative financial instruments - Current assets	$	355,093		$	247,614
Commodity contracts	Derivative financial instruments - Long-term assets		192,281			173,003
Commodity contracts	Derivative financial instruments - Current liabilities		(1,237	)		(2,734	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(16,884	)		(11,585	)
Interest rate contracts	Derivative financial instruments - Current liabilities		(4,092	)		(8,873	)
Interest rate contracts	Derivative financial instruments - Long-term liabilities		—			(1,005	)
Net derivatives		$	525,161		$	396,420
The Effect of Derivative Financial Instruments
		Three months ended March 31,
(in thousands)	Statement of Operations location	2009			2008
Commodity contracts (1)	Gain (loss) on derivative financial instruments	$	221,384		$	(341,194	)
Interest rate contracts (2)	Interest expense		4,116			(3,253	)
Net gain (loss)		$	225,500		$	(344,447	)

(1) Included in these amounts are cash settlements, including net cash receipts of $98,429 and $3,015 for the three months ended March 31, 2009 and 2008, respectively.

(2) Included in these amounts are cash settlements, including net cash payments of $1,670 for the three months ended March 31, 2009 and net cash receipts of $378 for the three months ended March 31, 2008.

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from or cash disbursement to our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Unrealized fair value adjustments included in “Gain on derivative financial instruments,” which do not impact cash flows, were gains of $123.0 million and losses of $344.2 million for the three months ended March 31, 2009 and 2008, respectively. Unrealized fair value adjustments included in “Interest expense,” which do not impact cash flows, were gains of $5.8 million and losses of $3.6 million for the three months ended March 31, 2009 and 2008, respectively.

We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. As of March 31, 2009 and December 31, 2008, we had a net asset position of $525.5 million and $396.4 million, respectively.

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Fair value measurements

We value our derivatives according to SFAS No. 157, “Fair Value Measurements,” or SFAS No. 157, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. This fair value may be different than the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities.

We prioritize the inputs used in measuring fair value into a three-tier fair value hierarchy. 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 withinLevel 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.

The following presents a summary of the estimated fair value of our derivative financial instruments for the three months ended March 31, 2009 and the year ended December 31, 2008:

	For the three months ended March 31, 2009
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	529,253		$	—	$	529,253
Interest rate swaps		—		(4,092	)		—		(4,092	)
	$	—	$	525,161		$	—	$	525,161
	For the year ended December 31, 2008
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	406,298		$	—	$	406,298
Interest rate swaps		—		(9,878	)		—		(9,878	)
	$	—	$	396,420		$	—	$	396,420

In accordance with FASB Interpretation 39 “Offsetting of Amounts Related to Certain Contracts—an interpretation of APB Opinion No. 10 and FASB Statement No. 105,” or FIN 39, we evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them gross on the Condensed Consolidated Balance Sheets. Net derivative asset values are determined, in part, by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

Oil and natural gas derivatives

Our commodity price derivatives represent oil and natural gas swap contracts. We have classified our oil and natural gas swaps and their related fair value tier as Level 2.

Oil derivatives. Our oil derivatives are swap contracts for notional Bbls of oil at fixed NYMEX West Texas Intermediate (WTI) oil prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (iii) the applicable estimated
credit-adjusted risk-free rate curve, as described above.

Natural gas derivatives. Our natural gas derivatives are swap contracts for notional Mmbtus of gas at posted price indexes, including NYMEX Henry Hub (HH) swap contracts coupled with basis swap contracts that convert the HH price index point to the Panhandle Eastern Pipe Line index (PEPL). The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps and PEPL index quotes for our existing basis swaps and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

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The following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value as of March 31, 2009:

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl			Fair value at March 31, 2009
Natural gas:
Swaps:
Remainder of 2009	75,660	$	8.16		$	278,477
2010	66,298		7.62			107,303
2011	12,775		7.48			10,592
2012	5,490		5.91			(4,384	)
2013	5,475		5.99			(4,737	)
Total natural gas	165,698					387,251
Basis swaps:
Remainder of 2009	2,750		(1.10	)		(486	)
Total basis swaps	2,750					(486	)
Oil:
Swaps:
Remainder of 2009	1,190		80.65			29,570
2010	1,568		104.64			62,752
2011	1,095		112.99			46,856
2012	92		109.30			3,310
Total oil	3,945					142,488
Total oil and natural gas and basis swaps					$	529,253

At December 31, 2008, we had outstanding derivative contracts to mitigate price volatility covering 168,658 Mmcf of natural gas and 4,335 Mbbls of oil. At March 31, 2009, the average forward NYMEX oil prices per Bbl for the remainder of 2009 and for 2010 were $54.97 and $62.68, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2009 and for 2010 were $4.29 and $5.93, respectively.

Our derivative financial instruments to mitigate price volatility covered 74.9% and 78.7% of our total equivalent Mcfe production for the three months ended March 31, 2009 and 2008, respectively.

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBO rates ranging from 2.45% to 2.8%. The net derivative liability value attributable to our interest rate derivative contracts as of the end of the reporting period are based on (i) the contracted notional amounts, (ii) forward active market-quoted LIBO rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. We have classified our interest rate swaps and their related fair value tier as Level 2.

During the three months ended March 31, 2009 and 2008, we recognized $4.1 million as a decrease to interest expense and $3.3 million as an increase to interest expense, respectively, on our interest rate swaps. As of March 31, 2009, the fair value of our interest rate swaps was a liability of $4.1 million.

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9. Current and long-term debt

Our total debt is summarized as follows:

(in thousands)	March 31, 2009		December 31, 2008
Long term debt:
EXCO Resources Credit Agreement	$	1,063,930	$	1,048,951
EXCO Operating Credit Agreement		1,238,469		1,218,485
Term Credit Agreement		300,000	��	300,000
7 1/4% senior notes due 2011		444,720		444,720
Unamortized premium on 7 1/4 % senior notes due 2011		6,706		7,582
Total debt		3,053,825		3,019,738
Less current maturities		300,000		—
Total long term debt	$	2,753,825	$	3,019,738

Credit agreements

EXCO Resources Credit Agreement

The EXCO Resources credit agreement, as amended, or the EXCO Resources Credit Agreement, has a borrowing base of $1.175 billion with commitments spread among 33 banks, none of which have commitments exceeding 10% of the aggregate commitment amount. On February 4, 2009, EXCO entered into the third amendment to the EXCO Resources Credit Agreement. Pursuant to the third amendment, the leverage ratio covenant, as defined in the agreement, was modified to provide that EXCO will maintain the current maximum leverage ratio of less than 4.00 to 1.00 as of the end of each quarter during 2009. The leverage ratio will decrease as of March 31, 2010 to 3.75 to 1.00 and further decrease as of June 30, 2010 to 3.50 to 1.00. The other financial covenants and all other terms, including the maturity date and borrowing base were not changed.

At March 31, 2009, the one month LIBO rate was 0.50%, which would have resulted in an interest rate of approximately 2.25% under the EXCO Resources Credit Agreement before the effectiveness of the fourth amendment thereto on April, 17, 2009. At March 31, 2009, we had $1.064 billion of outstanding indebtedness and $107.8 million of available borrowing capacity under the EXCO Resources Credit Agreement.

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. On April 17, 2009, we entered into the fourth amendment to the EXCO Resources Credit Agreement, whereby the banking group reaffirmed the existing borrowing base commitments of $1.175 billion and increased our interest rate margins by 75 basis points, or bps. The interest rate now ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. Based on the new interest rate margins and a one month LIBO rate of 0.41% on April 30, 2009, we would incur an interest rate of approximately 2.91% on any new indebtedness we may incur or refinancing of existing debt tranches under the EXCO Resources Credit Agreement.

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 may have in place derivative financial instruments covering no more than 80% of its forecasted production from total proved reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012.

As of March 31, 2009, 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;

• not permit our ratio of consolidated funded indebtedness (as defined) to consolidated EBITDAX (as defined) to be greater than (i) 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2008 up to and including December 31, 2009, (ii) 3.75 to 1.0 at the end of the fiscal quarter ending on March 31, 2010 and (iii) 3.50 to 1.0 beginning with the quarter ending June 30, 2010 and each quarter end thereafter; and

• maintain a consolidated EBITDAX to consolidated interest expense (as defined) ratio of at least 2.5 to 1.0 at the end of any fiscal quarter ending on or after September 30, 2007.

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The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement.

EXCO Operating Credit Agreement

The EXCO Operating credit agreement, as amended, or the EXCO Operating Agreement, has a borrowing base of $1.3 billion with commitments spread among 33 banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At March 31, 2009, the one month LIBO rate was 0.50%, which would have resulted in an interest rate of approximately 2.25% under the EXCO Operating Credit Agreement before the effectiveness of the fourth amendment thereto on April, 17, 2009. At March 31, 2009, we had $1.238 billion of outstanding indebtedness and $60.0 million of available borrowing capacity under the EXCO Operating Credit Agreement.

The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. On April 17, 2009, we entered into the fourth amendment to the EXCO Operating Credit Agreement, whereby the banking group reaffirmed the existing borrowing base commitments of $1.3 billion and increased our interest rate margin by 75 bps. The interest rate now ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending on borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. Based on the new interest rate margins and a one month LIBO rate of 0.41% on April 30, 2009, we would incur an interest rate of approximately 2.91% on any new indebtedness we may incur or refinancing of existing debt tranches under the EXCO Operating Credit Agreement.

The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may have in place derivative financial instruments covering no more than 80% of the “forecasted production from total proved reserves” (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total proved reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012.

As of March 31, 2009, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:

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

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

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

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Operating Credit Agreement.

Term Credit Agreement

On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, with an aggregate balance of $300.0 million. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating may incur additional fees on unpaid principal amounts, or duration fees, as defined in the agreement. These include a 5% fee on the unpaid principal on June 15, 2009 and an additional 3% fee on the unpaid outstanding balance on September 15, 2009. Presently, we expect to incur some or all of the duration fees unless cash flow from operations or proceeds from asset sales are sufficient to pay down the loan and are therefore accruing the fees over the term of the loan. The Term Credit Agreement is due and payable on January 15, 2010 and is guaranteed by all existing and future direct or indirect subsidiaries of EXCO Operating, including any guarantor of the EXCO Operating Credit Agreement.

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As of March 31, 2009, EXCO Operating was in compliance with the financial covenants contained in the Term Credit Agreement, which require during the period any amounts are outstanding under the Term Credit Agreement, that EXCO Operating:

• maintain a minimum current ratio (as defined) of 1.00 to 1.00 as of the end of any calendar quarter;

• not permit the maximum leverage ratio (as defined) to be greater than 3.50 to 1.00 as of the end of any calendar quarter; and

• not permit our minimum interest coverage ratio (as defined) to be less than 2.50 to 1.00 as of the end of any calendar quarter.

At the borrower’s election, the Term Credit Agreement may bear interest at a rate per annum equal to (A) the ABR, defined as the highest of (i) the rate of interest publicly announced by JPMorgan as its prime rate in effect at its principal office in New York City, (ii) the federal funds effective rate from time to time plus 0.50%, and (iii) the Adjusted LIBO Rate (defined as the greater of (x) the rate at which eurodollar deposits in the London interbank market for one month are quoted on Reuters BBA Libor Rates Page 3750, as adjusted for actual statutory reserve requirements for eurocurrency liabilities, and (y) 4.0%) plus 1.0%, plus 5.0% or (B) the Adjusted LIBO Rate plus 6.0%. In all cases, the minimum interest rate on the Term Credit Agreement is 10.0%. At March 31, 2009, the interest rate on the $300.0 million outstanding on the Term Credit Agreement was 10.0%.

The foregoing descriptions are not complete and are qualified in their entirety by the Term Credit Agreement.

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

As of March 31, 2009 and December 31, 2008, $444.7 million in principal was outstanding on our 7 1/4% senior notes due January 15, 2011, or Senior Notes. The unamortized premium on the Senior Notes at March 31, 2009 and December 31, 2008 was $6.7 million and $7.6 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $342.4 million on March 31, 2009. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.

10. Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws. We apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial operating losses primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties. As a result of these cumulative financial operating losses, we have provided valuation allowances of approximately $964.9 million until the realization of future deferred tax benefits can be validated. The valuation allowance does not impact future utilization of the underlying tax attributes.

11. Operating segments

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

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

(in thousands)	Exploration and production			Midstream		Intercompany eliminations			Consolidated total
For the three months ended March 31, 2009:
Third party revenues	$	172,208		$	17,013	$	—		$	189,221
Intersegment revenues		(7,982	)		15,576		(7,594	)		—
Total revenues	$	164,226		$	32,589	$	(7,594	)	$	189,221
Segment profit	$	107,211		$	6,545	$	—		$	113,756
For the three months ended March 31, 2008:
Third party revenues	$	324,843		$	7,892	$	—		$	332,735
Intersegment revenues		(7,252	)		9,191		(1,939	)		—
Total revenues	$	317,591		$	17,083	$	(1,939	)	$	332,735
Segment profit	$	262,079		$	7,117	$	—		$	269,196
As of March 31, 2009:
Total assets	$	3,216,444		$	460,296	$	—		$	3,676,740
As of December 31, 2008:
Total assets	$	4,392,218		$	430,134	$	—		$	4,822,352

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

	Three months ended March 31,
(in thousands)	2009			2008
Segment profits	$	113,756		$	269,196
Depreciation, depletion and amortization		(81,794	)		(109,217	)
Write-down of oil and natural gas properties		(1,293,579	)		—
Accretion of discount on asset retirement obligations		(2,071	)		(1,316	)
General and administrative		(20,547	)		(22,627	)
Interest expense		(36,132	)		(36,020	)
Gain (loss) on derivative financial instruments		221,384			(341,194	)
Other income		427			1,427
Income (loss) before income taxes	$	(1,098,556	)	$	(239,751	)

12. 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 collectively 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.

The columns designated as “Non-guarantor subsidiaries” in the accompanying condensed consolidating financial statements represent EXCO Operating and its subsidiaries. There are no other non-guarantor subsidiaries.

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

• Resources;

• the Guarantor Subsidiaries on a combined basis;

• the non-Guarantor Subsidiaries;

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

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• EXCO on a consolidated basis.

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

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

March 31, 2009

(in thousands)	Resources			Guarantor Subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	18,495		$	5,511		$	21,502		$	—	$	45,508
Other current assets		202,760			22,983			310,828			—		536,571
Total current assets		221,255			28,494			332,330			—		582,079
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		84,434			120,951			267,815			—		473,200
Proved developed and undeveloped oil and natural gas properties		681,532			406,808			1,335,597			—		2,423,937
Accumulated depletion		(250,378	)		(155,608	)		(605,086	)		—		(1,011,072	)
Oil and natural gas properties, net		515,588			372,151			998,326			—		1,886,065
Gas gathering, office and field equipment, net		8,277			54,769			425,018			—		488,064
Derivative financial instruments		140,977			—			51,304			—		192,281
Deferred financing costs, net		11,021			—			44,696			—		55,717
Goodwill		110,800			164,469			194,808			—		470,077
Investments in and advances to affiliates		(120,379	)		—			—			120,379		—
Other assets		2			854			1,601			—		2,457
Total assets	$	887,541		$	620,737		$	2,048,083		$	120,379	$	3,676,740
Liabilities and shareholders’ equity
Current liabilities	$	42,844		$	33,468		$	455,107		$	—	$	531,419
Long-term debt		1,515,356			—			1,238,469			—		2,753,825
Deferred income taxes		10,427			—			—			—		10,427
Other liabilities		37,217			72,438			34,330			—		143,985
Payable to parent		(955,387	)		956,738			(1,351	)		—		—
Commitments and contingencies		—			—			—			—		—
Total shareholders’ equity		237,084			(441,907	)		321,528			120,379		237,084
Total liabilities and shareholders’ equity	$	887,541		$	620,737		$	2,048,083		$	120,379	$	3,676,740

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2008

(in thousands)	Resources			Guarantor Subsidiaries			Non- guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	8,618		$	12,360		$	36,161		$	—		$	57,139
Other current assets		162,607			29,935			263,359			—			455,901
Total current assets		171,225			42,295			299,520			—			513,040
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		85,061			119,940			276,595			—			481,596
Proved developed and undeveloped oil and natural gas properties		940,529			673,814			1,964,001			—			3,578,344
Accumulated depletion		(232,261	)		(145,103	)		(558,724	)		—			(936,088	)
Oil and natural gas properties, net		793,329			648,651			1,681,872			—			3,123,852
Gas gathering, office and field equipment, net		8,582			55,404			414,630			—			478,616
Derivative financial instruments		120,097			—			52,906			—			173,003
Deferred financing costs, net		6,414			—			56,470			—			62,884
Goodwill		110,800			164,469			194,808			—			470,077
Investments in and advances to affiliates		802,902			—			—			(802,902	)		—
Other assets		2			678			200			—			880
Total assets	$	2,013,351		$	911,497		$	2,700,406		$	(802,902	)	$	4,822,352
Liabilities and shareholders’ equity
Current liabilities	$	66,871		$	50,256		$	205,746		$	—		$	322,873
Long-term debt		1,501,253			—			1,518,485			—			3,019,738
Deferred income taxes		9,371			—			—			—			9,371
Other liabilities		27,065			78,316			32,488			—			137,869
Payable to parent		(923,710	)		948,463			(24,753	)		—			—
Commitments and contingencies		—			—			—			—			—
Total shareholders’ equity		1,332,501			(165,538	)		968,440			(802,902	)		1,332,501
Total liabilities and shareholders’ equity	$	2,013,351		$	911,497		$	2,700,406		$	(802,902	)	$	4,822,352

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2009

(in thousands)		Resources			Guarantor Subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas		$	38,082		$	30,029		$	104,097		$	—	$	172,208
Midstream			—			—			17,013			—		17,013
Total revenues			38,082			30,029			121,110			—		189,221
Costs and expenses:
Oil and natural gas production			14,206			8,536			30,376			—		53,118
Midstream operating expenses			—			—			18,450			—		18,450
Gathering and transportation			52			1,213			2,632			—		3,897
Depreciation, depletion and amortization			18,890			11,757			51,147			—		81,794
Write-down of oil and natural gas properties			279,632			282,073			731,874			—		1,293,579
Accretion of discount on asset retirement obligations	��		517			907			647			—		2,071
General and administrative			1,828			5,219			13,500			—		20,547
Total costs and expenses			315,125			309,705			848,626			—		1,473,456
Operating income (loss)			(277,043	)		(279,676	)		(727,516	)		—		(1,284,235	)
Other income (expense):
Interest expense			(10,942	)		—			(25,190	)		—		(36,132	)
Gain on derivative financial instruments			106,220			9,278			105,886			—		221,384
Other income			6,490			(5,971	)		(92	)		—		427
Equity in earnings of subsidiaries			(923,281	)		—			—			923,281		—
Total other income (expense)			(821,513	)		3,307			80,604			923,281		185,679
Income (loss) before income taxes			(1,098,556	)		(276,369	)		(646,912	)		923,281		(1,098,556	)
Income tax expense			1,055			—			—			—		1,055
Net income (loss)			(1,099,611	)		(276,369	)		(646,912	)		923,281		(1,099,611	)
Preferred stock dividends			—			—			—			—		—
Net income (loss) available to common shareholders		$	(1,099,611	)	$	(276,369	)	$	(646,912	)	$	923,281	$	(1,099,611	)

22

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2008

(in thousands)	Resources			Guarantor Subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	99,789		$	44,614		$	180,440		$	—	$	324,843
Midstream		—			—			7,892			—		7,892
Total revenues		99,789			44,614			188,332			—		332,735
Costs and expenses:
Oil and natural gas production		18,242			7,813			26,326			—		52,381
Midstream operating expenses		—			—			8,027			—		8,027
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
Total costs and expenses		57,979			28,151			110,569			—		196,699
Operating income (loss)		41,810			16,463			77,763			—		136,036
Other income (expense):
Interest expense		(19,801	)		—			(16,219	)		—		(36,020	)
Loss on derivative financial instruments		(111,487	)		(26,572	)		(203,135	)		—		(341,194	)
Other income		7,442			(6,551	)		536			—		1,427
Equity in earnings of subsidiaries		(152,370	)		—			—			152,370		—
Total other income (expense)		(276,216	)		(33,123	)		(218,818	)		152,370		(375,787	)
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	)

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2009

(in thousands)	Resources			Guarantor Subsidiaries			Non- guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	39,737		$	11,317		$	54,272		$	—	$	105,326
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(23,420	)		(25,569	)		(141,003	)		—		(189,992	)
Proceeds from dispositions of property and equipment		—			77			5,400			—		5,477
Advances/investments with affiliates		(30,391	)		7,326			23,065			—		—
Net cash used in investing activities		(53,811	)		(18,166	)		(112,538	)		—		(184,515	)
Financing Activities:
Borrowings under credit agreements		14,979			—			19,984			—		34,963
Repayments under credit agreements		—			—			—			—		—
Settlement of derivative financial instruments with a financing element		13,909			—			23,707			—		37,616
Proceeds from issuance of common stock, net		447			—			—			—		447
Deferred financing costs and other		(5,385	)		—			(83	)		—		(5,468	)
Net cash provided by financing activities		23,950			—			43,608			—		67,558
Net increase (decrease) in cash		9,876			(6,849	)		(14,658	)		—		(11,631	)
Cash at the beginning of the period		8,617			12,360			36,162			—		57,139
Cash at end of period	$	18,493		$	5,511		$	21,504		$	—	$	45,508

24

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 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

25

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

Forward-looking statements

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

• our future financial and operating performance and results;

• our business strategy;

• market prices;

• our future derivative financial instrument activities; and

• our plans and forecasts.

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

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

• fluctuations in prices of oil and natural gas;

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

• future capital requirements and availability of financing;

• continued disruption of credit and capital markets and the ability of financial institutions to honor their commitments;

• estimates of reserves and economic assumptions;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

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

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

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

• cash flow and liquidity;

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

• availability of drilling and production equipment;

• marketing of oil and natural gas;

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

• title to our properties;

26

• litigation;

• competition;

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

• environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases;

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

• decisions 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, 2008.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, we have midstream operations in the East Texas/North Louisiana area. Our assets in East Texas/North Louisiana are owned by our subsidiary, EXCO Operating Company, LP (formerly EXCO Partners Operating Partnership, LP), and its subsidiaries and together they are collectively referred to as EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt. This structure allows us to maintain two credit agreements: one at EXCO Resources, or the EXCO Resources Credit Agreement, which currently has a borrowing base of $1.175 billion and one at EXCO Operating, or the EXCO Operating Credit Agreement, which currently has a borrowing base of $1.3 billion. We expect to continue to grow by leveraging our management team’s experience, developing our shale resource plays, 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 along with a comprehensive derivative financial instrument program to support our strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments, and manage our capital structure.

Oil and natural gas prices have historically been volatile. On March 31, 2009, the spot market price for natural gas at Henry Hub was $3.63 per Mmbtu, a 61.2% decrease from March 31, 2008. The price of oil has shown similar volatility, with a $49.64 per Bbl spot market price for oil at Cushing, Oklahoma at March 31, 2009, a 51.1% decrease from March 31, 2008. In the first quarter of 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $37.37 per Bbl and $4.60 per Mcf, respectively, compared with first quarter 2008 average realized prices

27

of $96.68 per Bbl and $8.61 per Mcf, respectively. It is impossible to predict the duration or outcome of these price declines or the long-term impact on drilling and operating costs and the impacts, whether favorable or unfavorable, to our results of operations and liquidity.

Our 2009 capital expenditure budget approved by our Board of Directors is $582.0 million which includes $416.0 million for leasing, drilling, development and exploitation expenditures, $141.0 million for midstream operations and $25.0 million of corporate and other. The 2009 capital expenditures have an emphasis on horizontal shale development and expansion of our midstream facilities. We have reduced our conventional drilling program and minimized acreage leasing. We will continue some of our conventional exploitation projects to minimize the base decline of our production on properties. We do not budget for acquisitions as these transactions are opportunistic in nature. As a result of the commodity price declines, we have suspended certain drilling projects as current prices do not meet our acceptable rates of return.

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 identify and develop additional reserves and add additional reserves through acquisitions.

Our future growth will depend upon our ability to continue to identify and 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.

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, 2008.

Recent accounting pronouncements

On April 9, 2009, the Financial Accounting Standards Board, or the FASB, issued Staff Position FAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” or FSP FAS 107-1 and APB 28-1. FSP FAS 107-1 and APB 28-1 amends Statement of Financial Accounting Standards, or SFAS, SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. The staff position also amends APB Opinion No. 28, “Interim Financial Reporting” to require fair value disclosures in summarized financial information at interim reporting periods. FSP FAS 107-1 and APB 28-1 are effective for interim periods ending after June 15, 2009. Adoption of FSP FAS 107-1 and APB 28-1 will not affect our financial position, operating results or cash flows.

On April 1, 2009, the FASB issued FASB Staff Position No. 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies,” or FSP 141(R)-1. FSP 141(R)-1 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business Combinations,” or SFAS No. 141, to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the pronouncement upon issuance. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” or SFAS No. 161. SFAS No. 161 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and our strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “—Note 8. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

28

On December 31, 2008, the Securities and Exchange Commission, or the SEC, issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:

• Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

• Permits the use of new technologies for determining oil and natural gas reserves;

• Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

• Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

• Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

• Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

We are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and disclosures.

29

Our results of operations

A summary of key financial data for the three months ended March 31, 2009 and 2008 related to our results of operations is presented below:

	Three months ended						Quarter to
	March 31,						quarter change
(dollars in thousands, except per unit prices)	2009			2008			2009-2008
Production:
Oil (Mbbls)		527			507			20
Natural gas (Mmcf)		33,184			32,049			1,135
Total production (Mmcfe) (1)		36,346			35,091			1,255
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	19,696		$	49,017		$	(29,321	)
Natural gas		152,512			275,826			(123,314	)
Total oil and natural gas	$	172,208		$	324,843		$	(152,635	)
Midstream operations:
Midstream revenues (before intersegment eliminations)	$	32,589		$	17,083		$	15,506
Midstream operating expenses (before intersegment eliminations)		26,044			9,966			16,078
Midstream operating profit (before intersegment eliminations)		6,545			7,117			(572	)
Intersegment eliminations		(7,982	)		(7,252	)		(730	)
Midstream operating loss (after intersegment eliminations)	$	(1,437	)	$	(135	)	$	(1,302	)
Oil and natural gas derivative financial instruments:
Cash settlements (payments) on derivative financial instruments	$	98,429		$	3,015		$	95,414
Non-cash change in fair value of derivative financial instruments		122,955			(344,209	)		467,164
Total derivative financial instrument activities	$	221,384		$	(341,194	)	$	562,578
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	37.37		$	96.68		$	(59.31	)
Natural gas (per Mcf)		4.60			8.61			(4.01	)
Natural gas equivalent (per Mcfe)		4.74			9.26			(4.52	)
Costs and expenses:
Oil and natural gas operating costs (2)	$	40,686		$	33,071		$	7,615
Production and ad valorem taxes		12,432			19,310			(6,878	)
Gathering and transportation		3,897			3,131			766
Depletion		74,984			103,912			(28,928	)
Depreciation and amortization		6,810			5,305			1,505
General and administrative (3)		20,547			22,627			(2,080	)
Interest expense, net, including impacts of interest rate swaps		36,132			36,020			112
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	1.12		$	0.94		$	0.18
Production and ad valorem taxes		0.34			0.55			(0.21	)
Gathering and transportation		0.11			0.09			0.02
Depletion		2.06			2.96			(0.90	)
Depreciation and amortization		0.19			0.15			0.04
General and administrative		0.57			0.64			(0.07	)
Net loss	$	(1,099,611	)	$	(162,839	)	$	(936,772	)
Preferred Stock dividends		—			(35,000	)		35,000
Loss available to common shareholders	$	(1,099,611	)	$	(197,839	)	$	(901,772	)

1) Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.

2) Share-based compensation included in oil and natural gas operating costs is $0.7 million and $1.0 million for the three months ended March 31, 2009 and 2008, respectively.

3) Share-based compensation included in general and administrative expenses is $2.5 million and $2.0 million for the three months ended March 31, 2009 and 2008, respectively.

The following is a discussion of our financial condition and results of operations for the three months ended March 31, 2009 and 2008.

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

• fluctuations in oil and natural gas prices, which impact our oil and natural gas reserves, revenues and net income or loss;

• mark-to-market accounting used for our derivative financial instruments gains or losses;

• changes in proved reserves and production volumes and their impact on depletion;

• the impact of a ceiling test write-down in the first quarter of 2009 and third and fourth quarters of 2008;

• properties acquired in the Appalachian acquisition in February 2008, the New Waskom acquisition in March 2008 and the Danville acquisition in July 2008; and

• significant changes in the amount of our long-term debt and the conversion of $2.0 billion of preferred stock into common stock in July 2008.

30

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, particularly the recent worldwide economic slowdown which continues to put downward pressure on oil and natural gas prices and demand;

• the level of domestic and international industrial demand for manufacturing operations;

• 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;

• 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; and

• trends in fuel use and government regulations that encourage less fuel use and encourage or mandate alternative fuel use.

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.

Marketing arrangements

We produce oil and natural gas. We do not refine or process the oil we produce. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

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

We may be unable to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable 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. Recent economic conditions related to the liquidity and creditworthiness of our purchasers may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

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Summary

For the three months ended March 31, 2009, we reported a net loss available to common shareholders of $1.1 billion, compared to a net loss available to common shareholders of $197.8 million for the quarter ended March 31, 2008.

During the first quarter of 2009, production volumes from our horizontal drilling activities in the Haynesville shale resulted in significant new production volumes that did not exist in the prior year’s first quarter. In addition, the impact of our Appalachian acquisition, New Waskom acquisition and our Danville acquisition in 2008 have increased our production, revenues, operating expenses and general and administrative expenses when compared to the prior year’s quarter. However, these positive impacts were overshadowed by the decline in oil and natural gas prices. In the first quarter of 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $37.37 per Bbl and $4.60 per Mcf, respectively, compared with first quarter 2008 average realized prices of $96.68 per Bbl and $8.61 per Mcf, respectively. Derivative financial instruments, which we use to mitigate price volatility, also have a significant impact on our results of operations, since we do not designate our derivative financial instruments as hedges and are required to mark the non-cash changes in the fair value of our derivatives to market at the end of each reporting period.

Oil and natural gas revenues, production and prices

The following table presents our revenues, production and prices by major producing areas for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,
	2009					2008					Quarter to quarter change
(in thousands, except per unit rate)	Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	22,616	$	104,097	$	4.60	21,575	$	180,440	$	8.36	1,041		$	(76,343	)	(3.76	)
Mid-Continent	5,752		24,439		4.25	5,939		62,203		10.47	(187	)		(37,764	)	(6.22	)
Appalachia	5,125		30,030		5.86	4,716		44,614		9.46	409			(14,584	)	(3.60	)
Permian and other	2,853		13,642		4.78	2,861		37,586		13.14	(8	)		(23,944	)	(8.36	)
Total	36,346	$	172,208		4.74	35,091	$	324,843		9.26	1,255		$	(152,635	)	(4.52	)

For the three months ended March 31, 2009, total oil and natural gas revenues were $172.2 million, a 47.0% decrease from the three months ended March 31, 2008 total oil and natural gas revenues of $324.8 million. For the first quarter of 2009, natural gas represented 88.6% of our oil and natural gas revenues and 91.3% of equivalent production, compared with the first quarter of 2008, where natural gas represented 84.9% of our oil and natural gas revenues and 91.3% of equivalent production. Total equivalent production volumes were 36.3 Bcfe for the three months ended March 31, 2009, a 3.6% increase over the prior year’s comparable period production of 35.1 Bcfe. In our East Texas/North Louisiana area, new production from our Haynesville shale drilling activities totaled 1.9 Bcfe (21.1 Mmcfe per day) and production from our Danville Acquisition added 1.6 Bcfe (17.8 Mmcfe per day). The increased volumes in the region were partially offset by decreased volumes from our Vernon field of 1.3 Bcfe (14.4 Mmcfe per day), decreased Cotton Valley drilling activity and natural declines from existing wells. In our Appalachian region, production volumes increased by 0.4 Bcfe (4.5 Mmcfe per day) as the March 31, 2009 quarter included a full 90 days of production from the Appalachian acquisition, while the prior year’s quarter included only 40 days of production. This increased production was, again, offset by natural production declines and certain 2009 curtailments from industrial users in Appalachia. In our Mid-Continent, Permian and other regions, production volumes decreased by 0.2 Bcfe (2.2 Mmcfe per day) due primarily to reduced drilling activity and natural production declines.

The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, decreased from $96.68 per Bbl for the three months ended March 31, 2008 to $37.37 per Bbl, or 61.3%, for the three months ended March 31, 2009. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.60 per Mcf, a decrease of 46.6% for the three months ended March 31, 2009 compared with $8.61 per Mcf for the three months ended March 31, 2008. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows, quantities of estimated Proved Reserves and related liquidity. Assuming we maintain our three months ended March 31, 2009 production levels for the remainder of the year, a change of $0.10 per Mcf of natural gas sold would result in an annual increase or decrease in revenues and cash flow of approximately $13.3 million and a change of $1.00 per Bbl of oil sold would result in an annual increase or decrease in revenues and cash flow of approximately $2.1 million without considering the effects of derivative financial instruments.

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Midstream revenues

Our Midstream revenues are principally derived from three of our wholly-owned subsidiaries; TGG Pipeline, Ltd., which hold an intrastate pipeline in East Texas/North Louisiana and Talco Midstream Assets, Ltd. and Vernon Gathering, LLC, which hold gathering systems in East Texas/North Louisiana.

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

For three months ended March 31, 2009, midstream revenues were $32.6 million compared with $17.1 million for the three months ended March 31, 2008. The increase in sales is due primarily to increased revenues due to the New Waskom acquisition, which closed in March 2008, and gathering assets acquired in the Danville acquisition, which closed in July 2008. These assets have several contracts whereby we purchase and resell natural gas produced by third-parties. The remaining increase in revenues was attributable to increases in drip sales and gathering fees associated with increased throughput on our midstream assets.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three months ended March 31, 2009 were $40.7 million and represent increases of $7.6 million, or 23.0%, from the same periods in 2008. Increases in total dollar value are due primarily to operating expenses incurred from our acquisitions and increases in the number of wells drilled during 2008. Management believes that analyses on a per Mcfe basis provide a more meaningful measure than the absolute dollar increases since the acquisitions in 2008 were significant. The following tables summarize direct operating expenses and unit rates per Mcfe for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,				Quarter to quarter change
(in thousands)	2009		2008		2009 - 2008
Lease operating expense	$	37,594	$	31,601	$	5,993
Workovers		2,395		479		1,916
Stock-based compensation (non-cash)		697		991		(294	)
Total oil and natural gas operating costs	$	40,686	$	33,071	$	7,615
	Three months ended March 31,				Quarter to quarter change
(per Mcfe)	2009		2008		2009 - 2008
Lease operating expense	$	1.03	$	0.90	$	0.13
Workovers		0.07		0.01		0.06
Stock-based compensation (non-cash)		0.02		0.03		(0.01	)
Total oil and natural gas operating costs	$	1.12	$	0.94	$	0.18

On a per Mcfe basis, oil and natural gas operating expenses for the three months ended March 31, 2009 increased $0.18 per Mcfe from the same period in 2008. Lease operating expenses per unit increased by $0.13 per Mcfe, or 14.4%, for the three months ended March 31, 2009 from the same period in 2008. These increases are primarily the result of increases in chemicals, labor, salt water disposal and the general increase in the costs of goods and services used in our operations. While we expect the costs of oil field services to decline in response to lower commodity prices, our unit rates per Mcfe may also be negatively affected by declines in volumes resulting from reduced drilling activity. We also expect our rate per Mcfe to benefit as our Haynesville production increases. Workover expenses for the three months ended March 31, 2009 increased $0.06 per Mcfe from the prior years’ quarter primarily due to workovers being performed in our Vernon field as we try to maintain our production levels from this field.

Increases in oil and natural gas operating costs for the three months ended March 31, 2009 were impacted by:

• the Appalachian acquisition, which closed on February 20, 2008 and added $1.0 million of incremental production expenses for the three months ended March 31, 2009;

• the Danville acquisition, which closed on July 15, 2008 and added $2.0 million of production expenses for the three months ended March 31, 2009; and

• increases from 475 new well additions added during 2008 through our development and exploitation capital program.

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Midstream operating expenses

Our midstream operating expenses for the three months ended March 31, 2009 increased $16.1 million from the same period in 2008. The increase in midstream operating expenses for the three months ended March 31, 2009 was primarily attributable to:

• increased cost of purchased gas of approximately $13.4 million due primarily to purchased natural gas for resale from our New Waskom and Danville acquisitions; and

• increased operating expenses of approximately $2.8 million related to the New Waskom and Danville acquisitions and the expansion of the TGG pipeline that was completed in the third quarter of 2008.

Gathering and transportation

We report gathering and transportation costs in accordance with Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs,” or EITF 00-10. We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments, contain revenues which are reported under two separate bases. Gathering and transportation expenses totaled $3.9 million for the three months ended March 31, 2009 compared to $3.1 million for the three months ended March 31, 2008. As our marketing efforts expand, we expect our gathering and transportation expenses will also increase.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended March 31, 2009 decreased by $6.9 million, or 35.6%, over the same period in 2008. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 7.2% of gross oil and natural gas sales for the three months ended March 31, 2009, compared with 5.9% during the same period in the prior year. The increase in the percentage of revenue basis is primarily the result of the different taxing jurisdictions in which we operate. 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. In Louisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis and ad valorem taxes are assessed on tangible assets and therefore, the resulting dollar value of severance and ad valorem taxes are not sensitive to changes in prices for natural gas. In our other operating areas, severance taxes are predominantly price dependent, while ad valorem assessments vary widely.

In addition to our existing production and ad valorem taxes on current properties, we may be subject to new taxes or changes to existing rates in the future. The State of Louisiana has raised its severance tax rate to $0.33 per Mcf from $0.29 effective July 1, 2009. In addition, the Commonwealth of Pennsylvania, which does not currently have ad valorem or severance taxes on oil and natural gas reserves or production, is currently studying different tax proposals impacting the oil and natural gas industry.

Overall, our severance and ad valorem tax rates per Mcfe were $0.34 per Mcfe for the three months ended March 31, 2009 compared with $0.55 per Mcfe for the three months ended March 31, 2008. The decrease is largely due to price. The following tables present our severance and ad valorem taxes on a per Mcfe basis and percentage of revenue basis for our significant producing regions.

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	Percentage of revenue basis
	Three months ended March 31, 2009							Three months ended March 31, 2008
(in thousands, except per unit rate)	Revenue		Severance and ad valorem taxes		% of revenue			Revenue		Severance and ad valorem taxes		% of revenue
Producing region:
East Texas/North Louisiana	$	104,097	$	8,330		8.0	%	$	180,440	$	10,121		5.6	%
Mid-Continent		24,439		1,885		7.7	%		62,203		4,645		7.5	%
Appalachia		30,030		780		2.6	%		44,614		1,281		2.9	%
Permian and other		13,642		1,437		10.5	%		37,586		3,263		8.7	%
Total	$	172,208	$	12,432		7.2	%	$	324,843	$	19,310		5.9	%
	Per Mcfe basis
	Three months ended March 31, 2009							Three months ended March 31, 2008
(in thousands, except per unit rate)	Production (Mcfe)		Severance and ad valorem taxes		$/Mcfe			Production (Mcfe)		Severance and ad valorem taxes		$/Mcfe
Producing region:
East Texas/North Louisiana		22,616	$	8,330	$	0.37			21,575	$	10,121	$	0.47
Mid-Continent		5,752		1,885		0.33			5,939		4,645		0.78
Appalachia		5,125		780		0.15			4,716		1,281		0.27
Permian and other		2,853		1,437		0.50			2,861		3,263		1.14
Total		36,346	$	12,432		0.34			35,091	$	19,310		0.55

Depletion

Our depletion expense for the three months ended March 31, 2009 decreased by $28.9 million, or 27.8%, from the same period in 2008. The primary reason for the decrease was the lower full cost pool amortization base resulting from $2.8 billion of ceiling test write-downs during the third and fourth quarters of 2008. These write-downs decreased our per unit depletion rate from $2.96 per Mcfe for the three months ended March 31, 2008 to $2.06 per Mcfe for the three months ended March 31, 2009. As a result of an additional ceiling test write-down in the first quarter of 2009, our depletion rate will further decrease.

Depreciation and amortization

Our depreciation and amortization costs for the three months ended March 31, 2009 increased by $1.5 million, or 28.4%, from the same period in 2008. The primary reason for the increase was the increases in our gas gathering asset base for the three months ended March 31, 2009 and our July 2008 Danville acquisition.

Accretion of discount on asset retirement obligations increased to $2.1 million for the three months ended March 31, 2009 from $1.3 million for the three months ended March 31, 2008. The increase is due to the combination of significant well additions and related plugging liabilities in connection with our 2008 acquisitions, revisions to previous estimates, and increased estimates for the costs to plug and abandon properties. The increased estimates for plugging and abandoning properties reflect increased costs for labor, rig rates and materials used in those operations.

Write-down of oil and natural gas properties

We recognized a write-down of our oil and natural gas properties of $1.3 billion for the three months ended March 31, 2009. Under full cost accounting, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. On March 31, 2009, the spot price for natural gas at Henry Hub was $3.63 per Mmbtu and the spot oil price at Cushing, Oklahoma was $49.64 per Bbl. Natural gas, which is sold at other natural gas marketing hubs where we conduct our operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we typically have received a premium to Henry Hub.

The pre-tax ceiling test write-down of $1.3 billion would have resulted in income tax benefits of $507.0 million. We are required to establish a deferred tax valuation allowance against this tax benefit as a result of the operating losses which have resulted from such write-downs. As a result, no income tax benefit is recognized.

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General and administrative

The following table presents our general and administrative expenses for the three months ended March 31, 2009 and 2008, and changes for the quarters then ended.

	Three months ended March 31,						Quarter to quarter change 2009-2008
(in thousands, except per unit rate)	2009			2008
General and administrative costs:
Gross general and administrative expense	$	30,523		$	30,521		$	2
Operator overhead reimbursements		(6,488	)		(5,675	)		(813	)
Capitalized acquisition and development charges		(3,488	)		(2,219	)		(1,269	)
Net general and administrative expense	$	20,547		$	22,627		$	(2,080	)
General and administrative expense per Mcfe	$	0.57		$	0.64		$	(0.07	)

Our general and administrative costs for the three months ended March 31, 2009 were $20.5 million, or $0.57 per Mcfe, compared to $22.6 million, or $0.64 per Mcfe, for the same period in 2008, a decrease of $2.1 million, or 9.2%. Significant components of the overall decrease for the three months ended March 31, 2009 include the following items:

• decreased legal fees of $3.5 million due to the first quarter 2008 cancellation of a proposed master limited partnership;

• decreased franchise and property taxes of $1.2 million due primarily to lower equity as a result of 2008 ceiling test write-downs and recapitalization of our corporate structure;

• increased operator overhead recoveries of $0.8 million due to the 2008 acquisitions; and

• increased capitalized salary costs to our full cost pool of $1.3 million due to expansion of technical personnel attributable to the acquisitions in 2008.

The decreases were partially offset by increased personnel costs of $4.1 million due to additional employees related primarily to our 2008 acquisitions and expansion of our technical and managerial staff to exploit our shale resource asset base through horizontal drilling and increased share-based compensation costs of $0.5 million due primarily to additional headcount.

Interest expense

Our interest expense increased approximately $0.1 million for the three months ended March 31, 2009 from the same period in 2008. The increase is primarily due to the $300.0 million credit agreement drawn on December 8, 2008, or the Term Credit Agreement. This increase was substantially offset by lower interest rates on our EXCO Resources and EXCO Operating credit agreements due to the decline in the LIBOR rates from the prior year, along with gains on the fair market value of our interest rate swaps and certain capitalized interest costs. The following table presents the components of our interest expense:

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	Three months ended March 31,						Quarter to quarter change 2009-2008
(in thousands)	2009			2008
Interest expense:
7 1/4% senior notes due 2011	$	7,184		$	7,238		$	(54	)
EXCO Resources Credit Agreement		6,424			9,502			(3,078	)
EXCO Operating Credit Agreement		7,854			14,763			(6,909	)
Term Credit Agreement		7,500			—			7,500
Amortization of deferred financing costs on EXCO Resources Credit Agreement		777			476			301
Amortization and write-off of deferred financing costs on EXCO Operating loan		754			753			1
Amortization of deferred financing costs on Term Credit Agreement		11,103			—			11,103
Interest rate swaps settlements		1,670			(378	)		2,048
Fair market value adjustment on interest rate swaps		(5,786	)		3,631			(9,417	)
Capitalized interest		(1,361	)		—			(1,361	)
Other interest expense		13			35			(22	)
Total interest expense	$	36,132		$	36,020		$	112

Derivative financial instruments

Our objective in entering into derivative financial instruments is to manage our exposure to commodity price and interest rate fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments, which are reported as a component of other income or expenses in our consolidated statements of operations. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments.

	Three months ended March 31,					Quarter to quarter change 2009-2008
(in thousands)	2009		2008
Derivative financial instrument activities:
Cash settlements on derivative financial instruments	$	98,429	$	3,015		$	95,414
Non-cash change in fair value of derivative financial instruments		122,955		(344,209	)		467,164
Total derivative financial instrument activities	$	221,384	$	(341,194	)	$	562,578

The use of derivative financial instruments allows us to limit the impacts of volatile price fluctuations associated with oil and natural gas. The following table presents our natural gas prices, before the impact of derivative financial instruments, where average realized prices per Mcfe dropped from $9.26 during the three months ended March 31, 2008 to $4.74 during the three months ended March 31, 2009. This volatility was offset somewhat from realized settlements of our derivatives, where average realized prices per Mcfe after the impact of our derivative financial instruments increased our price from $4.74 to $7.45 per Mcfe during the three months ended March 31, 2009 and increased our price from $9.26 to $9.35 per Mcfe for the three months ended March 31, 2008. This decreased our quarter to quarter change from $4.52 per Mcfe before cash settlements on derivatives to $1.90 per Mcfe after cash settlements on derivatives.

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	Three months ended March 31,				Quarter to quarter change 2009-2008
Realized pricing:	2009		2008
Oil per Bbl	$	37.37	$	96.68	$	(59.31	)
Natural gas per Mcf		4.60		8.61		(4.01	)
Natural gas equivalent per Mcfe	$	4.74	$	9.26	$	(4.52	)
Effect of cash settlements on derivatives		2.71		0.09		2.62
Net price per Mcfe, including derivative financial instruments	$	7.45	$	9.35	$	(1.90	)

Our cash settlements for the three months ended March 31, 2009 increased revenue by $98.4 million, or $2.71 per Mcfe, compared to cash settlements increasing revenues by $3.0 million, or $0.09 per Mcfe, for the same period in 2008. As noted above, the significant fluctuations between settlements of receipts on our derivative financial instruments demonstrate the aforementioned volatility in prices.

Our non-cash mark-to-market changes in the value of our oil and natural gas derivative financial instruments for the three months ended March 31, 2009 resulted in a gain of $123.0 million compared to a loss of $344.2 million for the same period in the prior year. The significant fluctuation was, again, attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

We expect to continue our comprehensive derivative financial instrument program as part of our overall acquisition and financing strategy to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. In connection with our acquisitions, we typically hedge a portion of future production acquired in order to lessen the variability of our returns on shareholders’ equity and to protect our shareholders’ equity by supporting our ability to meet our debt service obligations and stabilize cash flows.

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 LIBO rates ranging from 2.45% to 2.8%. For the three months ended March 31, 2009, we had realized losses from payments of $1.7 million and $5.8 million of non-cash unrealized gains attributable to our interest rate swaps, compared to realized gains from settlements of $0.3 million and non-cash unrealized losses of $3.6 million for the same period in 2008.

Income taxes

Our effective income tax rate for the three months ended March 31, 2009 was an expense of 0.1% and for the three months ended March 31, 2008, a benefit of 32.1%. For the three months ended March 31, 2009, we recognized a valuation allowance of $429.2 million against future deferred tax benefits. The valuation allowance was primarily the result of the ceiling test write-down, which decreased the book basis of our proved oil and natural gas properties. The effective income tax rate excluding the impact of the valuation allowance for the three months ended March 31, 2009 would have been a benefit of 39.0%. A substantial portion of our stock-based compensation included in our results of operations for the three months ended March 31, 2009 and 2008 are in the form of incentive stock options which are not deductible for tax purposes until a disqualifying event occurs. The change in the tax rate from the prior year, without giving consideration to the impact of the deferred income tax valuation allowance, is mainly a result of a state rate change last year in our state income taxes.

Our liquidity, capital resources and capital commitments

Overview

Our 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 issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. Historically, we have used acquisitions and vertical drilling as our primary vehicles for growth. As a result of our acquisitions, we have accumulated a large inventory of low risk drilling locations and acreage holdings with significant shale resource potential. This potential has caused us to shift our focus to define the extent of and develop these shale resources through the application of horizontal drilling, while continuing to develop certain vertical drilling opportunities in East Texas/North Louisiana, West Texas and Appalachia. Any near-term acquisitions will more than likely be focused on supplementing our shale resource holdings in our East Texas/North Louisiana and Appalachia areas as economic conditions permit. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility and using derivative financial instruments to mitigate price fluctuations. During the last half of 2008 and through the second quarter of 2009, prices for natural gas have declined significantly. As a result of these price declines, many of our vertical drilling economics do not meet our internal rate of return objectives. In response to the price declines, we reduced our anticipated capital spending for the 2009 fiscal year to

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$582.0 million, a 41.2% reduction from our fiscal 2008 capital expenditures. This 2009 capital expenditure budget reflected reduced drilling expenditures, while our expected capital for midstream operations increased, principally to reflect the expansion of our pipeline system to transport expected production from the Haynesville/Bossier area. As prices for natural gas continue to decline in 2009, we have suspended certain drilling projects, which may result in our 2009 capital expenditures being less than our 2009 budget if prices do not recover.

As of April 30, 2009, the aggregate borrowing bases under our credit agreements totaled $2.475 billion, of which $2.297 billion was drawn. In addition, we have $300.0 million outstanding under our Term Credit Agreement, which matures on January 15, 2010, and $444.7 million of Senior Notes due on January 11, 2011, or the Senior Notes.

Cash flows from operations represent the primary source of liquidity to fund our operations and our capital expenditure programs. The primary factors impacting our cash flow from operations include (a) levels of production from our oil and natural gas properties, (b) prices we receive for sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (c) operating costs of our oil and natural gas properties, (d) costs for our general and administrative activities and (e) interest expense and other financing related costs.

In the fourth quarter of 2008 we commenced a process to divest various non-strategic assets across our entire portfolio. We have engaged several different brokers to assist with these divestitures. Through April 30, 2009, we have completed the sale of certain oil and natural gas properties totalling approximately $21.0 million. We expect to complete additional divestitures in the second and third quarters of 2009.

We generally do not establish a 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 and the indenture governing our Senior Notes contains restrictions on incurring indebtedness and pledging our assets. In addition, disruptions in the credit and capital markets have limited the availability of financing to fund acquisitions. For 2009, we plan to focus primarily on drilling our shale projects.

Recent events affecting liquidity

Beginning in the fourth quarter of 2008, the United States government and the Federal Reserve implemented various programs and enacted legislation designed to provide liquidity to financial institutions, stabilize credit markets and provide other forms of economic stimulation to the economy. The impacts of these actions, many of which have yet to be fully implemented, on our industry and on us, cannot be determined at this time, nor can we determine the length of time that credit markets will remain constrained, and the ultimate impact on our ability to access capital is expected to be equally uncertain. As further discussed below, our capital budget for 2009 reflects reduced and more targeted capital expenditures for development and exploitation than in 2008 and prior years. The significant reduction in our overall drilling, especially conventional wells, could impact our production volumes in future periods. Should these conditions continue, the borrowing base of our credit agreements, compliance with debt covenants and status with credit rating agencies could be negatively affected. On April 17, 2009 our banking group reaffirmed the aggregate total of our borrowing base under our credit agreements at $2.475 billion. Our next borrowing base redetermination is scheduled to be on or about October 1, 2009. If commodity prices continue to be weak and our drilling program continues to be curtailed, there can be no assurance that future borrowing base reaffirmations will be successful.

In addition to the turmoil in the credit markets and related uncertainties, prices for natural gas have continued their precipitous decline which began the third quarter of 2008 and continued into the second quarter of 2009. The spot price for oil and natural gas on April 30, 2009 was $50.25 per Bbl and $3.44 per Mmbtu compared with $49.64 per Bbl and $3.63 per Mmbtu on March 31, 2009 and $44.60 per Bbl and $5.71 per Mmbtu on December 31, 2008. NYMEX future prices for oil and natural gas have also declined significantly since December 31, 2008, reflecting anticipated decreasing domestic and worldwide demand for oil and natural gas as a result of the global recession and uncertainties about the depth and length of the recession and the timing of a recovery. Each of the aforementioned events could impact our near-term, and perhaps long-term, liquidity and operating revenues resulting in changes to business plans or operations. As discussed in greater detail under “Item 3. Quantitative and Qualitative Disclosures About Market Risk,” we use derivative financial instruments to mitigate commodity price fluctuations and interest rate fluctuations to manage our debt service requirements.

Substantially all of the counterparties to our derivative financial instruments are lenders under our credit agreements. The remaining counterparties to our derivative financial instruments are affiliates of lenders under our credit agreements. Our banking relationships with the counterparties to our derivatives provide us with financial flexibility since we are not required to post additional collateral to secure obligations we may have in the future.

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While our cash provided from operations benefits from the use of derivative financial instruments, approximately 30% of our expected 2009 sales volumes are not subject to derivative financial instruments. Accordingly, in periods where prices increase above the fixed price contained in our derivative contracts, we will not receive full benefit from those increases. Conversely, when prices decrease below the fixed price in our derivative contracts, we are also impacted negatively on the portion of our production not covered by derivative contracts. Beginning in the second half of 2008 and into 2009, oil and natural gas prices declined significantly. As a result, we received cash payments from our oil and natural gas derivative counterparties during the quarter ended March 31, 2009 totaling $98.4 million. We are required to settle our derivative financial instruments prior to receiving the payments for production, which is typically collected 30 to 60 days after our derivative settlements are closed. This timing between settlement of the derivative financial instruments and actual collection of the proceeds can create short-term borrowing requirements in periods of increasing prices. In periods of declining prices, we may experience temporary cash and liquidity increases from settlements of our derivative financial instruments.

On April 30, 2009, the EXCO Resources Credit Agreement had a borrowing base of $1.175 billion, $1.064 billion of which was drawn, and the EXCO Operating Credit Agreement had a borrowing base of $1.300 billion, $1.233 billion of which was drawn. On February 4, 2009, the EXCO Resources Credit Agreement was further amended to modify certain debt covenants beginning with the quarter ended March 31, 2009. Despite the recent negative events in capital and credit markets and decline in commodity prices, we believe that our remaining borrowing capacity under our credit agreements, capital resources from existing cash balances, anticipated cash flow from operating activities, and reduced 2009 capital expenditures will be adequate to meet the cash requirements to fund our operations, debt service obligations and our 2009 capital expenditure programs. The interest rate grid on both our revolving facilities was increased by 75 bps effective April 17, 2009. Accordingly, our interest costs will increase in future periods. Our future cash flows are subject to a number of variables including production volumes and oil and natural gas prices. If oil and natural gas prices remain depressed for an extended period of time, we may be required to further reduce our capital expenditures in 2009 and in the future, which in turn may affect our liquidity and results of operations in future periods and impact our ability to maintain our borrowing base under our credit agreements or comply with existing bank covenants. In connection with the commodity price declines, we have also experienced decreases in certain capital and operating costs, such as drilling costs, tubular goods and oil field services. While these savings remain subject to future increases, they play a significant role in our capital budgets and operating costs, both of which impact our overall liquidity.

The Term Credit Agreement entered into on December 8, 2008 matures and becomes payable on January 15, 2010. We believe that based on EXCO Operating’s current production levels and current depressed prices for oil and natural gas, our cash flows from operations and remaining borrowing capacity under our credit agreement, may not be sufficient to fully repay the Term Credit Agreement when due without further reductions in our capital expenditure levels or non-strategic asset sales. Through April 2009, we closed sales of oil and natural gas properties resulting in proceeds of approximately $21.0 million. We are currently in various stages of activities related to the sale of other non-strategic oil and natural gas properties and have plans to pursue the sale of additional oil and natural gas properties in 2009. We believe that such asset sales will supplement our free cash to enable us to repay amounts outstanding under the Term Credit Agreement prior to its maturity. In addition to our credit agreements and the Term Credit Agreement, EXCO has $444.7 million of 7 1/4 % senior notes due January 15, 2011.

Historical sources and uses of funds

Cash flows from operations

Our operating cash flows are driven by the quantities of our production of oil and natural gas and the prices received from the sale of this production and revenue generated from our midstream operating activities. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income.

Net cash provided by operating activities, before working capital changes and adjustments for settlements of derivative financial instruments with a financing element, was $165.1 million for the three months ended March 31, 2009 compared with $222.1 million for the three months ended March 31, 2008. The 25.6% decrease is attributable primarily to lower average oil and natural gas prices in the first quarter of 2009 compared with average prices during the same period in 2008, offset by increases in cash settlements of our oil and natural gas derivatives. At March 31, 2009, our cash and cash equivalents balance was $45.5 million, a 20.4% decrease from December 31, 2008. On April 30, 2009, our cash and cash equivalent balance was $78.1 million. On January 15, 2009, we made the scheduled interest payment on our Senior Notes of $16.1 million. We generally pay interest on our other credit agreements on a monthly basis.

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Investing activities and transactions

In recent years, a significant amount of our growth has been through acquisitions of existing producing and non-producing oil and natural gas properties and related assets, including our midstream assets. These acquisitions have been funded to a great extent by borrowings under credit agreements and term loan agreements, as well as issuance of equity. As discussed above, the deterioration in the U.S. and worldwide credit and equity markets has significantly diminished our ability to fund additional growth in the near term through these capital sources.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the three months ended March 31, 2009 and 2008:

	Three months ended March 31,
(in thousands)	2009		2008
Capital expenditures:
Property acquisitions	$	7	$	414,519
Midstream acquisitions		—		55,667
Lease purchases		10,990		10,288
Development capital expenditures		113,026		152,159
Midstream capital additions		13,444		11,183
Corporate and other		14,433		10,350
Total capital expenditures	$	151,900	$	654,166

The 2009 capital expenditures have an emphasis on horizontal shale drilling and completion and expansion of our midstream facilities. We have further reduced our vertical well drilling program from our original 2009 expectations and minimized acreage leasing, except for leasing activities required to complete the formation of drilling units. We will continue our exploitation projects to minimize the base decline of our production on properties.

We have presently budgeted approximately $582.0 million for capital expenditures in 2009, of which we are contractually obligated to spend $73.7 million as of March 31, 2009. The 2009 capital expenditures budget is, we believe, responsive to the shift in focus to our significant shale resources potential, the uncertainties existing in the capital and credit markets and the continued depressed level of oil and natural gas prices. We expect to utilize our current cash balances, cash flow generated from operations and available funds under our credit agreements in 2009 to fund capital expenditures and acquisitions, if any. The capital budget for 2009 reflects a 41.2% decrease from 2008 actual capital expenditures, excluding acquisitions, of approximately $989.1 million. We continue to monitor the economics of drilling projects in light of the current commodity price environment, which may result in reductions in our planned capital expenditures.

Future cash flows are subject to a number of variables including production volumes, fluctuations in oil and natural gas prices and our ability to service the debt incurred in connection with our acquisitions. If cash flows decline we may be required to further reduce our capital expenditure budget, which in turn may affect our production in future periods. Our cash flow from operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures.

Credit agreements and long-term debt

As of April 30, 2009, we have total debt outstanding aggregating $3.042 billion consisting of the Term Credit Agreement due in January 2010 ($300.0 million), two credit agreements maturing in March 2012 ($2.297 billion) and Senior Notes due in January 2011 ($444.7 million). Terms and considerations of each of the debt obligations are discussed below.

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EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended has a borrowing base of $1.175 billion with commitments spread among 33 banks, none of which have commitments exceeding 10% of the aggregate commitment amount. On February 4, 2009, EXCO entered into the third amendment to the EXCO Resources Credit Agreement. Pursuant to the third amendment, the leverage ratio covenant, as defined in the agreement, was modified to provide that EXCO will maintain the current maximum leverage ratio of less than 4.00 to 1.00 as of the end of each quarter during 2009. The leverage ratio will decrease as of March 31, 2010 to 3.75 to 1.00 and further decrease as of June 30, 2010 to 3.50 to 1.00. The other financial covenants and all other terms, including the maturity date and borrowing base were not changed.

On April, 17, 2009, we entered into the fourth amendment to the EXCO Resources Credit Agreement which, among other things, reaffirmed a borrowing base of $1.175 billion and increased the interest rate margin by 75 bps. At April 30, 2009, we had $1.064 billion of outstanding indebtedness and $107.8 million of available borrowing capacity under the EXCO Resources Credit Agreement. The borrowing base is redetermined semi-annually with EXCO and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are on or about April 1 and October 1 of each year. The interest rate now ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. Based on the new interest rate margins and a one month LIBO rate of 0.41% on April 30, 2009, we would incur an interest rate of approximately 2.91% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

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 may have in place derivative financial instruments covering no more than 80% of its forecasted production from total proved reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have in place mortgages covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012.

As of March 31, 2009, 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;

• not permit our ratio of consolidated funded indebtedness (as defined) to consolidated EBITDAX (as defined) to be greater than (i) 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2008 up to and including December 31, 2009, (ii) 3.75 to 1.0 at the end of the fiscal quarter ending on March 31, 2010 and (iii) 3.50 to 1.0 beginning with the quarter ending June 30, 2010 and each quarter end thereafter; and

• maintain a consolidated EBITDAX to consolidated interest expense (as defined) ratio of at least 2.5 to 1.0 at the end of any fiscal quarter ending on or after September 30, 2007.

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement.

EXCO Operating Credit Agreement

The EXCO Operating Credit Agreement, as amended, has a borrowing base of $1.3 billion with commitments spread among 33 banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At April 30, 2009 we had $1.233 billion of outstanding indebtedness and $65.3 million of available borrowing capacity under the EXCO Operating Credit Agreement.

The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. On April 17, 2009, we entered into the fourth amendment to the EXCO Operating Credit Agreement, whereby our banking group reaffirmed the existing borrowing base of $1.3 billion and increased our interest rate margins by 75 bps. The interest rate now ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending on borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps, depending upon borrowing base usage. Based on the new interest rate margins and a one month LIBO rate of 0.41% on April 30, 2009, we would incur an interest rate of approximately 2.91% on any new indebtedness we may incur under the EXCO Operating Credit Agreement.

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The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may have in place derivative financial instruments covering no more than 80% of the “forecasted production from total proved reserves” (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total proved reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012.

As of April 30, 2009, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:

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

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

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

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Operating Credit Agreement.

Term Credit Agreement

On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, with an aggregate balance of $300.0 million. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating may incur additional fees on unpaid principal amounts, or duration fees, as defined in the agreement. These include a 5% fee on the unpaid principal on June 15, 2009, and an additional 3% fee on the unpaid outstanding balance on September 15, 2009. Presently, we expect to incur some or all of the duration fees unless cash flow from operations or proceeds from assets sales are sufficient to pay down the loan and are therefore accruing the fees over the term of the loan. The Term Credit Agreement is due and payable on January 15, 2010 and is guaranteed by all existing and future direct or indirect subsidiaries of EXCO Operating, including any guarantor of the EXCO Operating Credit Agreement.

At our election, the Term Credit Agreement may bear interest at a rate per annum equal to (A) the ABR, defined as the highest of (i) the rate of interest publicly announced by JPMorgan as its prime rate in effect at its principal office in New York City, (ii) the federal funds effective rate from time to time plus 0.50%, and (iii) the Adjusted LIBO Rate (defined as the greater of (x) the rate at which eurodollar deposits in the London interbank market for one month are quoted on Reuters BBA Libor Rates Page 3750, as adjusted for actual statutory reserve requirements for eurocurrency liabilities, and (y) 4.0%) plus 1.0%, plus 5.0% or (B) the Adjusted LIBO Rate plus 6.0%. In all cases, the minimum interest rate on the Term Credit Agreement is 10.0%. The Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities that are customary for agreements of this type and are substantially the same as the terms included in the EXCO Operating Credit Agreement. At March 31, 2009, the interest rate on the $300.0 million outstanding on the Term Credit Agreement was 10.0%.

As of March 31, 2009, EXCO Operating was in compliance with the financial covenants contained in the Term Credit Agreement, which require during the period any amounts our outstanding under the Term Credit Agreement, that EXCO Operating:

• maintain a minimum current ratio (as defined) of 1.00 to 1.00 as of the end of any calendar quarter;

• not permit the maximum leverage ratio (as defined) to be greater than 3.50 to 1.00 as of the end of any calendar quarter; and

• not permit our minimum interest coverage ratio (as defined) to be less than 2.50 to 1.00 as of the end of any calendar quarter.

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The foregoing descriptions are not complete and are qualified in their entirety by the Term Credit Agreement.

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

As of March 31, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at March 31, 2009 was $6.7 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $342.4 million on March 31, 2009.

Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year. Effective January 15, 2007, we may redeem some or all of the Senior Notes for the redemption price set forth in the Senior Notes. On January 15, 2009, we paid $16.1 million of interest on the Senior Notes.

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

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

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

• make investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

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

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

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

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, accordingly, 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 derivative contracts is to mitigate the impact of price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and related borrowings under our credit agreements. These transactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase. As of March 31, 2009, we had derivative financial instrument contracts in place for the volumes and prices shown below:

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(in thousands, except prices)	NYMEX gas volume - Mmbtu	Weighted average contract price per Mmbtu		PEPL gas volume - Mmbtu	Weighted average contract price per Mmbtu			NYMEX oil volume - Bbls	Weighted average contract price per Bbl
Swaps:
Q2 2009	25,080	$	8.15	910	$	(1.10	)	394	$	80.64
Q3 2009	25,290		8.15	920		(1.10	)	398		80.66
Q4 2009	25,290		8.18	920		(1.10	)	398		80.66
2010	66,298		7.62	—		—		1,568		104.64
2011	12,775		7.48	—		—		1,095		112.99
2012	5,490		5.91	—		—		92		109.30
2013	5,475		5.99	—		—		—		—

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 LIBO rates ranging from 2.45% to 2.8%. For the three months ended March 31, 2009, we had realized losses from settlements of $1.7 million and $5.8 million of non-cash unrealized gains attributable to 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, 2009:

	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
Long-term debt - Senior Notes (1)	$	—	$	444,720	$	—	$	—	$	444,720
Long-term debt - EXCO Resources Credit Agreement (2)		—		1,063,930		—		—		1,063,930
Long-term debt - EXCO Operating Credit Agreement (3)		—		1,238,469		—		—		1,238,469
Term Credit Agreement (4)		300,000		—		—		—		300,000
Tubular commitment		2,400		—		—		—		2,400
Firm transportation services (5)		26,077		17,797		4,307		446		48,627
Operating leases and construction commitments		8,912		10,802		6,909		3,845		30,468
Drilling contracts		53,527		64,897		8,295		—		126,719
Total contractual cash obligations	$	390,916	$	2,840,615	$	19,511	$	4,291	$	3,255,333

(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 EXCO Operating Credit Agreement matures on March 30, 2012.

(4) The Term Credit Agreement matures on January 15, 2010.

(5) Firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a shippers’ pipeline. Whether or not EXCO delivers the minimum quantity, we pay the fee as if the quantities were delivered. The above table does not include new firm transportation agreements entered into during the first quarter of 2009 with a shipper in the Haynesville shale producing region as this commitment is not effective until the shipper’s pipeline construction is completed. We expect this project to be completed by late 2009 or early 2010.

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.

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Commodity price risk

Our objective in entering into derivative financial instruments is to manage our exposure to commodity price and interest rate fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our acquisition activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

Pricing for oil and natural gas is volatile. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instrument’s fair value currently in earnings, with respect to commodity derivatives, gain (loss) on derivative financial instruments and with respect to interest rate swaps, as interest expense on financial risk management instruments. To illustrate the volatility of oil and natural gas prices and the impact of derivative financial instruments, we had unrealized mark-to-market losses in excess of $916.5 million for the first six months of 2008 on our oil and natural gas derivative financial instruments due to rapidly increasing prices for both oil and natural gas during that period. By the end of the third quarter of 2008 and through the end of 2008, commodity prices decreased substantially and our unrealized mark-to-market gains between July 2008 and December 2008 more than offset the unrealized losses incurred in the first half of the year which resulted in total net unrealized gains in 2008 of $493.7 million on our oil and natural gas derivative financial instruments. Natural gas prices have continued their decline into 2009. We expect that volatility in commodity prices will continue.

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 derivative financial instruments measured at fair value as of
March 31, 2009.

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl			Fair value at March 31, 2009
Natural gas:
Swaps:
Remainder of 2009	75,660	$	8.16		$	278,477
2010	66,298		7.62			107,303
2011	12,775		7.48			10,592
2012	5,490		5.91			(4,384	)
2013	5,475		5.99			(4,737	)
Total natural gas	165,698					387,251
Basis swaps:
Remainder of 2009	2,750		(1.10	)		(486	)
Total basis swaps	2,750					(486	)
Oil:
Swaps:
Remainder of 2009	1,190		80.65			29,570
2010	1,568		104.64			62,752
2011	1,095		112.99			46,856
2012	92		109.30			3,310
Total oil	3,945					142,488
Total oil and natural gas and basis swaps					$	529,253

At March 31, 2009, the average forward NYMEX oil prices per Bbl for the remainder of 2009 and for 2010 were $54.97 and $62.68, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2009 and for 2010 were $4.29 and $5.93, respectively. Our reported earnings and assets or liabilities for derivative financial instruments will continue to be subject to significant fluctuations in value due to price volatility.

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Realized gains or losses from the settlement of our oil and natural gas derivatives are recorded in our financial statements as gains or losses in other income or loss. For example, using the oil swaps in place as of March 31, 2009, for the remainder of 2009, if the settlement price exceeds the actual weighted average strike price of $80.65 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $80.65 per Bbl, multiplied by the hedged volume of 1,190 Mbbls. Conversely, if the settlement price is less than $80.65 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $80.65 per Bbl, multiplied by the hedged volume of 1,190 Mbbls. For example, for a hedged volume of 1,190 Mbbls, if the settlement price is $81.65 per Bbl then other income would decrease by $1.2 million. Conversely, if the settlement price is $79.65 per Bbl, other income would increase by $1.2 million.

Interest rate risk

At March 31, 2009, 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 outstanding on our Senior Notes. Interest is payable on borrowings under our credit agreements and the Term Credit Agreement 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, 2009, we had approximately $2.6 billion in outstanding borrowings under our credit agreements. A 1% change in interest rates based on the variable borrowings as of March 31, 2009 would result in an increase or decrease in our interest costs of $2.6 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBO rates ranging from 2.45% to 2.8%. As of March 31, 2009, the fair value of our interest rate swaps was a liability of $4.1 million.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO’s disclosure controls and procedures were effective as of March 31, 2009 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to EXCO’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO’s internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 6. Exhibits

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

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 6, 2009	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	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.
2.2	Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search, Incorporated, as sellers, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.
2.3	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	Articles of Amendment to the 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 August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.
3.3	Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.
3.4	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.
3.5	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.
3.6	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.
3.7	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.
3.8	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.
3.9	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 an Exhibit to EXCO’s Annual Report on Form 10-K for 2008 filed February 26, 2009 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.

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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 7 1/4% Global Note Due 2011, filed herewith.
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.
4.13	Seventh Supplemental Indenture, dated as of June 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2008 and incorporated by reference herein.
4.14	Eighth Supplemental Indenture, dated as of December 31, 2008, by and among EXCO Resources, Inc., EXCO Mid-Continent MLP, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2008 filed February 26, 2009 and incorporated herein by reference.
10.1	Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2008 filed February 26, 2009 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.

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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 7 1/4% Global Note Due 2011, filed herewith as Exhibit 4.5.
10.7	Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.8	Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.9	Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.10	Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.*
10.11	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.*
10.12	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.
10.13	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.*
10.14	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.
10.15	Amended and Restated Credit Agreement, dated as of March 30, 2007, among EXCO Partners Operating Partnership, LP, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.16	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.
10.17	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.
10.18	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.

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10.19	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.
10.20	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.
10.21	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.
10.22	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.
10.23	Counterpart Agreement, dated February 4, 2008, to that Certain Second Amended and Restated Credit Agreement, dated May 2, 2007, among EXCO Resources, Inc., as Borrower, and certain subsidiaries of Borrower and the lender parties thereto, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.
10.24	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.
10.25	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.
10.26	First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and Energy Search, Incorporated, as sellers, filed as an exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.
10.27	Seventh Supplemental Indenture, dated as of September 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q filed on August 6, 2008 and incorporated by reference herein.
10.28	Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries as guarantors, and JP Morgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K dated July 14, 2008 and filed on July 16, 2008 and incorporated by reference herein.
10.29	Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 14, 2008 and effective as of June 30, 2008, among EXCO Resources, Inc., as borrower, and certain of its subsidiaries, as guarantors, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated July 14, 2008 and filed on July 16, 2008 and incorporated by reference herein.
10.30	Seventh Supplemental Indenture, dated as of June 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2008 and incorporated by reference herein.
10.31	Third Amendment to Amended and Restated Credit Agreement, dated as of December 1, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries, as guarantors, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated December 1, 2008 and filed on December 5, 2008 and incorporated by reference herein.

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10.32	Senior Unsecured Term Credit Agreement, dated as of December 8, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries, as guarantors, and JPMorgan Chase Bank, N.A. as administrative agent, J.P. Morgan Securities Inc., as sole bookrunner and lead arranger, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated December 8, 2008 and filed on December 8, 2008 and incorporated by reference herein.
10.33	Third Amendment to Second Amended and Restated Credit Agreement, dated as of February 4, 2009, among EXCO Resources, Inc., as borrower, and certain of its subsidiaries, as guarantors, and JPMorgran Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated February 4, 2009 and filed on February 5, 2009 and incorporated by reference herein.
10.34	Eighth Supplemental Indenture, dated as of December 31, 2008, by and among EXCO Resources, Inc., EXCO Mid-Continent MLP, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2008 filed February 26, 2009 and incorporated by reference herein.
10.35	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of April 17, 2009, among EXCO Resources, Inc., as borrower, certain of its subsidiaries, as guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated April 17, 2009 and filed on April 20, 2009 and incorporated by reference herein.
10.36	Fourth Amendment to Amended and Restated Credit Agreement, dated as of April 17, 2009, among EXCO Operating Company, LP, as borrower, certain of its subsidiaries, as guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated April 17, 2009 and filed on April 20, 2009 and incorporated by reference herein.
31.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
31.3	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting Officer of EXCO Resources, Inc., filed herewith.
32.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.
99.1	Audit Committee Charter, filed herewith.

* These exhibits are management contracts.

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