Exco Resources (EXCO) 10-Q 2010 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, 2010

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	¨  (Do not check if a smaller reporting company)	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, 2010 was 212,445,984.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at March 31, 2010 and December 31, 2009	3
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2010 and 2009	5
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2010 and 2009	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	46
PART II.	OTHER INFORMATION	47
Item 6.	Exhibits	47
	Signatures	48
	Index to Exhibits	49

2

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	March 31, 2010			December 31, 2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	47,804		$	68,407
Restricted cash		69,988			58,909
Accounts receivable, net:
Oil and natural gas		67,984			56,485
Joint interest		76,408			47,104
Interest and other		53,099			10,832
Inventory		14,580			15,830
Derivative financial instruments		142,474			138,120
Other		7,869			6,401
Total current assets		480,206			402,088
Equity investment in TGGT Holdings, LLC		261,576			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		381,961			492,882
Proved developed and undeveloped oil and natural gas properties		1,989,923			1,875,749
Accumulated depletion		(1,166,623	)		(1,132,604	)
Oil and natural gas properties, net		1,205,261			1,236,027
Gas gathering assets		182,633			180,506
Accumulated depreciation and amortization		(25,023	)		(22,841	)
Gas gathering assets, net		157,610			157,665
Office and field equipment, net		30,381			31,771
Deferred financing costs, net		6,758			7,602
Derivative financial instruments		45,767			34,677
Goodwill		269,656			269,656
Other assets		10,384			2,421
Total assets	$	2,467,599		$	2,358,894

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	March 31, 2010			December 31, 2009
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	89,254		$	112,991
Revenues and royalties payable		95,552			79,356
Accrued interest payable		8,010			16,193
Current portion of asset retirement obligations		900			900
Income taxes payable		210			210
Derivative financial instruments		368			3,264
Current maturities of long term debt		447,779			—
Total current liabilities		642,073			212,914
Long-term debt, net of current maturities		762,543			1,196,277
Deferred income taxes		—			—
Derivative financial instruments		5,908			11,688
Asset retirement obligations and other long-term liabilities		78,354			78,427
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 - 212,238,537 at March 31, 2010 and 211,905,509 at December 31, 2009		212			212
Additional paid-in capital		3,115,167			3,105,238
Accumulated deficit		(2,136,658	)		(2,245,862	)
Total shareholders’ equity		978,721			859,588
Total liabilities and shareholders’ equity	$	2,467,599		$	2,358,894

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended March 31,
(in thousands, except per share data)	2010			2009
Revenues:
Oil and natural gas	$	130,994		$	172,208
Midstream		—			17,013
Total revenues		130,994			189,221
Costs and expenses:
Oil and natural gas production		27,058			53,118
Midstream operating		—			18,450
Gathering and transportation		11,113			3,897
Depreciation, depletion and amortization		38,818			81,794
Write-down of oil and natural gas properties		—			1,293,579
Accretion of discount on asset retirement obligations		1,089			2,071
General and administrative		26,419			20,547
Other operating items		(407	)		(405	)
Total costs and expenses		104,090			1,473,051
Operating income (loss)		26,904			(1,283,830	)
Other income (expense):
Interest expense		(10,634	)		(36,132	)
Gain on derivative financial instruments		99,149			221,384
Other income		60			22
Equity method income in TGGT Holdings, LLC		89			—
Total other income		88,664			185,274
Income (loss) before income taxes		115,568			(1,098,556	)
Income tax expense		—			1,055
Net income (loss)	$	115,568		$	(1,099,611	)
Earnings (loss) per common share:
Basic
Net income (loss)	$	0.54		$	(5.21	)
Weighted average common shares outstanding		212,086			210,995
Diluted
Net income (loss)	$	0.54		$	(5.21	)
Weighted average common and common equivalent shares outstanding		215,666			210,995

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended March 31,
(in thousands)	2010			2009
Operating Activities:
Net income (loss)	$	115,568		$	(1,099,611	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		38,818			81,794
Stock option compensation expense		4,609			3,223
Accretion of discount on asset retirement obligations		1,089			2,071
Write-down of oil and natural gas properties		—			1,293,579
Income from equity investment in TGGT Holdings, LLC		(89	)		—
Non-cash change in fair value of derivatives		(24,120	)		(128,741	)
Cash settlements of assumed derivatives		907			(37,616	)
Deferred income taxes		—			1,055
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011		(90	)		11,758
Effect of changes in:
Accounts receivable		(40,548	)		43,862
Other current assets		(1,680	)		(1,152	)
Accounts payable and other current liabilities		(3,161	)		(64,896	)
Net cash provided by operating activities		91,303			105,326
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(124,223	)		(189,992	)
Property acquisitions		(10,943	)		—
Restricted cash		(11,079	)		—
Equity investment in TGGT Holdings, LLC		(44,500	)		—
Proceeds from disposition of property and equipment		66,925			5,477
Net cash used in investing activities		(123,820	)		(184,515	)
Financing Activities:
Borrowings under credit agreements		39,960			34,963
Repayments under credit agreements		(24,981	)		—
Proceeds from issuance of common stock		4,206			447
Payment of common stock dividends		(6,364	)		—
Settlements of derivative financial instruments with a financing element		(907	)		37,616
Deferred financing costs and other		—			(5,468	)
Net cash provided by financing activities		11,914			67,558
Net decrease in cash		(20,603	)		(11,631	)
Cash at beginning of period		68,407			57,139
Cash at end of period	$	47,804		$	45,508
Supplemental Cash Flow Information:
Cash interest payments	$	21,041		$	48,933
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	1,105		$	507
Capitalized interest	$	2,915		$	1,361
Issuance of common stock for director services	$	9		$	17

See accompanying notes.

6

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

				Additional paid-in capital		Retained earnings (deficit)			Total shareholders’ equity
	Common Stock
(in thousands)	Shares	Amount
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
Balance at December 31, 2009	211,905	$	212	$	3,105,238	$	(2,245,862	)	$	859,588
Issuance of common stock	334		—		4,215		—			4,215
Share-based compensation	—		—		5,714		—			5,714
Common stock dividends	—		—		—		(6,364	)		(6,364	)
Net income	—		—		—		115,568			115,568
Balance at March 31, 2010	212,239	$	212	$	3,115,167	$	(2,136,658	)	$	978,721

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.

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in the East Texas, North Louisiana, Appalachia, and Permian producing areas. In addition to our oil and natural gas producing operations, as of August 14, 2009, we hold a 50% equity interest in a midstream joint venture in the East Texas/North Louisiana area.

Our assets in East Texas/North Louisiana, including our equity interest in the midstream operations, are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries, collectively, EXCO Operating. We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and exploitation projects and entering into beneficial joint development agreements. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments, and manage our capital structure.

The accompanying Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three months ended March 31, 2010 and 2009, 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, 2010 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, 2009.

On August 14, 2009, we closed the sale to an affiliate of BG Group plc, or BG Group, of a 50% interest in a newly formed company, TGGT Holdings, LLC, or TGGT, which now holds most of our East Texas/North Louisiana midstream assets, or the BG Midstream Transaction. As a result of the BG Midstream Transaction we no longer report our midstream operations as a separate business segment. Effective August 14, 2009, we account for the jointly-held midstream operations as an equity method investment. The net operations of our gathering system in Louisiana that supports our Vernon Field operations, which was previously reported within our midstream segment and was not included in the BG Midstream Transaction, is now reported in “Gathering and transportation” on the Condensed Consolidated Statement of Operations.

Beginning December 31, 2009, we reclassified certain items that relate to our operations from “Other income” into “Other operating items.” Prior year amounts have been reclassified to conform to current year reporting.

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.

8

2. Recent accounting pronouncements

On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009. See “Note 8. Derivative financial instruments and fair value measurements” for the impact to our 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 and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2009.

4. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2010:

(in thousands)
Asset retirement obligation at January 1, 2010	$	65,115
Activity during the three months ended March 31, 2010:
Liabilities incurred during the period		185
Liabilities settled during the period		(433	)
Accretion of discount		1,089
Asset retirement obligations at March 31, 2010		65,956
Less current portion		900
Long-term portion	$	65,056

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 require 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 exploration, exploitation, development and acquisition 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 $382.0 million and $492.9 million as of March 31, 2010 and December 31, 2009, respectively, are not subject to depletion. The $110.9 million decrease in our unproved properties between December 31, 2009 and March 31, 2010 was due primarily from reimbursements of acreage costs from BG Group. No impairment of undeveloped properties occurred during the first quarter of 2010. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment and transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds.

When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with FASB ASC Subtopic 835-20 for Capitalization of Interest. We began capitalizing interest in April 2008, upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. The cost of these projects, net of any amortized or transferred amounts into the depletable full cost pool was $258.8 million as of March 31, 2010. When the balance is moved to proved developed and undeveloped oil and natural gas properties, we will cease capitalizing interest.

9

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 are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our 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 and/or the relationship between capitalized costs and Proved Reserves.

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, calculated as the sum of the estimated future net revenues from Proved Reserves using the simple average spot price for the trailing twelve month period using the first day of each month. For the three months ended March 31, 2010, the trailing twelve month price was $69.64 per Bbl for oil at Cushing, Oklahoma and $3.99 per Mmbtu for natural gas at Henry Hub. 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. There was no ceiling test write-down for the first quarter of 2010.

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 full cost accounting rules in place prior to the SEC’s Release No. 33-8995 on December 31, 2009, the SEC required the full cost ceiling to be computed using spot market prices for oil and natural gas at our balance sheet date. 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.

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

6. Earnings (loss) per share

We account for earnings per share in accordance with FASB ASC Subtopic 260-10 for Earnings Per Share. ASC 260-10 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, 2010 and 2009 equals the net income (loss) divided by the weighted average common shares outstanding during the period. Diluted earnings (loss) per common share for the three months ended March 31, 2010 and 2009 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, whether exercisable or not. Antidilutive options represented by 684,952 potential common stock equivalents were excluded from the three months ended March 31, 2010 diluted earnings per share. Since we incurred a net loss for the three months ended March 31, 2009, we have excluded the potential common stock equivalents from the assumed conversion of 14,889,280 stock options.

10

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

	Three months ended March 31,
(in thousands, except per share amount)	2010		2009
Basic income (loss) per common share:
Net income (loss)	$	115,568	$	(1,099,611	)
Shares:
Weighted average number of common shares outstanding		212,086		210,995
Basic income (loss) per common share:
Net income (loss) per common share	$	0.54	$	(5.21	)
Diluted income (loss) per share:
Net income (loss)	$	115,568	$	(1,099,611	)
Shares:
Weighted average number of common shares outstanding		212,086		210,995
Dilutive effect of stock options		3,580		—
Weighted average number of common shares and common stock equivalent shares outstanding		215,666		210,995
Diluted income (loss) per share:
Net income (loss) per common share	$	0.54	$	(5.21	)

7. Stock options

We account for stock options in accordance with FASB ASC Topic 718 for Compensation – Stock Compensation Topic. As required by ASC 718, 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. Total share-based compensation to be recognized on unvested awards as of March 31, 2010 is $27.0 million over a weighted average period of 1.28 years.

The following is a reconciliation of our stock option expense for the three months ended March 31, 2010 and 2009:

	Three months ended March 31,
(in thousands)	2010		2009
General and administrative expense	$	4,259	$	2,526
Lease operating expense		350		697
Total share-based compensation expense		4,609		3,223
Share-based compensation capitalized		1,105		507
Total share-based compensation	$	5,714	$	3,730

During the three months ended March 31, 2010, options to purchase 186,700 shares were granted under the 2005 Incentive Plan at prices ranging from $18.38 to $22.22 per share with fair values ranging from $10.47 to $12.77 per share. 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. 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, 2010 and December 31, 2009, there were 3,803,075 and 3,920,100 shares available to be granted under the 2005 Incentive Plan, respectively.

In connection with certain divestitures, we accelerated the vesting of a number of employee stock options on the date of the employee’s termination and extended their exercise terms to one year from date of termination. We recognized $0.9 million in additional compensation expense related to the modification of option terms, $0.5 million of which would have been recognized over the remaining life of the options had they not been accelerated. The underlying stock price on the dates of modification ranged from $17.54 to $21.23 and the exercise prices of the options accelerated ranged from $7.50 to $24.66.

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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 FASB ASC Topic 815. ASC 815 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. ASC 815 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 ASC 815 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 FASB ASC Section 815-10-65, 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, 2010			December 31, 2009
Commodity contracts	Derivative financial instruments - Current assets	$	142,474		$	138,120
Commodity contracts	Derivative financial instruments - Long-term assets		45,767			34,677
Commodity contracts	Derivative financial instruments - Current liabilities		(368	)		(1,246	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(5,908	)		(11,688	)
Interest rate contracts	Derivative financial instruments - Current liabilities		—			(2,018	)
Net derivatives		$	181,965		$	157,845

The Effect of Derivative Financial Instruments

		Three months ended March 31,
(in thousands)	Statement of Operations location	2010			2009
Commodity contracts (1)	Gain on derivative financial instruments	$	99,149		$	221,384
Interest rate contracts (2)	Interest income (expense)		(45	)		4,116
Net gain		$	99,104		$	225,500

(1) Included in these amounts are net cash receipts of $77,047 and $98,429 for the three months ended March 31, 2010 and 2009, respectively.

(2) Included in these amounts are net cash payments of $2,063 and $1,670 for the three months ended March 31, 2010 and 2009, respectively.

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 $22.1 million and $123.0 million for the three months ended March 31, 2010 and 2009, respectively. Unrealized fair value adjustments included in “Interest expense,” which do not impact cash flows, were gains of $2.0 million and $5.8 million for the three months ended March 31, 2010 and 2009, respectively.

We place our derivative financial instruments with the financial institutions that are lenders under our credit agreements and we believe they all 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, 2010 and December 31, 2009, we had a net asset position of $182.0 million and $157.8 million, respectively.

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Fair value measurements

We value our derivatives according to FASB ASC Topic 820 for Fair Value Measurements and Disclosures, 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 as of March 31, 2010 and as of December 31, 2009:

	March 31, 2010
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	181,965		$	—	$	181,965
	December 31, 2009
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	159,863		$	—	$	159,863
Interest rate swaps		—		(2,018	)		—		(2,018	)
	$	—	$	157,845		$	—	$	157,845

In accordance with FASB ASC Section 815-10-45 for the Scope Section of Subtopic 815-10 for Derivatives and Hedging, 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 primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined 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 and (iii) the applicable estimated credit-adjusted risk-free rate curve, as described above.

13

Natural gas derivatives. Our natural gas derivatives are swap contracts for notional Mmbtus of natural gas at posted price indexes, using NYMEX Henry Hub. 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 Henry Hub for natural gas swaps for our existing basis swaps and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

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, 2010:

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2010
Natural gas:
Swaps:
Remainder of 2010	41,683	$	7.18	$	120,466
2011	20,075		7.04		33,602
2012	9,150		6.11		2,887
2013	5,475		5.99		(365	)
Total natural gas	76,383				156,590
Oil:
Swaps:
Remainder of 2010	337		114.96		10,025
2011	456		116.00		13,375
2012	92		109.30		1,975
Total oil	885				25,375
Total oil and natural gas derivatives				$	181,965

At December 31, 2009, we had outstanding derivative contracts to mitigate price volatility covering 88,213 Mmcf of natural gas and 995 Mbbls of oil. At March 31, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $84.96 and $86.13, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2010 and for 2011 were $4.27 and $5.34, respectively.

Our derivative financial instruments to mitigate price volatility covered 66.4% and 74.9% of our total equivalent Mcfe production for the three months ended March 31, 2010 and 2009, 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 LIBOR 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 LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. We classified our interest rate swaps and their related fair value tier as Level 2.

During the three months ended March 31, 2010 and 2009, we recognized $0.1 million as an increase to interest expense and $4.1 million as a decrease to interest expense, respectively, on our interest rate swaps.

Our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of March 31, 2010.

14

Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable, current portion of debt and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature.

The estimated fair value of our 7 ¹/4% senior notes due January 15, 2011, or Senior Notes, is $445.9 million with a carrying amount of $447.8 million as of March 31, 2010. The estimated fair value has been calculated based on market quotes.

9. Current and long-term debt

Our total debt is summarized as follows:

(in thousands)	March 31, 2010		December 31, 2009
Long term debt:
EXCO Resources Credit Agreement	$	96,465	$	81,486
EXCO Operating Credit Agreement		666,078		666,078
7 1/4% senior notes due January 15, 2011		444,720		444,720
Unamortized premium on 7 1/4% senior notes due January 15, 2011		3,059		3,993
Total debt		1,210,322		1,196,277
Less current maturities		447,779		—
Total long term debt	$	762,543	$	1,196,277

Credit agreements

EXCO Resources Credit Agreement

The EXCO Resources credit agreement, as amended, or the EXCO Resources Credit Agreement, had a borrowing base of $450.0 million as of March 31, 2010, of which $96.5 million was drawn with $338.4 million of available borrowing capacity.

The interest rate ranges from LIBOR plus 175 basis points, or 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.

On April 30, 2010, the EXCO Resources Credit Agreement was amended (see “Note 14. Subsequent events”).

Pursuant to the April 30, 2010 amendment to the EXCO Resources Credit Agreement, EXCO Resources was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement as of March 31, 2010.

EXCO Operating Credit Agreement

The EXCO Operating credit agreement, as amended, or the EXCO Operating Credit Agreement, had a borrowing base of $850.0 million at March 31, 2010 of which $666.1 was drawn with $183.9 million of available borrowing capacity.

The interest rate under the EXCO Operating Credit Agreement ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon 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.

On April 30, 2010, the EXCO Operating Credit Agreement was consolidated into the EXCO Resources Credit Agreement (see “Note 14. Subsequent events”).

Pursuant to the April 30, 2010 amendment to the EXCO Resources Credit Agreement, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement as of March 31, 2010.

15

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

As of March 31, 2010 and December 31, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at March 31, 2010 and December 31, 2009 was $3.1 million and $4.0 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.9 million on March 31, 2010. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.

10. Dividends

On February 22, 2010 our Board of Directors approved a first quarter 2010 cash dividend equal to $0.03 per share. The total cash dividend of $6.4 million was paid on March 19, 2010 to holders of record on March 5, 2010. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under our credit agreement, as amended, our Senior Notes and the approval of EXCO’s Board of Directors.

11. 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 cumulative financial operating losses, we have recognized valuation allowances of approximately $631.7 million until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowance does not impact future utilization of the underlying tax attributes.

12. Operating Segments

We follow FASB ASC Topic 280 for Segment Reporting when reporting operating segments. Prior to the BG Midstream Transaction where we sold a 50% interest in most of our East Texas/North Louisiana midstream operations, our reportable segments consisted of exploration and production and midstream. Our exploration and production operational segment and midstream segment were 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 was responsible for purchasing, gathering, transporting, processing and treating natural gas. We evaluated the performance of our operating segments based on segment profits, which included segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and segment costs and expenses. Segment profit generally excluded income taxes, interest income, interest expense, unallocated corporate expenses, depreciation and depletion, asset retirement obligations, and gains and losses associated with ceiling test write-downs and asset sales, other income and expense, and income from equity investments.

As a result of the BG Midstream Transaction, we reviewed the criteria outlined in ASC 280-10 and determined that the midstream assets we retained, made up exclusively of the Vernon Field midstream assets, were not material and therefore, would no longer meet thresholds to be defined as a reportable segment. We also reviewed our equity investment in TGGT and concluded that it also would not be considered a reportable segment. We now account for our interest in TGGT using the equity method (see “Note 13. Equity investment”).

The reportable midstream segment for 2009 is effective from January 1, 2009 through August 13, 2009. The Vernon Field midstream assets operations are included in the exploration and production segment effective August 14, 2009.

16

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, 2010:
Third party revenues	$	130,994		$	—	$	—		$	130,994
Intersegment revenues		—			—		—			—
Total revenues	$	130,994		$	—	$	—		$	130,994
Segment profits	$	92,823		$	—	$	—		$	92,823
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 profits	$	107,211		$	6,545	$	—		$	113,756
As of March 31, 2010:
Capital expenditures	$	130,491		$	—	$	—		$	130,491
Goodwill	$	269,656		$	—	$	—		$	269,656
Total assets	$	2,467,599		$	—	$	—		$	2,467,599
As of December 31, 2009:
Capital expenditures	$	458,410		$	53,122	$	—		$	511,532
Goodwill	$	269,656		$	—	$	—		$	269,656
Total assets	$	2,358,894		$	—	$	—		$	2,358,894

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

	Three months ended March 31,
(in thousands)	2010			2009
Segment profits	$	92,823		$	113,756
Depreciation, depletion and amortization		(38,818	)		(81,794	)
Write-down of oil and natural gas properties		—			(1,293,579	)
Other operating items		407			405
Accretion of discount on asset retirement obligations		(1,089	)		(2,071	)
General and administrative		(26,419	)		(20,547	)
Interest expense		(10,634	)		(36,132	)
Gain on derivative financial instruments		99,149			221,384
Other income		60			22
Equity method income in TGGT Holdings, LLC		89			—
Income (loss) before income taxes	$	115,568		$	(1,098,556	)

17

13. Equity investment

Our 50% ownership interest in TGGT is accounted for under the equity method. The following tables present summarized financial information of TGGT and a reconciliation of our investment to our proportionate 50% interest in TGGT’s equity:

(in thousands)	March 31, 2010
Assets
Total current assets	$	90,186
Property and equipment, net		577,349
Total assets	$	667,535
Liabilities and members’ equity
Total current liabilities	$	52,834
Total long-term liabilities		5,316
Members’ equity:
Total members’ equity		609,385
Total liabilities and members’ equity	$	667,535
	Three months ended March 31, 2010
Revenues
Gas sales	$	16,130
Condensate, shrinkage and loss revenues		2,040
Gathering, compression and other services		13,614
Total revenues		31,784
Costs and expenses:
Gas purchases		16,418
Operating expenses		9,305
Depreciation expense		3,699
Other expenses		2,922
Total costs and expenses		32,344
Loss before income taxes		(560	)
Income tax expense		67
Net loss	$	(627	)
EXCO’s equity in TGGT loss before amortization	$	(314	)
Amortization of the difference in the historical basis of our contribution	$	403
EXCO’s equity in TGGT earnings after amortization	$	89
(in thousands)	March 31, 2010
Investment in TGGT	$	261,576
Basis adjustment (1)		44,137
Cumulative amortization of basis adjustment (2)		(1,020	)
EXCO’s 50% interest in TGGT’s March 31, 2010 equity	$	304,693

(1) Our equity investment in TGGT exceeds our book value of assets by $44.1 million represented by $55.5 million difference in the historical basis of our contribution and the fair value of BG Group’s contribution offset by $11.4 million of goodwill included in our investment.

(2) The $55.5 million basis difference is being amortized over the estimated life of TGGT's assets.

14. Subsequent events

Subsequent to March 31, 2010, we entered into several significant transactions as discussed below.

On April 21, 2010, EXCO announced a joint acquisition by EXCO Operating and an affiliate of BG Group of all the membership interests in Common Resources, L.L.C. for $446.0 million ($223.0 million net to EXCO Operating), subject to customary preliminary and final purchase price adjustments. The Common Resources entity, which will be owned equally by EXCO Operating and the BG affiliate, holds approximately 29,200 net undeveloped acres, seven producing natural gas wells, and gathering lines in the Haynesville and Bossier shale areas of East Texas. We expect the acquisition to close in May 2010.

18

On April 30, 2010, we amended and restated the EXCO Resources Credit Agreement which consolidated the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement into one credit agreement with a borrowing base of $1.3 billion. Terms of the amended and restated agreement include, among other things, EXCO Operating and certain of its subsidiaries becoming guarantor subsidiaries under the EXCO Resources Credit Agreement and our Senior Notes. The amended EXCO Resources Credit Agreement matures on April 30, 2014.

15. 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, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some of our subsidiaries (referred to as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources (defined below), and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish us from the Guarantor Subsidiaries. The Non-Guarantor Subsidiaries represent the consolidated financials of EXCO Operating. As discussed in “Note 14. Subsequent events,” the amendment of the EXCO Resources Credit Agreement resulted in EXCO Operating and certain of its subsidiaries becoming Guarantor Subsidiaries effective in the second quarter of 2010.

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

• Resources;

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries;

• elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and

• EXCO on a consolidated basis.

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

19

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

March 31, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	21,201		$	(7,762	)	$	34,365		$	—		$	47,804
Restricted cash		—			—			69,988			—			69,988
Other current assets		51,857			21,665			288,892			—			362,414
Total current assets		73,058			13,903			393,245			—			480,206
Equity investment in TGGT Holdings, LLC		—			—			261,576			—			261,576
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		47,598			126,686			207,677			—			381,961
Proved developed and undeveloped oil and natural gas properties		344,693			324,146			1,321,084			—			1,989,923
Accumulated depletion		(280,455	)		(178,480	)		(707,688	)		—			(1,166,623	)
Oil and natural gas properties, net		111,836			272,352			821,073			—			1,205,261
Gas gathering, office and field equipment, net		8,495			46,029			133,467			—			187,991
Investments in and advances to affiliates		284,862			—			—			(284,862	)		—
Deferred financing costs, net		2,815			—			3,943			—			6,758
Derivative financial instruments		33,824			—			11,943			—			45,767
Goodwill		38,100			164,469			67,087			—			269,656
Other assets		1			919			9,464			—			10,384
Total assets	$	552,991		$	497,672		$	1,701,798		$	(284,862	)	$	2,467,599
Liabilities and shareholders’ equity
Current liabilities	$	474,905		$	17,557		$	149,611		$	—		$	642,073
Long-term debt		96,465			—			666,078			—			762,543
Deferred income taxes		—			—			—			—			—
Other liabilities		5,021			43,213			36,028			—			84,262
Payable to parent		(1,002,121	)		906,548			95,573			—			—
Total shareholders’ equity		978,721			(469,646	)		754,508			(284,862	)		978,721
Total liabilities and shareholders’ equity	$	552,991		$	497,672		$	1,701,798		$	(284,862	)	$	2,467,599

20

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2009

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	47,412		$	(4,154	)	$	25,149		$	—		$	68,407
Restricted cash		—			—			58,909			—			58,909
Other current assets		69,449			20,922			184,401						274,772
Total current assets		116,861			16,768			268,459			—			402,088
Equity investment in TGGT Holdings, LLC		—			—			216,987			—			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		54,570			99,812			338,500			—			492,882
Proved developed and undeveloped oil and natural gas properties		328,135			302,323			1,245,291			—			1,875,749
Accumulated depletion		(274,275	)		(174,268	)		(684,061	)		—			(1,132,604	)
Oil and natural gas properties, net		108,430			227,867			899,730			—			1,236,027
Gas gathering, office and field equipment, net		8,175			46,558			134,703			—			189,436
Investments in and advances to affiliates		198,661			—			—			(198,661	)		—
Deferred financing costs, net		3,166			—			4,436			—			7,602
Derivative financial instruments		31,312			—			3,365			—			34,677
Goodwill		38,100			164,469			67,087			—			269,656
Other assets		3			818			1,600			—			2,421
Total assets	$	504,708		$	456,480		$	1,596,367		$	(198,661	)	$	2,358,894
Liabilities and shareholders’ equity
Current liabilities	$	39,917		$	16,376		$	156,621		$	—		$	212,914
Long-term debt		530,199			—			666,078			—			1,196,277
Deferred income taxes		—			—			—			—			—
Other liabilities		5,998			46,963			37,154			—			90,115
Payable to parent		(930,994	)		862,536			68,458			—			—
Total shareholders’ equity		859,588			(469,395	)		668,056			(198,661	)		859,588
Total liabilities and shareholders’ equity	$	504,708		$	456,480		$	1,596,367		$	(198,661	)	$	2,358,894

21

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	17,645		$	19,354		$	93,995		$	—		$	130,994
Costs and expenses:
Oil and natural gas production		3,956			5,686			17,416			—			27,058
Gathering and transportation		—			446			10,667			—			11,113
Depreciation, depletion and amortization		7,150			5,661			26,007			—			38,818
Accretion of discount on asset retirement obligations		83			572			434			—			1,089
General and administrative		7,645			5,269			13,505			—			26,419
Other operating items		(602	)		(278	)		473			—			(407	)
Total costs and expenses		18,232			17,356			68,502			—			104,090
Operating income (loss)		(587	)		1,998			25,493			—			26,904
Other income (expense):
Interest expense		(7,074	)		—			(3,560	)		—			(10,634	)
Gain on derivative financial instruments		30,854			3,912			64,383			—			99,149
Other income (expense)		6,174			(6,161	)		47			—			60
Equity method income in TGGT Holdings, LLC		—			—			89			—			89
Equity in earnings of subsidiaries		86,201			—			—			(86,201	)		—
Total other income (expense)		116,155			(2,249	)		60,959			(86,201	)		88,664
Net Income (loss)	$	115,568		$	(251	)	$	86,452		$	(86,201	)	$	115,568

22

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
Other operating items		(303	)		(194	)		92			—		(405	)
Total costs and expenses		314,822			309,511			848,718			—		1,473,051
Operating income (loss)		(276,740	)		(279,482	)		(727,608	)		—		(1,283,830	)
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		6,187			(6,165	)		—			—		22
Equity in earnings of subsidiaries		(923,281	)		—			—			923,281		—
Total other income (expense)		(821,816	)		3,113			80,696			923,281		185,274
Income (loss) before income taxes		(1,098,556	)		(276,369	)		(646,912	)		923,281		(1,098,556	)
Income tax benefit		1,055			—			—			—		1,055
Net income (loss)	$	(1,099,611	)	$	(276,369	)	$	(646,912	)	$	923,281	$	(1,099,611	)

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	40,670		$	753		$	49,880		$	—	$	91,303
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(8,833	)		(47,331	)		(79,002	)		—		(135,166	)
Restricted cash		—			—			(11,079	)		—		(11,079	)
Equity investment in TGGT Holdings, LLC		—			—			(44,500	)		—		(44,500	)
Proceeds from dispositions		22			(42	)		66,945			—		66,925
Advances/investments with affiliates		(69,984	)		43,012			26,972			—		—
Net cash provided used in investing activities		(78,795	)		(4,361	)		(40,664	)		—		(123,820	)
Financing Activities:
Borrowings under credit agreements		14,979			—			24,981			—		39,960
Repayments under credit agreements		—			—			(24,981	)		—		(24,981	)
Proceeds from issuance of common stock, net		4,206			—			—			—		4,206
Payment of common stock dividends		(6,364	)		—			—			—		(6,364	)
Settlement of derivative financial instruments with a financing element		(907	)		—			—			—		(907	)
Net cash used in financing activities		11,914			—			—			—		11,914
Net increase (decrease) in cash		(26,211	)		(3,608	)		9,216			—		(20,603	)
Cash at the beginning of the period		47,412			(4,154	)		25,149			—		68,407
Cash at end of period	$	21,201		$	(7,762	)	$	34,365		$	—	$	47,804

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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

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

Unless the context requires otherwise, references to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

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;

• 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, legislation of derivative financial instruments and elimination of income tax incentives available to our industry;

• 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;

• potential acts of terrorism;

• 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.

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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, 2009.

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 facility 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 exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in the East Texas, North Louisiana, Appalachia and Permian producing areas. In addition to our oil and natural gas producing operations, we hold a 50% equity interest in a midstream joint venture in East Texas/North Louisiana. Our assets in East Texas/North Louisiana, including our equity interest in midstream operations, are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries, collectively, EXCO Operating.

Historically, we used acquisitions and vertical drilling as our vehicle for growth. As a result of our acquisitions, we accumulated an inventory of drilling locations and acreage holdings with significant potential in the Haynesville/Bossier and Marcellus shale resource plays. During 2009 we focused our efforts into developing these shale assets by entering into a joint venture with BG Group plc, or BG Group, in East Texas/North Louisiana, or the BG Upstream Transaction, accelerating the development of our Haynesville shale assets within the joint venture, and disposing of our non-strategic assets, including our Mid-Continent division, Rockies division, and certain non-strategic Appalachia, East Texas/North Louisiana and Permian assets. In addition, we closed the sale to an affiliate of BG Group of a 50% interest in a newly formed company which now holds most of our East Texas/North Louisiana midstream assets, or the BG Midstream Transaction. We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations, accumulating undeveloped acreage in shale areas, exploitation projects and entering into joint venture transactions.

We intend to exploit these shales primarily through horizontal drilling. Future acquisitions are likely to be focused on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We will continue to develop certain vertical drilling opportunities in our East Texas/North Louisiana, Appalachia and Permian areas as industry economic conditions permit.

Our credit agreement, as amended on April 30, 2010, or the EXCO Resources Credit Agreement, has a borrowing base of $1.3 billion, of which $817.5 million was drawn as of April 30, 2010. Available borrowing capacity was $467.3 million as of April 30, 2010.

For the three months ended March 31, 2010, we produced 23.8 Bcfe of oil and natural gas, with March 2010 daily production of 278 Mmcfe. Of the amount produced, 18.8 Bcfe were produced in our East Texas/North Louisiana division, 3.3 Bcfe were produced in our Appalachia division and 1.7 Bcfe were produced in our Permian division.

Our plans for 2010 are focused on the Haynesville/Bossier and Marcellus shales. Our budgeted capital expenditures for 2010 total $538.6 million, of which $409.4 million is allocated to these shale resource plays. Our East Texas/North Louisiana capital expenditures are favorably impacted by our joint development agreement with BG Group, which includes a $400.0 million carry equal to 75% of our share of drilling and completion costs within our joint venture area, or the BG Carry. During the first quarter of 2010, we spent $68.6 million in East Texas/North Louisiana, $51.0 million of which was in the area of mutual interest with BG Group, or the BG AMI, and reflects the favorable impact of the BG Carry. As of March 31, 2010, the remaining balance of the BG Carry was approximately $313.8 million. In Appalachia we spent $42.0 million during the first quarter of 2010 and our remaining planned capital expenditures are expected to total $112.3 million.

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For the three months ended March 31, 2010, we made $44.5 million in equity contributions to the midstream joint venture owned equally by EXCO and BG Group that owns the midstream assets located within the BG AMI, or TGGT. Our remaining 2010 capital budget includes $30.5 million in equity contributions to TGGT. The remaining TGGT capital budget for 2010 is $168.4 million, $84.2 million net to EXCO’s interest. The management of TGGT is also evaluating several expansion projects which, if approved, will require additional capital contributions.

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.

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, 2009.

Recent accounting pronouncements

On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009. See “Note 8. Derivative financial instruments and fair value measurements” in Notes to Condensed Consolidated Financial Statements for the impact to our disclosures.

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Our results of operations

A summary of key financial data for the three months ended March 31, 2010 and 2009 related to our results of operations is presented below:

	Three months ended March 31,					Quarter to quarter change 2010-2009
(dollars in thousands, except per unit prices)	2010		2009
Production:
Oil (Mbbls)		159		527			(368	)
Natural gas (Mmcf)		22,837		33,184			(10,347	)
Total production (Mmcfe) (1)		23,791		36,346			(12,555	)
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	11,963	$	19,696		$	(7,733	)
Natural gas		119,031		152,512			(33,481	)
Total oil and natural gas	$	130,994	$	172,208		$	(41,214	)
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	77,047	$	98,429		$	(21,382	)
Non-cash change in fair value of derivative financial instruments		22,102		122,955			(100,853	)
Total derivative financial instrument activities	$	99,149	$	221,384		$	(122,235	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	75.24	$	37.37		$	37.87
Natural gas (per Mcf)		5.21		4.60			0.61
Natural gas equivalent (per Mcfe)		5.51		4.74			0.77
Costs and expenses:
Oil and natural gas operating costs (2)	$	19,193	$	40,686		$	(21,493	)
Production and ad valorem taxes		7,865		12,432			(4,567	)
Gathering and transportation		11,113		3,897			7,216
Depletion		34,020		74,984			(40,964	)
Depreciation and amortization		4,798		6,810			(2,012	)
General and administrative (3)		26,419		20,547			5,872
Interest expense, net, including impacts of interest rate swaps		10,634		36,132			(25,498	)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.81	$	1.12		$	(0.31	)
Production and ad valorem taxes		0.33		0.34			(0.01	)
Gathering and transportation		0.47		0.11			0.36
Depletion		1.43		2.06			(0.63	)
Depreciation and amortization		0.20		0.19			0.01
General and administrative		1.11		0.57			0.54
Net income (loss)	$	115,568	$	(1,099,611	)	$	1,215,179

(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 $0.4 million and $0.7 million for the three months ended March 31, 2010 and 2009, respectively.

(3) Share-based compensation included in general and administrative expenses is $4.3 million and $2.5 million for the three months ended March 31, 2010 and 2009, respectively.

The following is a discussion of our financial condition and results of operations for the three months ended March 31, 2010 and 2009.

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

• the BG Upstream Transaction;

• 2009 divestitures;

• 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, including the impact of SEC Release No, 33-8995 effective December 31, 2009, and their impact on depletion;

• a ceiling test write-down in the first quarter of 2009; and

• the BG Midstream Transaction and related adoption of the equity method of accounting for our investment in TGGT;

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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 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, 2010, we reported a net income available to common shareholders of $115.6 million, compared to a net loss available to common shareholders of $1.1 billion for the quarter ended March 31, 2009. The loss in the first quarter of 2009 was primarily due to a non-cash ceiling test write-down of $1.3 billion.

During 2009 we initiated and completed an aggressive divestiture program to sell our non-strategic properties and also entered into joint venture agreements with BG Group involving most of our East Texas/North Louisiana assets and midstream operations.

Proceeds from these divestitures and joint venture transactions, along with other non-strategic asset sales, were approximately $2.1 billion, resulting in decreases in our full cost pool, gathering assets, and operating assets and liabilities. In addition, we recorded gains on these divestitures totaling approximately $691.9 million. When comparing first quarter 2010 to first quarter 2009, these transactions result in significant declines in our production of oil and natural gas revenues and operating costs. These divestitures will impact comparability of our 2010 and 2009 results of operations throughout 2010. Accordingly, we are presenting certain pro forma comparisons to facilitate understanding of operating data. Also, as a result of the BG Midstream Transaction, we no longer have a midstream segment, with the exception of the activity related to our Vernon gathering system, which is now recorded net in “Gathering and transportation” on our Condensed Consolidated Statement of Operations. Offsetting these declines is a reduction in our depletion and depreciation expense of $43.0 million, no requirement for a ceiling test write-down in the first quarter of 2010, increases in our average sale prices and decreases in our oil and natural gas operating costs.

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 production, revenues, and prices

Total equivalent production volumes were 23.8 Bcfe for the three months ended March 31, 2010, a 34.5% decrease over the prior year’s comparable period production of 36.3 Bcfe. While these declines are a result of the divestitures and the BG Upstream Transaction discussed above, management believes that analyzing the production on a pro forma basis, assuming the divestitures and joint venture transaction had occurred on January 1, 2009, provides a more meaningful analysis of the on-going production activity.

	Three months ended March 31,
	2010	2009				Quarter to quarter change
(in Mmcfe)	Actual production	Actual production	Pro forma adjustment (1)		Pro forma production	Actual production		2010 Actual vers 2009 pro forma production
Producing region:
East Texas/North Louisiana	18,753	22,616	(7,246	)	15,370	(3,863	)	3,383
Appalachia	3,341	5,125	(1,476	)	3,649	(1,784	)	(308	)
Permian and other	1,697	2,853	(500	)	2,353	(1,156	)	(656	)
Mid-Continent	—	5,752	(5,752	)	—	(5,752	)	—
Total	23,791	36,346	(14,974	)	21,372	(12,555	)	2,419

(1) The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by the BG Upstream Transaction as if these sales had occurred on January 1, 2009.

On a pro forma basis, production in our East Texas/North Louisiana region for the three months ended March 31, 2010 increased by 3.4 Bcfe, or 22.0%, from the same period in the prior year. This increase was a result of the continued successful development of our Haynesville shale, which resulted in a production increase over the same period in the prior year of 7.8 Bcfe, offset by production declines of 1.5 Bcfe in our Cotton Valley area and 2.9 Bcfe in our Vernon Field, resulting from the suspension of our vertical drilling operations and normal production declines. The Appalachia and Permian and other divisions also decreased as a result of normal production declines which were further impacted by the suspension of our drilling programs in both areas during 2009. As part of our 2009 divestiture program, we sold our Mid-Continent division during 2009.

31

To analyze our revenue and prices, using actual production, the following table presents our revenues, production and prices by major producing areas for the three months ended March 31, 2010 and 2009:

	Three months ended March 31,
	2010					2009					Quarter to quarter change
(dollars in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	18,753	$	93,995	$	5.01	22,616	$	104,097	$	4.60	(3,863	)	$	(10,102	)	$	0.41
Appalachia	3,341		19,354		5.79	5,125		30,030		5.86	(1,784	)		(10,676	)		(0.07	)
Permian and other	1,697		17,645		10.40	2,853		13,642		4.78	(1,156	)		4,003			5.62
Mid-Continent	—		—		—	5,752		24,439		4.25	(5,752	)		(24,439	)		(4.25	)
Total	23,791	$	130,994		5.51	36,346	$	172,208		4.74	(12,555	)	$	(41,214	)		0.77

For the three months ended March 31, 2010, total oil and natural gas revenues were $131.0 million, a 23.9% decrease from the three months ended March 31, 2009 total oil and natural gas revenues of $172.2 million. Although the declines in revenue are a result of divestitures and the BG Upstream Transaction, we actually realized overall increases in prices received. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $37.37 per Bbl for the three months ended March 31, 2009 to $75.24 per Bbl, or 101.3%, for the three months ended March 31, 2010. The average natural gas sales price, excluding the impact of derivative financial instruments, was $5.21 per Mcf, an increase of 13.3% for the three months ended March 31, 2010 compared with $4.60 per Mcf for the three months ended March 31, 2009.

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, 2010 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 $9.1 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 $0.6 million without considering the effects of derivative financial instruments.

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Oil and natural gas operating costs

Our oil and natural gas operating costs for the three months ended March 31, 2010 were $19.2 million and represent a decrease of $21.5 million, or 52.8%, from the same period in 2009. While the total dollar value decrease is due primarily to the 2009 divestitures and BG Upstream Transaction, management believes that analyses on a per Mcfe basis provide a more meaningful measure than the absolute dollar decrease since the divestitures and BG Upstream Transaction in 2009 were significant. The following tables summarize direct operating expenses and unit rates per Mcfe for the three months ended March 31, 2010 and 2009:

	Three months ended March 31,
	2010						2009						Quarter to quarter change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	10,529	$	1,390	$	11,919	$	19,919	$	2,125	$	22,044	$	(9,390	)	$	(735	)	$	(10,125	)
Appalachia		4,787		136		4,923		7,406		350		7,756		(2,619	)		(214	)		(2,833	)
Permian and other		2,134		217		2,351		3,342		328		3,670		(1,208	)		(111	)		(1,319	)
Mid-Continent		—		—		—		6,927		289		7,216		(6,927	)		(289	)		(7,216	)
Total	$	17,450	$	1,743	$	19,193	$	37,594	$	3,092	$	40,686	$	(20,144	)	$	(1,349	)	$	(21,493	)
	Three months ended March 31,
	2010						2009						Quarter to quarter change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.56	$	0.07	$	0.63	$	0.88	$	0.09	$	0.97	$	(0.32	)	$	(0.02	)	$	(0.34	)
Appalachia		1.43		0.04		1.47		1.44		0.07		1.51		(0.01	)		(0.03	)		0.04
Permian and other		1.26		0.13		1.39		1.17		0.11		1.28		0.09			0.02			0.11
Mid-Continent		—		—		—		1.20		0.05		1.25		(1.20	)		(0.05	)		(1.25	)
Operating costs per Mcfe		0.73		0.07		0.80		1.03		0.09		1.12		(0.30	)		(0.02	)		(0.32	)

On a per Mcfe basis, oil and natural gas operating expenses for the three months ended March 31, 2010 decreased $0.32 per Mcfe from the same period in 2009, with lease operating expenses representing $0.30 of the decrease and workovers and other representing $0.02 of the decrease. The total decrease in East Texas/North Louisiana is a result of increased production in our Haynesville shale, which has a low lease operating rate per Mcfe, and declines in our Vernon Field and Cotton Valley area, which historically have a higher lease operating rate per Mcfe. The decrease in Appalachia is a result of the fourth quarter 2009 divestitures of our Ohio and certain Northwestern Pennsylvania producing assets. These decreases were offset by increases in Permian and other resulting from lower production but without a corresponding decrease in non-variable costs, including labor costs.

Midstream operations

Until our adoption of the equity method of accounting in connection with the BG Midstream Transaction in August 2009, our midstream revenues were principally derived from three of our wholly-owned subsidiaries:

• TGG Pipeline, Ltd., which owns an intrastate pipeline in East Texas and a gathering system in North Louisiana;

• Talco Midstream Assets, Ltd., which owns gathering systems in East Texas and North Louisiana; and

• Vernon Gathering LLC, a gathering system located in Jackson Parish, Louisiana.

Revenues in our midstream segment were primarily derived from sales of natural gas purchased for resale and fees earned from gathering, transportation, treating and compression of natural gas. We do not own any natural gas processing facilities.

Pursuant to the BG Midstream Transaction, TGGT now holds our East Texas/North Louisiana midstream assets, exclusive of the Vernon Field midstream assets. TGGT is accounted for using the equity method of accounting. The net operations of Vernon Gathering are now reflected in “Gathering and transportation” on our Condensed Consolidated Statements of Operations.

Gathering and transportation

We report gathering and transportation costs in accordance with Accounting Standards Codification 605.45, or ASC 605.45. 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

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which are reported under two separate bases. Gathering and transportation expenses totaled $11.1 million for the three months ended March 31, 2010, compared to $3.9 million for the three months ended March 31, 2009. The overall increase in gathering and transportation expenses is a result of new firm transportation agreements in the Haynesville area, which commenced in February 2010, along with the fees being charged by TGGT.

In connection with our change from reporting our midstream operations as a separate business segment, we began reporting the net results of operations from our Vernon Gathering system as a component of gathering and transportation expenses in the third quarter of 2009.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended March 31, 2010 decreased by $4.6 million, or 36.7%, over the same period in 2009. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 6.0% of gross oil and natural gas sales for the three months ended March 31, 2010, compared with 7.2% during the same period in the prior year. In addition to the impact from the 2009 divestitures and BG Upstream Transaction, the decrease 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. Therefore, the resulting dollar value of production is not sensitive to changes in prices for natural gas. The rate in Louisiana, whether stated on a per Mcfe basis or as a percentage of revenues, is also impacted by certain severance tax holidays on deep wells. Approval of these holidays is on a well by well basis, and credits are not recognized until approvals are received. Accordingly, a 50% decline in the average sales price per Mcf in Louisiana would double the effective production tax rate as a percentage of revenue. In our other operating areas, production taxes are predominantly price dependent. 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 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 $0.33 per Mcfe for the three months ended March 31, 2010 compared with $0.34 per Mcfe for the three months ended March 31, 2009. 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, 2010							Three months ended March 31, 2009
(dollars in thousands)	Revenue		Severance and ad valorem taxes		% of revenue			Revenue		Severance and ad valorem taxes		% of revenue
Producing region:
East Texas/North Louisiana	$	93,995	$	5,498		5.8	%	$	104,097	$	8,330		8.0	%
Appalachia		19,354		766		4.0	%		30,030		780		2.6	%
Permian and other		17,645		1,601		9.1	%		13,642		1,437		10.5	%
Mid-Continent		—		—		0.0	%		24,439		1,885		7.7	%
Total	$	130,994	$	7,865		6.0	%	$	172,208	$	12,432		7.2	%
	Per Mcfe basis
	Three months ended March 31, 2010							Three months ended March 31, 2009
(dollars 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		18,753	$	5,498	$	0.29			22,616	$	8,330	$	0.37
Appalachia		3,341		766		0.23			5,125		780		0.15
Permian and other		1,697		1,601		0.94			2,853		1,437		0.50
Mid-Continent		—		—		—			5,752		1,885		0.33
Total		23,791	$	7,865		0.33			36,346	$	12,432		0.34

Depletion

Our depletion expense for the three months ended March 31, 2010 decreased by $41.0 million, or 54.6%, from the same period in 2009. The primary reason for the decrease was the lower full cost pool amortization base resulting from $1.3 billion of ceiling test write-downs during the first quarter of 2009 and the divestitures and joint venture transactions during the third and fourth quarters of 2009. These factors decreased our per unit depletion rate from $2.06 per Mcfe for the three months ended March 31, 2009 to $1.43 per Mcfe for the three months ended March 31, 2010.

Depreciation and amortization

Our depreciation and amortization costs for the three months ended March 31, 2010 decreased by $2.0 million, or 29.5%, from the same period in 2009. The primary reason for the decrease was the sale of our gas gathering asset to form our equity investment in TGGT during the third quarter of 2009.

Accretion of discount on asset retirement obligations decreased to $1.1 million for the three months ended March 31, 2010 from $2.1 million for the three months ended March 31, 2009. The decrease is due to the divestitures we completed in 2009, including the sale of our Mid-Continent division and the BG Upstream Transaction, offset by significant well additions and related plugging liabilities in connection with our 2009 Haynesville activity.

Write-down of oil and natural gas properties

There was no ceiling test write-down for the first quarter of 2010. As required under the SEC’s Release No. 33-8995 Modernization of Oil and Gas Reporting, or Release No. 33-8995, at the end of each quarterly period the full cost ceiling is to be computed as the sum of the estimated future net revenues from Proved Reserves using the simple average spot price for the trailing twelve month period using the first day of each month. We computed the after-tax present value of our proved oil and natural gas properties using the $3.99 per Mmbtu average price for Henry Hub and the $69.64 per Bbl average price for Cushing, Oklahoma.

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 full cost accounting rules in place before Release No. 33-8995, we were 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. 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.

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General and administrative

The following table presents our general and administrative expenses for the three months ended March 31, 2010 and 2009, and changes for the quarters then ended.

	Three months ended March 31,						Quarter to quarter change 2010-2009
(in thousands, except per unit rate)	2010			2009
General and administrative costs:
Gross general and administrative expense	$	33,153		$	30,523		$	2,630
Operator overhead reimbursements		(3,770	)		(6,488	)		2,718
Capitalized acquisition and development charges		(2,964	)		(3,488	)		524
Net general and administrative expense	$	26,419		$	20,547		$	5,872
General and administrative expense per Mcfe	$	1.11		$	0.57		$	0.54

Our general and administrative costs for the three months ended March 31, 2010 were $26.4 million, or $1.11 per Mcfe, compared to $20.5 million, or $0.57 per Mcfe, for the same period in 2009, an increase of $5.9 million, or 28.6%. Significant components of the overall increases for the three months ended March 31, 2010 include the following items:

• increased salaries and benefit costs of $2.6 million due primarily to technical employees hired to exploit our shale resource asset base;

• increased costs of $2.3 million due to various claims and settlements;

• increased share-based compensation costs of $1.7 million due primarily to the annual stock option grant in 2009 and the acceleration of option vesting of certain employees impacted by the 2009 divestitures;

• increased building rent of $0.9 million due to expansion of our Dallas office; and

• decreases in operator overhead recoveries of $2.7 million and capitalized charges of $0.5 million, both due to the 2009 divestitures.

These increases were partially offset by decreased technology costs of $0.7 million due to timing of maintenance and licensing agreements, along with a $4.7 million recovery of technical service costs from our service agreement with BG Group.

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Interest expense

Our interest expense decreased approximately $25.5 million for the three months ended March 31, 2010 from the same period in 2009. The decrease is primarily due to the interest and deferred financing costs related to the $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, that EXCO Operating paid off on August 14, 2009, along with lower average balances on our credit agreements and lower capitalized interest. These decreases were partially offset by losses on our interest rate swaps. The following table presents the components of our interest expense:

	Three months ended March 31,						Quarter to quarter change
(in thousands)	2010			2009
Interest expense:
7 1/4% senior notes due 2011	$	7,127		$	7,184		$	(57	)
EXCO Resources Credit Agreement		864			6,424			(5,560	)
EXCO Operating Credit Agreement		4,567			7,854			(3,287	)
Term Credit Agreement		—			7,500			(7,500	)
Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement		351			777			(426	)
Amortization of deferred financing costs on EXCO Operating Credit Agreement		493			754			(261	)
Amortization of deferred financing costs on Term Credit Agreement		—			11,103			(11,103	)
Interest rate swaps settlements		2,063			1,670			393
Fair market value adjustment on interest rate swaps		(2,018	)		(5,786	)		3,768
Capitalized interest		(2,915	)		(1,361	)		(1,554	)
Other interest expense		102			13			89
Total interest expense	$	10,634		$	36,132		$	(25,498	)

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. 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.

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The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments including the early termination settlements required by the October 2009 amendment to the EXCO Operating Credit Agreement. Our derivative activity is reported as a component of other income or expenses in our consolidated statements of operations.

	Three months ended March 31,				Quarter to quarter change
(in thousands)	2010		2009
Derivative financial instrument activities:
Cash settlements on derivative financial instruments, excluding early terminations	$	39,111	$	98,429	$	(59,318	)
Cash settlements on early terminations of derivative financial instruments		37,936		—		37,936
Non-cash change in fair value of derivative financial instruments		22,102		122,955		(100,853	)
Total derivative financial instrument activities	$	99,149	$	221,384	$	(122,235	)

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 increased from $4.74 during the three months ended March 31, 2009 to $5.51 during the three months ended March 31, 2010. Excluding the impact of the cash settlement on early terminations of derivatives, this volatility was offset by realized settlements of our derivatives, where average realized prices per Mcfe after the impact of our derivative financial instruments increased our price from $5.51 to $7.15 per Mcfe during the three months ended March 31, 2010 and increased our price from $4.74 to $7.45 per Mcfe for the three months ended March 31, 2009. This decreased our quarter to quarter change from an increase of $0.77 per Mcfe before cash settlements on derivatives to a decrease of $0.30 per Mcfe after cash settlements on derivatives. Due to the first quarter 2010 early termination settlements, our realized price for the three months ended March 31, 2010 was further increased by $1.60 Mcfe to $8.75.

	Three months  ended March 31,				Quarter to quarter  change
Realized pricing:	2010		2009
Oil per Bbl	$	75.24	$	37.37	$	37.87
Natural gas per Mcf		5.21		4.60		0.61
Natural gas equivalent per Mcfe	$	5.51	$	4.74	$	0.77
Cash settlements on derivatives, excluding early terminations		1.64		2.71		(1.07	)
Net price per Mcfe, including derivative financial instruments before early terminations	$	7.15	$	7.45	$	(0.30	)
Cash settlements on derivatives terminated early		1.60		—		1.60
Net price per Mcfe, including all derivative financial instruments	$	8.75	$	7.45	$	1.30

Our total cash settlements for the three months ended March 31, 2010, including the derivatives settled early, increased revenue by $77.1 million, or $3.24 per Mcfe, compared to cash settlements increasing revenues by $98.4 million, or $2.71 per Mcfe, for the same period in 2009. 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, 2010 resulted in gains of $22.1 million compared to gains of $123.0 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 LIBOR ranging from 2.45% to 2.8%. For the three months ended March 31, 2010, we had realized losses from payments of $2.1 million and $2.0 million of non-cash unrealized gains attributable to our interest rate swaps, compared to realized losses from payments of $1.7 million and $5.8 million of non-cash unrealized gains for the same period in 2009. These swaps expired on February 14, 2010. As of March 31, 2010 we have not entered into any new interest rate swaps.

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Income taxes

Our effective income tax rate for the three months ended March 31, 2010 and 2009 was zero and an expense of 0.1%, respectively. For the three months ended March 31, 2010, we utilized a portion of our accumulated valuation allowance of $46.0 million and have accumulated $631.7 million of valuation allowance which can be used against future deferred tax benefits. 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 is primarily attributable to the ceiling test write-downs, which occurred in the first quarter of 2009 and 2008, that have resulted in recognition of operating losses that caused the book basis of our proved oil and natural gas properties to be less than the tax basis of those properties. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits become more likely than not. The effective income tax rates excluding the impact of the valuation allowance for the three months ended March 31, 2010 and 2009 would have been 39.8% and 39.0%, respectively. A substantial portion of our stock-based compensation included in our results of operations for the three months ended March 31, 2010 and 2009 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 joint ventures, proceeds from sales 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. Prior to 2009, we used acquisitions of producing properties and vertical drilling of development wells in established basins as our primary vehicle for growth. These acquisitions provided us with substantial acreage with deep rights in shale resource plays, and our recent success using horizontal drilling in the Haynesville shale in East Texas/North Louisiana has created significant growth opportunities in the area, as well as in the Bossier shale play in East Texas/North Louisiana and the Marcellus shale play in Appalachia. These additional opportunities have resulted in a shift in our focus from an acquisition-oriented strategy to horizontal drilling, development and exploitation activities.

Presently, we have budgeted approximately $363.6 million for capital expenditures for the remainder of 2010 , of which we are contractually obligated to spend $201.1 million, which includes significant acreage commitments in the Marcellus shale area, as of March 31, 2010. We expect to utilize our current cash balances, including funds which we have already placed in our restricted accounts to fund Haynesville development, cash flow generated from operations and available funds under our credit agreement to fund capital expenditures and acquisitions. The capital budget, as amended, for 2010 reflects a 5.3% increase from 2009 actual capital expenditures, excluding acquisitions. The remaining 2010 capital budget of $363.6 million is net of approximately $151.2 million of BG Carry covering our interests in certain drilling and completion costs in East Texas/North Louisiana.

Below is our 2010 budget, which reflects the BG Carry and excludes acquisitions.

(in thousands)	Q1 2010 actuals		April - December 2010 capital budget		Total 2010 capital budget
East Texas/North Louisiana	$	68,608	$	186,525	$	255,133
Appalachia		41,987		112,259		154,246
Permian and other		7,859		21,304		29,163
TGGT		44,500		30,500		75,000
Corporate		12,037		13,007		25,044
Total	$	174,991	$	363,595	$	538,586

On April 21, 2010, we announced a joint acquisition of Common Resources, L.L.C., with an affiliate of BG Group. The acquisition includes seven producing horizontal wells, gathering lines and approximately 29,200 net undeveloped acres in the Haynesville and Bossier shales. Our 50% share of the $446.0 million acquisition price, subject to customary closing adjustments will be approximately $223.0 million and will be funded with borrowings under the EXCO Resources Credit Agreement. We expect this acquisition to close in May 2010.

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As a result of the 2009 joint venture with BG Group in our East Texas/North Louisiana areas of operation, we have increased our drilling and leasing activities in this area. Pursuant to the Joint Development Agreement, or JDA, with BG Group, BG Group agreed to fund 75% of our 50% interest in deep drilling projects up to a total of $400.0 million. As a result of this carried amount, our required capital expenditures will be substantially reduced during the carried period, which we project will extend through 2011. As of March 31, 2010, approximately $313.8 million remains unfunded by BG Group under the carry provisions of the JDA.

Cash flows from operations and unused borrowing capacity under our revolving credit agreements 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 (i) levels of production from our oil and natural gas properties, (ii) prices we receive for sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs for our general and administrative activities and (v) interest expense and other financing related costs. The following table presents our liquidity and financial position as of March 31, 2010 and April 30, 2010.

(in thousands)	March 31, 2010		April 30, 2010
Cash (1)	$	117,792	$	142,179
Drawings under credit agreement(s)		762,543		817,500
Senior Notes (2)		444,720		444,720
Total debt		1,207,263		1,262,220
Net debt	$	1,089,471	$	1,120,041
Consolidated borrowing base	$	1,300,000	$	1,300,000
Total of unused borrowing base (1) (3)	$	522,254	$	467,298
Unused borrowing base plus cash (1) (3)	$	640,046	$	609,477

(1) Includes restricted cash of $70.0 million at March 31, 2010 and $117.0 million at April 30, 2010.

(2) Excludes unamortized bond premium of $3.1 million at March 31, 2010 and $2.7 million at April 30, 2010.

(3) Net of $15.2 million in letters of credit at March 31, 2010 and $15.2 million at April 30, 2010.

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 7 ¹/4% Senior Notes due January 15, 2011, or Senior Notes. These agreements contain 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. Any future 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.

Recent events affecting liquidity

Our joint acquisition of Common Resources, L.L.C., which is expected to close in May 2010, will be funded with available borrowings under our credit agreement. In addition to the borrowings required to fund our share of the acquisition of approximately $223.0 million, subject to customary closing adjustments, we expect to increase our number of drilling rigs to accelerate development in the area, which will require additional capital expenditures. Drilling costs within the Common Resources, L.L.C. area are subject to the BG Carry, which will also accelerate the utilization of the unused portion of the carry.

The capital and credit markets remained constrained and unpredictable throughout 2009 and through the first quarter of 2010. Actions taken by the United States government and Federal Reserve in 2008 and 2009 through enacted legislation and implementation of various programs have had only a limited impact in stabilizing the credit markets and promoting liquidity in financial institutions. The effects of these actions, some of which have not yet been fully implemented, on our industry and on us are not determinable 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.

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In addition to the turmoil in the credit markets and related uncertainties, prices for natural gas suffered a precipitous decline beginning in the third quarter of 2008 and has continued throughout the first quarter of 2010. As of April 30, 2010, the spot prices for oil and natural gas were $86.15 per Bbl and $4.24 per Mmbtu compared with $79.36 per Bbl and $5.79 per Mmbtu as of December 31, 2009. The 2010 average NYMEX future prices as of April 30, 2010 for natural gas have also declined from the 2010 average NYMEX future prices as of December 31, 2009 by $1.42 per Mmbtu, reflecting anticipated decreased 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.

Our proposed capital budget for 2010 reflects targeted capital expenditures. As in 2009, our 2010 capital program will focus on Haynesville/Bossier shale plays in East Texas/North Louisiana and we will expand our activities in the Marcellus shale play in Appalachia. Our 2009 asset sales and reduced ownership interest in East Texas/North Louisiana properties arising from the BG Upstream Transaction, will impact our production volumes in future periods. However, the provision in the JDA for the BG Group to fund 75% of our share of drilling and development costs on new Haynesville and other deep wells spud after closing, of which $313.8 million remains unfunded, provides us with substantial economic benefit toward development of the Haynesville shale play. While the value derived from the BG Carry reduces our capital expenditures in East Texas/North Louisiana, the credit markets and natural gas prices remain a concern.

Our Senior Notes with a principal balance of $444.7 million mature on January 15, 2011. We believe that our cash flows from operations, amounts available to us under our credit facility and additional asset sales or joint venture transactions will provide us with sufficient liquidity to pay-off the Senior Notes at maturity. Alternatively, we believe current market conditions may provide an opportunity to refinance the Senior Notes.

Despite the ongoing uncertainties existing in the capital and credit markets and commodity prices, we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities, reduced capital expenditures and remaining borrowing capacity under our credit agreement will be adequate to meet the cash requirements to fund our operations, debt service obligations and our 2010 capital expenditure programs. Our future cash flows are subject to a number of variables including production volumes, oil and natural gas prices and drilling and service costs.

Significant acreage acquisitions also have an impact on our near term liquidity as these types of acquisitions may cause an increase in our outstanding debt without any immediate cash flows or increases under the borrowing base within our credit agreement. On April 21, 2010, we entered into an agreement with BG Group to jointly acquire Common Resources, L.L.C., which holds undeveloped acreage in the Haynesville shale for $446.0 million, subject to preliminary and final closing adjustments. Our share of this acquisition ($223.0 million) will increase outstanding indebtedness under our credit agreement.

Under our JDA with BG Group in East Texas/North Louisiana, we acquired undeveloped acreage and offered 50% of that acreage to BG Group pursuant to the BG AMI. During the first quarter of 2010, we received $65.5 million of such reimbursements from BG Group. As of March 31, 2010, we have a receivable of $38.7 million for reimbursements of acquired acreage which we expect to collect in the second quarter of 2010.

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 proceeds from the sale of 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 was $91.3 million for the three months ended March 31, 2010 compared with $105.3 million for the three months ended March 31, 2009. The 13.3% decrease is attributable primarily to lower cash settlements of our oil and natural gas derivatives offset by higher average oil and natural gas prices in the first quarter of 2010 compared with average prices during the same period in 2009. At April 30, 2010, our cash and cash equivalents balance was $25.2 million and our restricted cash account, which is principally used for Haynesville development operations, was $117.0 million.

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We made cash dividend payments to our common shareholders of $6.4 million on March 19, 2010.

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, 2010 and 2009:

	Three months ended March 31,
(in thousands)	2010		2009
Capital expenditures:
Development capital expenditures	$	64,993	$	113,026
Property acquisitions		8,698		7
Lease purchases		49,263		10,990
Midstream capital additions		—		13,444
Corporate, gathering systems and other		16,235		14,433
Total capital expenditures	$	139,189	$	151,900

Our development capital expenditures emphasize horizontal shale drilling and completion.

We have presently budgeted approximately $538.6 million for capital expenditures in 2010, of which we are contractually obligated to spend $201.1 million, which includes significant acreage commitments in the Marcellus shale area, as of March 31, 2010. We expect to utilize our current cash balances, cash flow generated from operations and available funds under our credit agreements in 2010 to fund capital expenditures and acquisitions, if any. The capital budget for 2010 reflects a 5.3% increase from 2009 actual capital expenditures, excluding acquisitions. The 2010 capital budget of $538.6 million is net of approximately $205.1 million of BG Carry attributable to development of our Haynesville/Bossier shale assets. 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. Our April 21, 2010 acquisition of Common Resources, L.L.C. will require additional capital expenditures and we expect that additional capital contributions to TGGT will also be required to expand gathering capacity and treating facilities.

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, 2010, we have total debt outstanding aggregating $1,262.2 million consisting of borrowings under our EXCO Resources Credit Agreement of $817.5 million and $444.7 million of Senior Notes due in January 2011. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

On April 30, 2010, we amended and restated the EXCO Resources Credit Agreement which consolidated the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement into one credit agreement with a borrowing base of $1.3 billion. Terms of the consolidated agreement include, among other things, EXCO Operating and certain of its subsidiaries becoming guarantor subsidiaries under the EXCO Resources Credit Agreement and our Senior Notes. The amended EXCO Resources Credit Agreement matures on April 30, 2014 and permits certain investments, loans and advances to unrestricted subsidiaries which are jointly held with BG Group, including TGGT and upon closing, Common Resources, L.L.C.

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Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the Engineered Value, as defined in the credit agreement, in our oil and natural gas properties covered by the borrowing base. EXCO is permitted to have derivative financial instruments covering no more than 100% of forecasted production from all Proved Reserves (as defined in the agreement) during the first two years of the forthcoming five year period, 90% of the forecasted production for any month during the third year of the forthcoming five year period and 85% of the forecasted production during the fourth and fifth year of the forthcoming five year period.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the amendment, EXCO may declare and pay cash dividends on its common stock in an amount not to exceed $50.0 million in any four consecutive fiscal quarters, provided that as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) EXCO has at least 10% of its borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under EXCO’s 7 ¹/4% Senior Notes Indenture.

The interest rate ranges from LIBOR plus 200 basis points, or bps, to LIBOR plus 300 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 100 bps to ABR plus 200 bps depending upon borrowing base usage.

Financial covenants require that we:

• maintain a consolidated current ratio (as defined in the agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

• not permit our ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 3.50 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2010;

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

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

As of March 31, 2010, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at March 31, 2010 was $3.1 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.9 million on March 31, 2010.

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, 2010, 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.

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Effective April 30, 2010, in connection with the amended EXCO Resources Credit Agreement, EXCO Operating Company and certain subsidiaries became guarantor subsidiaries of the Senior Notes. However, certain other subsidiaries, including TGGT and pending the acquisition of Common Resources, L.L.C., are or will become non-guarantor 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, 2010, we had derivative financial instrument contracts in place for the volumes and prices shown below:

(in thousands, except prices)	NYMEX gas volume - Mmbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Bbls	Weighted average contract price per Bbl
Swaps:
Q2 2010	13,803	$	7.16	111	$	114.96
Q3 2010	13,940		7.16	113		114.96
Q4 2010	13,940		7.21	113		114.96
2011	20,075		7.04	456		116.00
2012	9,150		6.11	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 LIBOR ranging from 2.45% to 2.8%. For the three months ended March 31, 2010, we had realized losses from settlements of $2.1 million and $2.0 million of non-cash unrealized gains attributable to our interest rate swaps. As of March 31, 2010 we no longer have any interest rate swaps.

Off-balance sheet arrangements

None.

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Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at March 31, 2010:

	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)		—		96,465		—		—		96,465
Long-term debt - EXCO Operating Credit Agreement (3)		—		666,078		—		—		666,078
Firm transportation services and other fixed commitments (4)		42,134		69,757		71,541		190,622		374,054
Operating leases		6,917		11,145		9,625		3,528		31,215
Drilling contracts		56,564		50,888		4,849		—		112,301
Total contractual cash obligations	$	550,335	$	894,333	$	86,015	$	194,150	$	1,724,833

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

(2) The EXCO Resources Credit Agreement, as amended, matures on April 30, 2014.

(3) The EXCO Operating Credit Agreement was consolidated with the EXCO Resources Credit Agreement on April 30, 2010.

(4) Firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a shippers’ pipeline. Other fixed commitments include salt water disposal arrangements. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were delivered.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity price risk

Our 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, gains or losses on derivative financial instruments and with respect to interest rate swaps, as interest expense on financial risk management instruments.

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.

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The following table sets forth our oil and natural gas derivative financial instruments measured at fair value as of March 31, 2010.

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2010
Natural gas:
Swaps:
Remainder of 2010	41,683	$	7.18	$	120,466
2011	20,075		7.04		33,602
2012	9,150		6.11		2,887
2013	5,475		5.99		(365	)
Total natural gas	76,383				156,590
Oil:
Swaps:
Remainder of 2010	337		114.96		10,025
2011	456		116.00		13,375
2012	92		109.30		1,975
Total oil	885				25,375
Total oil and natural gas derivatives				$	181,965

At March 31, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $84.96 and $86.13, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2010 and for 2011 were $4.27 and $5.34, 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.

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, 2010, for the remainder of 2010, if the settlement price exceeds the actual weighted average strike price of $114.96 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $114.96 per Bbl, multiplied by the hedged volume of 337 Mbbls. Conversely, if the settlement price is less than $114.96 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $114.96 per Bbl, multiplied by the hedged volume of 337 Mbbls. For example, for a hedged volume of 337 Mbbls, if the settlement price is $115.96 per Bbl then other income would decrease by $0.3 million. Conversely, if the settlement price is $113.96 per Bbl, other income would increase by $0.3 million.

Interest rate risk

At March 31, 2010, our exposure to interest rate changes related primarily to borrowings under our credit agreements and interest earned on our short-term investments. The interest rate is fixed at 7 ¹/4% on the $444.7 million outstanding on our Senior Notes. Interest is payable on borrowings under our credit agreements based on a floating rate as more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity, capital resources and capital commitments.” At March 31, 2010, we had approximately $762.5 million in outstanding borrowings under our credit agreements. A 1% change in interest rates based on the variable borrowings as of March 31, 2010 would result in an increase or decrease in our interest costs of $7.6 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%. Our interest rate swaps expired in February 2010 and we have not entered into any new agreements.

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

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effective as of March 31, 2010 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, 2010 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 6. Exhibits

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

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SIGNATURES

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

EXCO RESOURCES, INC.

(Registrant)

Date: May 5, 2010	By:	/s/ DOUGLAS H. MILLER
		Douglas H. Miller
		Chairman and Chief Executive Officer
	By:	/s/ STEPHEN F. SMITH
		Stephen F. Smith
		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	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.2	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.3	Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.4	Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
2.5	First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.6	Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
2.7	Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO—North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
2.8	Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 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.

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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.
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 as an Exhibit to EXCO’s Quarterly Report on From 10-Q, filed on May 6, 2009 and incorporated by reference herein.
4.6	Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.
4.7	Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s 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.

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4.11	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.
4.12	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.
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 as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed May 6, 2009 and incorporated by reference herein.
10.7	Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.8	Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.9	Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive 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.

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10.13	Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated herein by reference.
10.14	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.*
10.15	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.
10.16	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 Book runner 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.
10.17	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 Book runner and Lead Arranger, filed as an Exhibit to EXCO’s Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.
10.18	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.
10.19	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.
10.20	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.
10.21	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.
10.22	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.
10.23	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.
10.24	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.

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10.25	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.
10.26	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.
10.27	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.
10.28	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 book runner 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.
10.29	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 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 February 4, 2009 and filed on February 5, 2009 and incorporated by reference herein.
10.30	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.
10.31	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.
10.32	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.
10.33	Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 1, 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 September 29, 2009 and filed on October 5, 2009 and incorporated by reference herein.
10.34	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.35	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.36	Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.

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10.37	Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.
10.38	Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.
10.39	Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
10.40	Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated August 14, 2009, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.
10.41	First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.42	Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
10.43	Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO – North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
10.44	Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 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.

* These exhibits are management contracts.

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