Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q 1 d10q.htm FORM 10-Q Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

¨	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 001-32743

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 x 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):

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 July 29, 2010 was 212,654,604

EXCO RESOURCES, INC.

INDEX


PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009	3
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	5
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Six Months Ended June 30, 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	33
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 4.	Controls and Procedures	54

PART II.	OTHER INFORMATION	54

Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Securities and Use of Proceeds	57
Item 6.	Exhibits	57
	Signatures	58
	Index to Exhibits	59

PART I—FINANCIAL INFORMATION

Item 1.

Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	June 30, 2010			December 31, 2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	98,027		$	68,407
Restricted cash		75,246			58,909
Accounts receivable, net:
Oil and natural gas		63,362			56,485
Joint interest		88,944			47,104
Interest and other		17,651			10,832
Inventory		12,600			15,830
Derivative financial instruments		102,507			138,120
Other		40,471			6,401

Total current assets		498,808			402,088

Equity investments		288,143			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		622,294			492,882
Proved developed and undeveloped oil and natural gas properties		2,114,990			1,875,749
Accumulated depletion		(1,207,745	)		(1,132,604	)

Oil and natural gas properties, net		1,529,539			1,236,027

Gas gathering assets		145,954			180,506
Accumulated depreciation and amortization		(20,939	)		(22,841	)

Gas gathering assets, net		125,015			157,665

Office and field equipment, net		24,238			31,771
Deferred financing costs, net		18,756			7,602
Derivative financial instruments		39,912			34,677
Goodwill		218,256			269,656
Other assets		11,234			2,421

Total assets	$	2,753,901		$	2,358,894

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
(in thousands, except per share and share data)	2010			2009
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	87,368		$	112,991
Revenues and royalties payable		106,693			79,356
Accrued interest payable		16,302			16,193
Current portion of asset retirement obligations		900			900
Income taxes payable		5,210			210
Derivative financial instruments		639			3,264
Current maturities of long-term debt		446,831			—

Total current liabilities		663,943			212,914

Long-term debt, net of current maturities		477,500			1,196,277
Deferred income taxes		—			—
Derivative financial instruments		5,648			11,688
Asset retirement obligations and other long-term liabilities		60,327			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 - 212,648,328 at June 30, 2010 and 211,905,509 at December 31, 2009		213			212
Additional paid-in capital		3,124,991			3,105,238
Accumulated deficit		(1,578,721	)		(2,245,862	)

Total shareholders’ equity		1,546,483			859,588

Total liabilities and shareholders’ equity	$	2,753,901		$	2,358,894

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share data)	2010			2009			2010			2009
Revenues:
Oil and natural gas	$	118,344		$	146,252		$	249,338		$	318,460
Midstream		—			12,942			—			29,955

Total revenues		118,344			159,194			249,338			348,415

Costs and expenses:
Oil and natural gas production		31,024			48,394			58,082			101,512
Midstream operating		—			11,719			—			30,169
Gathering and transportation		12,873			4,055			23,986			7,952
Depreciation, depletion and amortization		45,339			55,180			84,157			136,974
Write-down of oil and natural gas properties		—			—			—			1,293,579
Accretion of discount on asset retirement obligations		1,001			2,018			2,090			4,089
General and administrative		25,866			22,488			52,285			43,035
Gain on divestures and other operating items		(574,946	)		8,382			(575,353	)		7,977

Total costs and expenses		(458,843	)		152,236			(354,753	)		1,625,287

Operating income (loss)		577,187			6,958			604,091			(1,276,872	)
Other income (expense):
Interest expense		(14,476	)		(46,891	)		(25,110	)		(83,023	)
Gain (loss) on derivative financial instruments		707			(31,017	)		99,856			190,367
Other income		57			13			117			35
Equity method income		5,290			—			5,379			—

Total other income (expense)		(8,422	)		(77,895	)		80,242			107,379

Income (loss) before income taxes		568,765			(70,937	)		684,333			(1,169,493	)
Income tax expense		4,452			1,055			4,452			2,110

Net income (loss)	$	564,313		$	(71,992	)	$	679,881		$	(1,171,603	)

Earnings (loss) per common share:
Basic
Net income (loss)	$	2.66		$	(0.34	)	$	3.20		$	(5.55	)

Weighted average common shares outstanding		212,497			211,089			212,293			211,042

Diluted
Net income (loss)	$	2.62		$	(0.34	)	$	3.15		$	(5.55	)

Weighted average common and common equivalent shares outstanding		215,498			211,089			215,520			211,042

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six months ended June 30,
(in thousands)	2010			2009
Operating Activities:
Net income (loss)	$	679,881		$	(1,171,603	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		84,157			136,974
Stock option compensation expense		8,463			6,480
Accretion of discount on asset retirement obligations		2,090			4,089
Write-down of oil and natural gas properties		—			1,293,579
Gain on divestitures		(574,878	)
Income from equity investments		(5,379	)		—
Non-cash change in fair value of derivatives		21,711			46,196
Cash settlements of assumed derivatives		907			(90,294	)
Deferred income taxes		—			2,110
Amortization of deferred financing costs and premium on 7¹/4% senior notes due 2011		3,847			23,767
Effect of changes in:
Accounts receivable		(65,218	)		27,300
Other current assets		(4,081	)		(3,497	)
Accounts payable and other current liabilities		30,353			(48,168	)

Net cash provided by operating activities		181,853			226,933

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(263,361	)		(267,405	)
Property acquisitions		(438,382	)		(62,963	)
Restricted cash		(16,337	)		(37,500	)
Deposit on pending divestitures		—			57,688
Investment in equity investments		(68,500	)		—
Proceeds from disposition of property and equipment		956,296			55,783
Advances to Appalachia JV		(30,448	)		—

Net cash provided by (used in) investing activities		139,268			(254,397	)

Financing Activities:
Borrowings under credit agreements		1,352,399			52,949
Repayments under credit agreements		(1,622,463	)		(22,740	)
Proceeds from issuance of common stock		9,091			1,648
Payment of common stock dividends		(12,740	)		—
Settlements of derivative financial instruments with a financing element		(907	)		90,294
Deferred financing costs and other		(16,881	)		(20,468	)

Net cash provided by (used in) financing activities		(291,501	)		101,683

Net increase in cash		29,620			74,219
Cash at beginning of period		68,407			57,139

Cash at end of period	$	98,027		$	131,358


Supplemental Cash Flow Information:
Cash interest payments	$	25,520		$	72,718

Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	2,175		$	1,180

Capitalized interest	$	6,114		$	2,797

Issuance of common stock for director services	$	25		$	35

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


				Additional		Retained			Total
	Common Stock			paid-in		earnings			shareholders’
(in thousands)	Shares	Amount		capital		(deficit)			equity
Balance at December 31, 2008	210,969	$	211	$	3,070,766	$	(1,738,476	)	$	1,332,501
Issuance of common stock	207		—		1,683		—			1,683
Share-based compensation					7,660		—			7,660
Net loss					—		(1,171,603	)		(1,171,603	)

Balance at June 30, 2009	211,176	$	211	$	3,080,109	$	(2,910,079	)	$	170,241


Balance at December 31, 2009	211,905	$	212	$	3,105,238	$	(2,245,862	)	$	859,588
Issuance of common stock	743		1		9,115		—			9,116
Share-based compensation					10,638		—			10,638
Common stock dividends					—		(12,740	)		(12,740	)
Net income					—		679,881			679,881

Balance at June 30, 2010	212,648	$	213	$	3,124,991	$	(1,578,721	)	$	1,546,483

See accompanying notes.

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 key North American oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia.

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 pursuing opportunistic acquisitions. 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 June 30, 2010 and December 31, 2009, the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009, the Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the six months ended June 30, 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 June 30, 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.

In August 2009, we discontinued reporting our midstream operations as a separate business segment in connection with 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.

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 the current year presentation.

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

2.	Significant recent activities

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 Company, LP, or EXCO Operating and certain of its subsidiaries becoming guarantor subsidiaries under the EXCO Resources Credit Agreement and our 7 ¹/4% senior notes due January 15, 2011, or the Senior Notes. The amended EXCO Resources Credit Agreement matures on April 30, 2014.

On June 1, 2010, we closed a transaction which resulted in the sale of a 50% undivided interest in substantially all of our Appalachian oil and natural gas proved and unproved properties and related assets to BG Group for cash consideration of approximately $835.2 million, subject to customary final closing adjustments, or the Appalachia JV. In addition to the cash consideration received at closing, BG Group agreed to fund 75% of our working interest share for each deep rights well (primarily the Marcellus shale play) up to a total of $150.0 million. In conjunction with the Appalachia JV, we entered into a Joint Development Agreement, or JDA, with BG Group. The effective date of the transaction was January 1, 2010.

In conjunction with the Appalachia JV, EXCO and BG Group each own a 50% interest in an operating company, EXCO Resources (PA), LLC, or OPCO, which operates the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. On June 1, 2010, we made a $33.0 million advance to OPCO to provide working capital for our share of properties. This advance was recorded as a prepaid asset and included in “Other” current assets on our Condensed Consolidated Balance Sheet and will be offset by any payments made by OPCO for our interest in the operated properties. We will continue to fund OPCO with advances based on the activity of our properties.

In addition, certain midstream assets owned by us were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which both EXCO and BG Group will pursue the construction and expansion of gathering systems, pipeline systems and treating facilities for anticipated future production from the Marcellus shale. We use the equity method to account for the Appalachia Midstream, LLC.

The Appalachia JV caused a significant alteration to our full cost pool and a gain, net of a reduction in goodwill, of $575.0 million was recognized during the second quarter of 2010.

On June 30, 2010, EXCO and BG Group jointly closed the purchase of properties in Shelby, San Augustine and Nacogdoches Counties, Texas in the Haynesville and Bossier shales from Southwestern Energy Company, or the Southwestern Transaction. The total purchase price paid at the closing was $355.8 million ($177.9 million net to EXCO), subject to customary post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under our credit agreement. The development of these assets is governed by the East Texas/North Louisiana JV. The majority of the assets acquired in the Southwestern Transaction represent incremental working interests in properties that EXCO and BG Group acquired in the Common Transaction.

3.	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 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

4.	Significant accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2009.

5.	Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2010:


(in thousands)
Asset retirement obligation at January 1, 2010	$	65,115
Activity during the six months ended June 30, 2010:
Liabilities incurred during the period		431
Liabilities settled during the period		(433	)
Reduction to retirement obligations due to divestitures		(19,251	)
Accretion of discount		2,090

Asset retirement obligations at June 30, 2010		47,952
Less current portion		(900	)

Long-term portion	$	47,052

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

6.	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 $622.3 million and $492.9 million as of June 30, 2010 and December 31, 2009, respectively, are not subject to depletion. The $129.4 million increase in our unproved properties between December 31, 2009 and June 30, 2010 was due primarily to the properties purchased in the Southwestern Transaction and the Common Transaction, offset by reimbursements of acreage costs from BG Group in the Haynesville area and elimination of all of our unproved property costs as of June 1, 2010 in the Appalachia area in connection with the proceeds received in connection with the Appalachia JV and the related gain. No impairment of undeveloped properties occurred during the second 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 amount sold amortized or transferred amounts into the depletable full cost pool was $372.2 million as of June 30, 2010. When the balance is moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we will cease capitalizing interest.

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 unit-of-production 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.

Divestitures 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 unit-of-production rate and/or the relationship between capitalized costs and Proved Reserves. In the event a divestiture results in a significant alteration to our full cost pool, we also record a proportionate reduction of goodwill associated with our oil and natural gas properties.

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 six months ended June 30, 2010, the trailing twelve month price was $75.76 per Bbl for oil at Cushing, Oklahoma and $4.10 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 were no ceiling test write-downs for the first or second quarters of 2010.

For the six months ended June 30, 2009, we recognized a ceiling test write-down of $1.3 billion to our proved oil and natural gas properties. This write-down occurred during the first quarter of 2009. 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 June 30, 2009, the spot price for natural gas at Henry Hub was $3.89 per Mmbtu and the spot oil price at Cushing, Oklahoma was $69.79 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.

7.	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 and six months ended June 30, 2010 and 2009 equals the net income (loss) divided by the weighted average common shares outstanding during the periods. Diluted earnings (loss) per common share for the three and six months ended June 30, 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 1,300,320 and 869,561 potential common stock equivalents were excluded from the three and six months ended June 30, 2010 diluted earnings per share. Since we incurred a net loss for the three and six months ended June 30, 2009, we have excluded potentially dilutive common stock equivalents from the assumed conversion of stock options of 14,687,706 and 14,790,302 for the three and six months ended June 30, 2009, respectively.

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


	Three months ended June 30,					Six months ended June 30,
(in thousands, except per share amount)	2010		2009			2010		2009
Basic income (loss) per common share:
Net income (loss)	$	564,313	$	(71,992	)	$	679,881	$	(1,171,603	)

Shares:
Weighted average number of common shares outstanding		212,497		211,089			212,293		211,042

Basic income (loss) per common share:
Net income (loss) per common share	$	2.66	$	(0.34	)	$	3.20	$	(5.55	)

Diluted income (loss) per share:
Net income (loss)	$	564,313	$	(71,992	)	$	679,881	$	(1,171,603	)

Shares:
Weighted average number of common shares outstanding		212,497		211,089			212,293		211,042
Dilutive effect of stock options		3,001		—			3,227		—

Weighted average number of common shares and common stock equivalent shares outstanding		215,498		211,089			215,520		211,042

Diluted income (loss) per share:
Net income (loss) per common share	$	2.62	$	(0.34	)	$	3.15	$	(5.55	)

8.	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 weighted average volatility 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 June 30, 2010 is $23.8 million over a weighted average period of 1.09 years.

The following is a reconciliation of our stock option expense for the three and six months ended June 30, 2010 and 2009:


	Three months ended June 30,				Six months ended June 30,
(in thousands)	2010		2009		2010		2009
General and administrative expense	$	3,603	$	2,575	$	7,862	$	5,101

Lease operating expense		251		682		601		1,379


Total share-based compensation expense		3,854		3,257		8,463		6,480

Share-based compensation capitalized		1,070		673		2,175		1,180


Total share-based compensation	$	4,924	$	3,930	$	10,638	$	7,660

During the six months ended June 30, 2010, options to purchase 364,350 shares were granted under the 2005 Incentive Plan at prices ranging from $16.34 to $22.22 per share with fair values ranging from $9.07 to $12.77 per share. During the six months ended June 30, 2009, options to purchase 178,600 shares were granted under the 2005 Incentive Plan at prices ranging from $7.89 to $16.29 per share with fair values ranging from $4.89 to $10.44 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of June 30, 2010 and December 31, 2009, there were 3,740,400 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. For the six months ended June 30, 2010, 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.

9.	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	June 30, 2010			December 31, 2009
Commodity contracts	Derivative financial instruments - Current assets	$	102,507		$	138,120
Commodity contracts	Derivative financial instruments - Long-term assets		39,912			34,677
Commodity contracts	Derivative financial instruments - Current liabilities		(639	)		(1,246	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(5,648	)		(11,688	)
Interest rate contracts	Derivative financial instruments - Current liabilities		—			(2,018	)

Net derivative financial instruments		$	136,132		$	157,845

The Effect of Derivative Financial Instruments


		Three months ended June 30,					Six months ended June 30,
(in thousands)	Statement of Operations location	2010		2009			2010			2009
Commodity contracts (1)	Gain (loss) on derivative financial instruments	$	707	$	(31,017	)	$	99,856		$	190,367
Interest rate contracts (2)	Interest expense		—		(4,597	)		(45	)		(481	)

Net gain (loss)		$	707	$	(35,614	)	$	99,811		$	189,886

(1)	Included in these amounts are net cash receipts of $46,538 and $123,585 for the three and six months ended June 30, 2010, respectively, and net cash receipts of $142,139 and $240,568 for the three and six months ended June 30, 2009, respectively.

(2)

Included in these amounts are net cash payments of $0 and $2,063 for the three and six months ended June 30, 2010, respectively, and net cash payments of $2,816 and $4,486 for the three and six months ended June 30, 2009, respectively. Our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2010.

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 (loss) on derivative financial instruments,” which do not impact cash flows, were losses of $45.8 million and $173.2 million for the three months ended June 30, 2010 and 2009, respectively, and were losses of $23.7 million and $50.2 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized fair value adjustments included in “Interest expense,” which do not impact cash flows, were losses of $1.8 million for the three months ended June 30, 2009, and gains of $2.0 million and $4.0 million for the six months ended June 30, 2010 and 2009, respectively. There was no impact for the three months ended June 30, 2010, as our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2010.

We place our derivative financial instruments with the financial institutions that are lenders under our credit agreement 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 June 30, 2010 and December 31, 2009, we had a net asset position of $136.1 million and $157.8 million, respectively.

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

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

The following presents a summary of the estimated fair value of our derivative financial instruments as of June 30, 2010 and as of December 31, 2009:


	For the six months ended June 30, 2010
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	136,132		$	—	$	136,132


	For the year ended 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.

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 June 30, 2010:


(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at June 30, 2010
Natural gas:
Swaps:
Remainder of 2010	27,880	$	7.19	$	65,026
2011	31,025		6.55		36,686
2012	16,470		6.05		5,921
2013	5,475		5.99		571

Total natural gas	80,850				108,204


Oil:
Swaps:
Remainder of 2010	226		114.96		8,465
2011	548		111.32		17,018
2012	92		109.30		2,445

Total oil	866				27,928


Total oil and natural gas and derivatives				$	136,132

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 June 30, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $76.73 and $79.38, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2010 and for 2011 were $4.85 and $5.34, respectively.

Our derivative financial instruments, used to mitigate price volatility, covered 54.5% and 60.1% for the three and six months ended June 30, 2010, respectively, and 75.2% and 75.0% for the three and six months ended June 30, 2009, respectively, of our total equivalent Mcfe production.

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 six months ended June 30, 2010, we recognized increases of $0.1 million to interest expense on our interest rate swaps. During the three and six months ended June 30, 2009, we recognized increases of $4.6 million and $0.5 million, respectively, to interest expense on our interest rate swaps. There was no impact for the three months ended June 30, 2010, as our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2010.

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 Senior Notes is $445.0 million with a carrying amount of $446.8 million as of June 30, 2010. The estimated fair value has been calculated based on market quotes.

10.

Current and long-term debt

Our total debt is summarized as follows:


(in thousands)	June 30, 2010		December 31, 2009
EXCO Resources Credit Agreement	$	477,500	$	81,486
EXCO Operating Credit Agreement (1)		—		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		2,111		3,993

Total debt		924,331		1,196,277
Less current maturities		446,831		—

Total long-term debt	$	477,500	$	1,196,277

(1)	On April 30, 2010, the EXCO Operating Credit Agreement was consolidated into the EXCO Resources Credit Agreement.

Credit agreements

As of June 30, 2010, we had total debt outstanding aggregating $922.2 million consisting of borrowings under our EXCO Resources Credit Agreement of $477.5 million and $444.7 million of Senior Notes, net of unamortized premiums. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended, has a borrowing base of $1.2 billion. On June 30, 2010, we had $477.5 million of outstanding indebtedness and $707.3 million of available borrowing capacity under the credit agreement. The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries which are jointly held with BG Group. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group. On July 16, 2010, the EXCO Resources Credit Agreement was further amended to allow us to repurchase up to $200.0 million of our common stock (see “Note 15. Subsequent events”).

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.

As of June 30, 2010, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which 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.

EXCO Operating Credit Agreement

On April 30, 2010, the EXCO Operating Credit Agreement was consolidated into the EXCO Resources Credit Agreement. 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.

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

As of June 30, 2010 and December 31, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at June 30, 2010 and December 31, 2009 was $2.1 million and $4.0 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.0 million on June 30, 2010. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.

11.

Dividends

On May 21, 2010 our Board of Directors approved a second quarter 2010 cash dividend equal to $0.03 per share. The total cash dividend of $6.4 million was paid on June 15, 2010 to holders of record on June 1, 2010. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources Credit Agreement, our Senior Notes and the approval of EXCO’s Board of Directors.

12.

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. For the three and six months ended June 30, 2010, we utilized $231.7 million and $277.7 million, respectively, of our accumulated valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $400.0 million, as of June 30, 2010, 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.

13.

Operating Segments

We follow FASB ASC Topic 280 for Segment Reporting when reporting operating segments. Prior to the East Texas/North Louisiana Midstream JV 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 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 East Texas/North Louisiana Midstream JV, 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 14. Equity investments”).

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.

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 June 30, 2010:
Third party revenues	$	118,344		$	—	$	—		$	118,344
Intersegment revenues		—			—		—			—

Total revenues	$	118,344		$	—	$	—		$	118,344

Segment profit	$	74,447		$	—	$	—		$	74,447


For the three months ended June 30, 2009:
Third party revenues	$	146,252		$	12,942	$	—		$	159,194
Intersegment revenues		(8,050	)		16,676		(8,626	)		—

Total revenues	$	138,202		$	29,618	$	(8,626	)	$	159,194

Segment profit	$	85,753		$	9,273	$	—		$	95,026


For the six months ended June 30, 2010:
Third party revenues	$	249,338		$	—	$	—		$	249,338
Intersegment revenues		—			—		—			—

Total revenues	$	249,338		$	—	$	—		$	249,338

Segment profit	$	167,270		$	—	$	—		$	167,270


For the six months ended June 30, 2009:
Third party revenues	$	318,460		$	29,955	$	—		$	348,415
Intersegment revenues		(16,032	)		32,252		(16,220	)		—

Total revenues	$	302,428		$	62,207	$	(16,220	)	$	348,415

Segment profit	$	192,964		$	15,818	$	—		$	208,782


As of June 30, 2010:
Capital Expenditures	$	270,103		$	—	$	—		$	270,103

Goodwill	$	218,256		$	—	$	—		$	218,256

Total assets	$	2,753,901		$	—	$	—		$	2,753,901


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 June 30,						Six months ended June 30,
(in thousands)	2010			2009			2010			2009
Segment profits	$	74,447		$	95,026		$	167,270		$	208,782
Depreciation, depletion and amortization		(45,339	)		(55,180	)		(84,157	)		(136,974	)
Write-down of oil and natural gas properties		—			—			—			(1,293,579	)
Gain on divestitures and other operating items		574,946			(8,382	)		575,353			(7,977	)
Accretion of discount on asset retirement obligations		(1,001	)		(2,018	)		(2,090	)		(4,089	)
General and administrative		(25,866	)		(22,488	)		(52,285	)		(43,035	)
Interest expense		(14,476	)		(46,891	)		(25,110	)		(83,023	)
Gain (loss) on derivative financial instruments		707			(31,017	)		99,856			190,367
Other income		57			13			117			35
Equity income		5,290			—			5,379			—

Income (loss) before income taxes	$	568,765		$	(70,937	)	$	684,333		$	(1,169,493	)

14.

Equity investments

In conjunction with the Appalachia JV that closed on June 1, 2010, we own a 50% interest in OPCO, which will operate the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. Our investment in OPCO is equal to the working capital and historical costs of assets we retained in OPCO, less the 50% interest we sold to BG Group upon closing the Appalachia JV. Our equity investment in OPCO exceeds our book value of assets by $4.1 million representing the difference in the historical basis of our investment and the 50% interest in the fair value of BG Group’s purchase. The $4.1 million basis difference is being amortized over the estimated amortized life of OPCO’s unproved properties.

In addition, certain midstream assets owned by EXCO were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which EXCO and BG Group will pursue the construction and expansion of gathering systems for anticipated future production from the Marcellus Shale. Our investment in Appalachia Midstream, LLC is equal to the assets we contributed, less the 50% interest we sold to BG Group upon closing the Appalachia JV.

Along with our 50% ownership interest in TGGT, we account for these investments under the equity method. The following tables present summarized consolidated financial information of our equity investments and a reconciliation of our investment to our proportionate 50% interest.


(in thousands)	June 30, 2010
Assets
Total current assets	$	151,387
Property and equipment, net		669,370
Other assets		848

Total assets	$	821,605

Liabilities and members’ equity
Total current liabilities	$	143,003
Total long term liabilities		8,791
Members’ equity:
Total members’ equity		669,811

Total liabilities and members’ equity	$	821,605


	Three months ended June 30, 2010		Six months ended June 30, 2010
Revenues
Oil and natural gas	$	25	$	25
Midstream		43,568		75,352

Total revenues		43,593		75,377

Costs and expenses:
Oil and natural gas production		42		42
Midstream operating		25,161		50,884
Other expenses		3,879		7,578
Depreciation, depletion and amortization		4,758		7,680

Total costs and expenses		33,840		66,184

Income before income taxes		9,753		9,193
Income tax expense		92		159

Net income	$	9,661	$	9,034

EXCO’s share of equity income before amortization	$	4,831	$	4,517
Amortization of the difference in the historical basis of our contribution		459		862

EXCO’s share of equity income after amortization	$	5,290	$	5,379


(in thousands)	June 30, 2010
Equity investments	$	288,143
Basis adjustment (1)		48,242
Cumulative amortization of basis adjustment (2)		(1,479	)

EXCO’s 50% interest in June 30, 2010 equity investments	$	334,906

(1)	Our equity investments in TGGT and OPCO exceed our book value of assets by $48.2 million represented by $59.6 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 in TGGT.

(2)	The $59.6 million basis difference is being amortized over the estimated life of associated assets.

15.

Subsequent events

On July 19, 2010, we announced a share repurchase program which authorizes us to purchase up to $200.0 million of our common stock. Any repurchases will be made in the open market, in privately negotiated transactions or in structured share repurchase programs, and may be made from time to time and

in one or more larger repurchases. The program will be conducted in compliance with the Securities and Exchange Commission’s Rule 10b-18 and applicable legal requirements and shall be subject to market conditions and other factors.

EXCO is not obligated to repurchase any common stock, or any particular amount of common stock, and the repurchase program may be modified or suspended at any time at EXCO’s discretion. The repurchases may be funded from available cash or borrowings under our credit agreement.

16.

Condensed consolidating financial statements

On April 30, 2010, when the EXCO Operating credit agreement was consolidated into the EXCO Resources Credit Agreement, certain non-guarantor subsidiaries, including EXCO Operating, which owns all of our East Texas/North Louisiana assets, became guarantor subsidiaries under our Senior Notes. The accompanying condensed consolidating financial statements are presented as if the previous non-guarantor subsidiaries were guarantor subsidiaries for each of the periods presented. As of June 30, 2010, the non-guarantor subsidiaries consist primarily of TGGT, OPCO and certain oil and natural gas properties which are pending transfer to EXCO. 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 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.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

June 30, 2010


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	4,278		$	93,509		$	240		$	—		$	98,027
Restricted cash		—			75,246			—			—			75,246
Other current assets		61,903			259,604			4,028			—			325,535

Total current assets		66,181			428,359			4,268			—			498,808

Equity Investment		—			—			288,143			—			288,143
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		44,285			341,048			236,961			—			622,294
Proved developed and undeveloped oil and natural gas properties		358,122			1,706,441			50,427			—			2,114,990
Accumulated depletion		(285,029	)		(921,470	)		(1,246	)		—			(1,207,745	)

Oil and natural gas properties, net		117,378			1,126,019			286,142			—			1,529,539

Gas gathering, office and field equipment, net		9,610			134,774			4,869			—			149,253
Investments in and advances to affiliates		962,057			—			—			(962,057	)		—
Deferred financing costs, net		18,756			—			—			—			18,756
Derivative financial instruments		29,521			10,391			—			—			39,912
Goodwill		38,100			180,156			—			—			218,256
Other assets		3			11,231			—			—			11,234

Total assets	$	1,241,606		$	1,890,930		$	583,422		$	(962,057	)	$	2,753,901


Liabilities and shareholders’ equity
Current liabilities	$	491,464		$	170,058		$	2,421		$	—		$	663,943
Long-term debt		477,500			—			—			—			477,500
Deferred income taxes		—			—			—			—			—
Other liabilities		10,806			55,116			53			—			65,975
Payable to parent		(1,284,647	)		1,267,079			17,568			—			—
Total shareholders’ equity		1,546,483			398,677			563,380			(962,057	)		1,546,483

Total liabilities and shareholders’ equity	$	1,241,606		$	1,890,930		$	583,422		$	(962,057	)	$	2,753,901

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		$	20,995		$	—	$	—		$	68,407
Restricted cash		—			58,909			—		—			58,909
Other current assets		69,449			204,880			443		—			274,772

Total current assets		116,861			284,784			443		—			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			394,313			43,999		—			492,882
Proved developed and undeveloped oil and natural gas properties		328,135			1,539,252			8,362		—			1,875,749
Accumulated depletion		(274,275	)		(858,329	)		—		—			(1,132,604	)

Oil and natural gas properties, net		108,430			1,075,236			52,361		—			1,236,027

Gas gathering, office and field equipment, net		8,175			181,261			—		—			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			231,556			—		—			269,656
Other assets		3			2,418			—		—			2,421

Total assets	$	504,708		$	1,783,056		$	269,791	$	(198,661	)	$	2,358,894


Liabilities and shareholders’ equity
Current liabilities	$	39,917		$	172,795		$	202	$	—		$	212,914
Long-term debt		530,199			666,078			—		—			1,196,277
Deferred income taxes		—			—			—		—			—
Other liabilities		5,998			84,117			—		—			90,115
Payable to parent		(930,994	)		930,994			—		—			—
Total shareholders’ equity		859,588			(70,928	)		269,589		(198,661	)		859,588

Total liabilities and shareholders’ equity	$	504,708		$	1,783,056		$	269,791	$	(198,661	)	$	2,358,894

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2010


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	16,077		$	99,220		$	3,047	$	—		$	118,344

Costs and expenses:
Oil and natural gas production		3,895			26,716			413		—			31,024
Gathering and transportation		—			12,699			174		—			12,873
Depreciation, depletion and amortization		5,697			38,624			1,018		—			45,339
Accretion of discount on asset retirement obligations		85			915			1		—			1,001
General and administrative		6,612			19,254			—		—			25,866
Gain on divestitures and other operating items		2,766			(577,712	)		—		—			(574,946	)

Total costs and expenses		19,055			(479,504	)		1,606		—			(458,843	)

Operating income (loss)		(2,978	)		578,724			1,441		—			577,187
Other income (expense):
Interest expense		(11,301	)		(3,175	)		—		—			(14,476	)
Gain (loss) on derivative financial instruments		3,088			(2,381	)		—		—			707
Other income (expense)		4,155			(4,098	)		—		—			57
Equity method income		—			—			5,290		—			5,290
Equity in earnings of subsidiaries		575,801			—			—		(575,801	)		—

Total other income (expense)		571,743			(9,654	)		5,290		(575,801	)		(8,422	)

Income (loss) before income taxes		568,765			569,070			6,731		(575,801	)		568,765
Income tax expense		4,452			—			—		—			4,452

Net income (loss)	$	564,313		$	569,070		$	6,731	$	(575,801	)	$	564,313

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenues:
Oil and natural gas	$	41,543		$	104,709		$	—	$	—	$	146,252
Midstream		—			12,942			—		—		12,942

Total revenues		41,543			117,651			—		—		159,194

Costs and expenses:
Oil and natural gas production		13,169			35,225			—		—		48,394
Midstream operating		—			11,719			—		—		11,719
Gathering and transportation		35			4,020			—		—		4,055
Depreciation, depletion and amortization		12,073			43,107			—		—		55,180
Accretion of discount on asset retirement obligations		505			1,513			—		—		2,018
General and administrative		3,886			18,602			—		—		22,488
Other operating items		(467	)		8,849			—		—		8,382

Total costs and expenses		29,201			123,035			—		—		152,236

Operating income (loss)		12,342			(5,384	)		—		—		6,958
Other income (expense):
Interest expense		(17,194	)		(29,697	)		—		—		(46,891	)
Gain (loss) on derivative financial instruments		(35,214	)		4,197			—		—		(31,017	)
Other income (expense)		6,211			(6,198	)		—		—		13
Equity method income		—			—			—		—		—
Equity in earnings of subsidiaries		(37,082	)		—			—		37,082		—

Total other income (expense)		(83,279	)		(31,698	)		—		37,082		(77,895	)

Income (loss) before income taxes		(70,937	)		(37,082	)		—		37,082		(70,937	)
Income tax expense		1,055			—			—		—		1,055

Net income (loss)	$	(71,992	)	$	(37,082	)	$	—	$	37,082	$	(71,992	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2010


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	33,722		$	211,888		$	3,728	$	—		$	249,338

Costs and expenses:
Oil and natural gas production		7,851			49,870			361		—			58,082
Gathering and transportation		—			23,694			292		—			23,986
Depreciation, depletion and amortization		12,847			70,064			1,246		—			84,157
Accretion of discount on asset retirement obligations		168			1,921			1		—			2,090
General and administrative		14,257			38,028			—		—			52,285
Gain on divestitures and other operating items		2,164			(577,517	)		—		—			(575,353	)

Total costs and expenses		37,287			(393,940	)		1,900		—			(354,753	)

Operating income (loss)		(3,565	)		605,828			1,828		—			604,091
Other income (expense):
Interest expense		(18,375	)		(6,735	)		—		—			(25,110	)
Gain on derivative financial instruments		33,942			65,914			—		—			99,856
Other income (expense)		10,329			(10,212	)		—		—			117
Equity method income		—			—			5,379		—			5,379
Equity in earnings of subsidiaries		662,002			—			—		(662,002	)		—

Total other income (expense)		687,898			48,967			5,379		(662,002	)		80,242

Income (loss) before income taxes		684,333			654,795			7,207		(662,002	)		684,333
Income tax expense		4,452			—			—		—			4,452

Net income (loss)	$	679,881		$	654,795		$	7,207	$	(662,002	)	$	679,881

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenues:
Oil and natural gas	$	79,625		$	238,835		$	—	$	—	$	318,460
Midstream					29,955			—				29,955

Total revenues		79,625			268,790			—		—		348,415

Costs and expenses:
Oil and natural gas production		27,375			74,137			—		—		101,512
Midstream operating		—			30,169			—		—		30,169
Gathering and transportation		87			7,865			—		—		7,952
Depreciation, depletion and amortization		30,963			106,011			—		—		136,974
Write-down of oil and natural gas properties		279,632			1,013,947			—				1,293,579
Accretion of discount on asset retirement obligations		1,022			3,067			—		—		4,089
General and administrative		5,714			37,321			—		—		43,035
Other operating items		(770	)		8,747			—		—		7,977

Total costs and expenses		344,023			1,281,264			—		—		1,625,287

Operating income (loss)		(264,398	)		(1,012,474	)		—		—		(1,276,872	)
Other income (expense):
Interest expense		(28,136	)		(54,887	)		—		—		(83,023	)
Gain on derivative financial instruments		71,006			119,361			—		—		190,367
Other income (expense)		12,398			(12,363	)		—		—		35
Equity method income		—			—			—		—		—
Equity in earnings of subsidiaries		(960,363	)		—			—		960,363		—

Total other income (expense)		(905,095	)		52,111			—		960,363		107,379

Income (loss) before income taxes		(1,169,493	)		(960,363	)		—		960,363		(1,169,493	)
Income tax expense		2,110										2,110

Net income (loss)	$	(1,171,603	)	$	(960,363	)	$	—	$	960,363	$	(1,171,603	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2010


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	58,315		$	135,348		$	(11,810	)		—	$	181,853

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(19,885	)		(478,113	)		(203,745	)		—		(701,743	)
Restricted cash		—			(16,337	)		—			—		(16,337	)
Investment in equity investments		—			(68,500	)		—			—		(68,500	)
Proceeds from dispositions		11,348			944,948			—			—		956,296
Advances to Appalachia JV		—			(30,448	)		—			—		(30,448	)
Advances/investments with affiliates		223,570			(439,365	)		215,795			—		—

Net cash provided by (used in) investing activities		215,033			(87,815	)		12,050			—		139,268

Financing Activities:
Borrowings under credit agreements		1,302,437			49,962			—			—		1,352,399
Repayments under credit agreements		(1,597,482	)		(24,981	)		—			—		(1,622,463	)
Proceeds from issuance of common stock, net		9,091			—			—			—		9,091
Payment of common stock dividends		(12,740	)		—			—			—		(12,740	)
Settlement of derivative financial instruments with a financing element		(907	)		—			—			—		(907	)
Deferred financing costs and other		(16,881	)		—			—			—		(16,881	)

Net cash provided by (used in) financing activities		(316,482	)		24,981			—			—		(291,501	)

Net increase (decrease) in cash		(43,134	)		72,514			240			—		29,620
Cash at beginning of period		47,412			20,995			—			—		68,407

Cash at end of period	$	4,278		$	93,509		$	240		$	—	$	98,027

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	121,583		$	105,350		$	—	$	—	$	226,933

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(34,436	)		(295,932	)		—		—		(330,368	)
Restricted Cash		(21,000	)		(16,500	)		—		—		(37,500	)
Deposits on pending property divestitures		41,188			16,500			—		—		57,688
Proceeds from dispositions of property and equipment		35,733			20,050			—		—		55,783
Advances/investments with affiliates		(53,187	)		53,187			—		—		—

Net cash used in investing activities		(31,702	)		(222,695	)		—		—		(254,397	)

Financing Activities:
Borrowings under credit agreements		14,979			37,970			—		—		52,949
Repayments under credit agreements		(17,500	)		(5,240	)		—		—		(22,740	)
Settlement of derivative financial instruments with a financing element		31,082			59,212			—		—		90,294
Proceeds from issuance of common stock, net		1,648			—			—		—		1,648
Deferred financing costs and other		(5,386	)		(15,082	)		—		—		(20,468	)

Net cash provided by financing activities		24,823			76,860			—		—		101,683

Net increase (decrease) in cash		114,704			(40,485	)		—		—		74,219
Cash at beginning of period		8,618			48,521			—		—		57,139

Cash at end of period	$	123,322		$	8,036		$	—	$	—	$	131,358

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 shale play in Appalachia and the Haynesville and Bossier shale plays 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.

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 and financial condition depend substantially on prevailing prices for oil and natural gas, the availability of capital from our credit agreement and liquidity from capital markets. Declines in oil or natural gas prices may have a material adverse affect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and ability to fund our operations. 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

Our primary strategy is to develop and exploit our Haynesville, Bossier and Marcellus shale resources and leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. Funds generated from our mature, low-cost fields are used as a source of cash flows to drill and develop our shale resources. We also continue to pursue acquisitions with shale potential.

In 2009 and 2010, we entered into joint venture agreements with affiliates of BG Group plc, or BG Group, in East Texas/North Louisiana, or the East Texas/North Louisiana JV, and Appalachia, or the Appalachia JV, which provided us with substantial liquidity to reduce our outstanding debt. These joint ventures provide a total of $550.0 million of carried drilling costs in our favor, which allows us to accelerate drilling activities in our shale plays at a smaller initial cash outlay until the drilling carry is exhausted.

In addition to the Appalachia JV, we recently acquired approximately 26,000 net acres in the Haynesville and Bossier shales, including approximately 23,800 acres in the Shelby Trough, which has allowed us to establish a second major focus area within the Haynesville and Bossier shale plays outside of our core DeSoto Parish position.

We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays in our joint ventures, exploiting our multi-year inventory of development drilling locations and accumulating undeveloped acreage in shale areas.

We intend to exploit these shales primarily through horizontal drilling. Future acquisitions are likely to be focused on supplementing these 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 $1.2 billion, of which $497.5 million was drawn as of July 29, 2010. Available borrowing capacity was $687.3 million as of July 29, 2010. We also have $444.7 million of 7¹/4% senior notes due January 15, 2011, or the Senior Notes.

For the three months ended June 30, 2010, we produced 26.5 Bcfe of oil and natural gas, with June 2010 daily production of 299 Mmcfe. Of the amount produced, 22.0 Bcfe were produced in our East Texas/North Louisiana division, 2.7 Bcfe were produced in our Appalachia division and 1.8 Bcfe were produced in our Permian division.

For the six months ended June 30, 2010, we produced 50.3 Bcfe of oil and natural gas. Of the amount produced, 40.8 Bcfe were produced in our East Texas/North Louisiana division, 6.0 Bcfe were produced in our Appalachia division and 3.5 Bcfe were produced in our Permian division.

Our plans for 2010 are focused on the Haynesville, Bossier and Marcellus shales. Our net budgeted capital expenditures for 2010, which include equity contributions to TGGT and acreage reimbursements from BG Group totals $546.8 million. 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 until the carry amount is satisfied, or the East Texas/North Louisiana Carry. During the first half of 2010, we spent $158.5 million in East Texas/North Louisiana, $123.9 million of which was in the area of mutual interest with BG Group, or the BG AMI. As of June 30, 2010, the remaining balance of the East Texas/North Louisiana Carry was approximately $237.8 million. In Appalachia we spent $75.0 million during the first half of 2010 and our remaining planned capital expenditures are expected to total $44.4 million. Similar to East Texas/North Louisiana, our Appalachia capital expenditures will be favorably impacted by the Appalachia JV, which included a $150.0 million carry equal to approximately 75% of our share of deep drilling and completion costs within our joint venture area until the carry amount is satisfied, or the Appalachia Carry. As of June 30, 2010, none of the Appalachia Carry had been utilized.

For the three and six months ended June 30, 2010, we made $24.0 million and $68.5 million, respectively, in equity contributions to our East Texas/North Louisiana midstream joint venture, or TGGT. Our remaining 2010 capital budget includes $6.5 million in equity contributions to TGGT. 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 9. Derivative financial instruments and fair value measurements” in Notes to Condensed Consolidated Financial Statements for the impact to our disclosures.

Our results of operations

A summary of key financial data for the three and six months ended June 30, 2010 and 2009 related to our results of operations is presented below:


	Three months ended June 30,						Quarter to quarter change			Six months ended June 30,						Period to period change
(dollars in thousands, except per unit prices)	2010			2009			2010-2009			2010			2009			2010-2009
Production:
Oil (Mbbls)		168			485			(317	)		327			1,012			(685	)
Natural gas (Mmcf)		25,539			33,608			(8,069	)		48,376			66,792			(18,416	)
Total production (Mmcfe) (1)		26,547			36,518			(9,971	)		50,338			72,864			(22,526	)
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	12,506		$	27,197		$	(14,691	)	$	24,469		$	46,893		$	(22,424	)
Natural gas		105,838			119,055			(13,217	)		224,869			271,567			(46,698	)

Total oil and natural gas	$	118,344		$	146,252		$	(27,908	)	$	249,338		$	318,460		$	(69,122	)

Oil and natural gas derivative financial instruments:
Cash settlements (payments) on derivative financial instruments	$	46,538		$	142,139		$	(95,601	)	$	123,585		$	240,568		$	(116,983	)
Non-cash change in fair value of derivative financial instruments		(45,831	)		(173,156	)		127,325			(23,729	)		(50,201	)		26,472

Total derivative financial instrument activities	$	707		$	(31,017	)	$	31,724		$	99,856		$	190,367		$	(90,511	)

Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	74.44		$	56.08		$	18.36		$	74.83		$	46.34		$	28.49
Natural gas (per Mcf)		4.14			3.54			0.60			4.65			4.07			0.58
Natural gas equivalent (per Mcfe)		4.46			4.00			0.46			4.95			4.37			0.58
Costs and expenses:
Oil and natural gas operating costs (2)	$	22,503		$	39,032		$	(16,529	)	$	41,696		$	79,718		$	(38,022	)
Production and ad valorem taxes		8,521			9,362			(841	)		16,386			21,794			(5,408	)
Gathering and transportation		12,873			4,055			8,818			23,986			7,952			16,034
Depletion		41,122			48,093			(6,971	)		75,142			123,077			(47,935	)
Depreciation and amortization		4,217			7,087			(2,870	)		9,015			13,897			(4,882	)
General and administrative (3)		25,866			22,488			3,378			52,285			43,035			9,250
Interest expense, net, including impacts of interest rate swaps		14,476			46,891			(32,415	)		25,110			83,023			(57,913	)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.85		$	1.07		$	(0.22	)	$	0.83		$	1.09		$	(0.26	)
Production and ad valorem taxes		0.32			0.26			0.06			0.33			0.30			0.03
Gathering and transportation		0.48			0.11			0.37			0.48			0.11			0.37
Depletion		1.55			1.32			0.23			1.49			1.69			(0.20	)
Depreciation and amortization		0.16			0.19			(0.03	)		0.18			0.19			(0.01	)
General and administrative		0.97			0.62			0.35			1.04			0.59			0.45
Net income (loss)	$	564,313		$	(71,992	)	$	636,305		$	679,881		$	(1,171,603	)	$	1,851,484

(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 $0.2 million, $0.6 million, $0.7 million and $1.4 million for the three and six months ended June 30, 2010 and 2009, respectively.

(3)	Share-based compensation included in general and administrative expenses are $3.6 million, $7.9 million, $2.6 million and $5.1 million for the three and six months ended June 30, 2010 and 2009, respectively.

The following is a discussion of our financial condition and results of operations for the three and six months ended June 30, 2010 and 2009.

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

•

the East Texas/North Louisiana JV;

•

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 equity method of accounting for our investment in TGGT.

The Appalachia JV closed on June 1, 2010. Future comparability of our results of operations will be impacted by this transaction.

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.

Summary

For the three months ended June 30, 2010, we reported net income of $564.3 million, compared to a net loss of $72.0 million for the three months ended June 30, 2009. For the six months ended June 30, 2010, we reported net income of $679.9 million, compared to a net loss of $1.172 billion for the six months ended June 30, 2009.

During 2009 we completed a divestiture program to sell certain non-strategic properties and also entered into the East Texas/North Louisiana JV and TGGT. Proceeds from the 2009 divestitures and joint venture transactions, along with the non-strategic asset sales, were approximately $2.1 billion, resulting in decreases in our full cost pool, gathering assets, operating assets and liabilities, and gains totaling approximately $691.9 million. In addition, on June 1, 2010, we closed the Appalachia JV, which resulted in the sale of a 50% undivided interest in substantially all of our Appalachian oil and natural gas proved and unproved properties and related assets for approximately $835.2 million, subject to final closing adjustments, plus a $150.0 million deep drilling carry. As a result, when comparing the first half and second quarter of 2010 to the first half and second quarter of 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.

Upon closing TGGT, we adopted the equity method of accounting for our investment in TGGT and discontinued reporting our midstream operations as a separate business segment. Results of operations from our Vernon gathering system, which was not part of TGGT, are now recorded net in “Gathering and transportation” on our Condensed Consolidated Statement of Operations.

Offsetting declines in 2010 production and revenues arising from 2009 divestitures is a $575.0 million gain associated with the Appalachia JV, along with a $9.9 million quarterly reduction and $52.8 million year-to-date reduction in our depletion and depreciation expense. During the first quarter of 2009, we recorded a $1.3 billion non-cash ceiling test write-down, which significantly impacted 2009’s net income.

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 26.5 Bcfe for the three months ended June 30, 2010, a 27.3% decrease from the prior year’s comparable period production of 36.5 Bcfe, and 50.3 Bcfe for the six months ended June 30, 2010, a 30.9% decrease from the prior year’s comparable period production of 72.9 Bcfe. While these declines are a result of the 2009 divestitures, the East Texas/North Louisiana JV and the Appalachia JV, as discussed above, management believes that analyzing the production on a pro forma basis, assuming the divestitures and joint venture transactions had occurred on January 1, 2009, provides a more meaningful analysis of the on-going production activity.


	Three months ended June 30,
	2010				2009				Quarter to quarter change
(in Mmcfe)	Actual production	Pro forma adjustment (1)		Pro forma production	Actual production	Pro forma adjustment (2)		Pro forma production	Actual production		Pro forma production
Producing region:
East Texas/North Louisiana	22,097	—		22,097	23,341	(7,973	)	15,368	(1,244	)	6,729
Appalachia	2,669	(1,085	)	1,584	5,025	(3,244	)	1,781	(2,356	)	(197	)
Permian and other	1,781	—		1,781	2,402	(388	)	2,014	(621	)	(233	)
Mid-Continent	—	—		—	5,750	(5,750	)	—	(5,750	)	—

Total	26,547	(1,085	)	25,462	36,518	(17,355	)	19,163	(9,971	)	6,299


	Six months ended June 30,
	2010				2009				Period to period change
(in Mmcfe)	Actual production	Pro forma adjustment (1)		Pro forma production	Actual production	Pro forma adjustment (2)		Pro forma production	Actual production		Pro forma production
Producing region:
East Texas/North Louisiana	40,850	—		40,850	45,957	(15,219	)	30,738	(5,107	)	10,112
Appalachia	6,010	(2,707	)	3,303	10,150	(6,544	)	3,606	(4,140	)	(303	)
Permian and other	3,478	—		3,478	5,255	(888	)	4,367	(1,777	)	(889	)
Mid-Continent	—	—		—	11,502	(11,502	)	—	(11,502	)	—

Total	50,338	(2,707	)	47,631	72,864	(34,153	)	38,711	(22,526	)	8,918

(1)	The pro forma adjustments reduce production volumes attributable to the properties affected by the Appalachia JV as if the sale had occurred on January 1, 2010.

(2)	The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by both the East Texas/North Louisiana JV and the Appalachia JV 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 and six months ended June 30, 2010 increased by 6.7 Bcfe and 10.1 Bcfe, or 43.8% and 32.9%, respectively, from the same periods in the prior year. These increases were a result of the continued successful development of our Haynesville shale, which resulted in a production increase of 9.7 Bcfe for the three months ended June 30, 2010 and production increases of 17.5 Bcfe for the six months ended June 30, 2010, when compared to the same period in the prior year. These increases were offset by production declines of 0.8 Bcfe in our Cotton Valley area and 2.2 Bcfe in our Vernon Field for the three months ended June 30, 2010 and declines of 2.2 Bcfe in our Cotton Valley area and 5.2 Bcfe in our Vernon Field for the six months ended June 30, 2010, when compared to the same period in the prior year. These declines are primarily the result of the suspension of vertical drilling operations in 2009 and normal production declines. The Appalachia and Permian divisions also experienced production declines due primarily to suspension of certain drilling programs in both areas during 2009. Our Mid-Continent division was sold during 2009.

The following table presents our revenues, production and prices by major producing areas, based on historical data, for the three and six months ended June 30, 2010 and 2009:


	Three months ended June 30,
	2010					2009					Quarter to quarter change
(in thousands, except per unit rate)	Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	22,097	$	90,354	$	4.09	23,341	$	82,778	$	3.55	(1,244	)	$	7,576		$	0.54
Appalachia	2,669		11,912		4.46	5,025		21,930		4.36	(2,356	)		(10,018	)		0.10
Permian and other	1,781		16,078		9.03	2,402		15,185		6.32	(621	)		893			2.71
Mid-Continent	—		—		—	5,750		26,359		4.58	(5,750	)		(26,359	)		(4.58	)

Total	26,547	$	118,344		4.46	36,518	$	146,252		4.00	(9,971	)	$	(27,908	)		0.46


	Six months ended June 30,
	2010					2009					Year to year change
(in thousands, except per unit rate)	Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	40,850	$	184,349	$	4.51	45,957	$	186,875	$	4.07	(5,107	)	$	(2,526	)	$	0.45
Appalachia	6,010		31,266		5.20	10,150		51,960		5.12	(4,140	)		(20,694	)		0.08
Permian and other	3,478		33,723		9.70	5,255		28,827		5.49	(1,777	)		4,896			4.21
Mid-Continent	—		—		—	11,502		50,798		4.42	(11,502	)		(50,798	)		(4.42	)

Total	50,338	$	249,338		4.95	72,864	$	318,460		4.37	(22,526	)	$	(69,122	)		0.58

For the three months ended June 30, 2010, total oil and natural gas revenues were $118.3 million, a 19.1% decrease from the three months ended June 30, 2009 total oil and natural gas revenues of $146.3 million. The decline in revenues is primarily a result of 2009 divestitures and the East Texas/North Louisiana JV, partially offset by overall increases in prices received. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $56.08 per Bbl for the three months ended June 30, 2009 to $74.44 per Bbl, or 32.7%, for the three months ended June 30, 2010. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.14 per Mcf, an increase of 16.9% for the three months ended June 30, 2010 compared with $3.54 per Mcf for the three months ended June 30, 2009.

For the six months ended June 30, 2010, total oil and natural gas revenues were $249.3 million, a 21.7% decrease from the six months ended June 30, 2009 total oil and natural gas revenues of $318.5 million. The decline in revenue is primarily a result of divestitures and the East Texas/North Louisiana JV, partially offset by increases in the prices received. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $46.34 per Bbl for the six months ended June 30, 2009 to $74.83 per Bbl, or 61.5%, for the six months ended June 30, 2010. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.65 per Mcf, an increase of 14.3% for the six months ended June 30, 2010 compared with $4.07 per Mcf for the six months ended June 30, 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 six months ended June 30, 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 $9.7 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 $0.7 million, without considering the effects of derivative financial instruments.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and six months ended June 30, 2010 were $22.5 million and $41.7 million, respectively, and represent decreases of $16.5 million, or 42.3%, and $38.0 million, or 47.7%, respectively, from the same period in 2009. While the total dollar value decrease is due primarily to the 2009 divestitures and the East Texas/North Louisiana JV, management believes that analyses on a per Mcfe basis provide a more meaningful measure than the absolute dollar decrease since the divestitures and East Texas/North Louisiana JV in 2009 were significant.

On a per Mcfe basis, oil and natural gas operating expenses for the three months ended June 30, 2010 decreased $0.22 per Mcfe from the same period in 2009, with lease operating expenses representing $0.25 of the decrease, offset by a $0.03 increase in workovers and other. 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 East Texas/North Louisiana is offset in part by the increased workover expenses in our Vernon Field. The increases in both Appalachia and Permian are a result of production declines associated with suspended drilling operations.


	Three months ended June 30,
	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	$	12,616	$	2,785	$	15,401	$	19,621	$	2,444	$	22,065	$	(7,005	)	$	341		$	(6,664	)
Appalachia		4,472		80		4,552		7,266		347		7,613		(2,794	)		(267	)		(3,061	)
Permian and other		2,335		215		2,550		2,855		333		3,188		(520	)		(118	)		(638	)
Mid-Continent		—		—		—		6,055		111		6,166		(6,055	)		(111	)		(6,166	)

Total	$	19,423	$	3,080	$	22,503	$	35,797	$	3,235	$	39,032	$	(16,374	)	$	(155	)	$	(16,529	)


	Three months ended June 30,
	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	$	0.57	$	0.13	$	0.70	$	0.84	$	0.10	$	0.94	$	(0.27	)	$	0.03		$	(0.24	)
Appalachia		1.68		0.03		1.71		1.45		0.07		1.52		0.23			(0.04	)		0.19
Permian and other		1.31		0.12		1.43		1.19		0.14		1.33		0.12			(0.02	)		0.10
Mid-Continent		—		—		—		1.05		0.02		1.07		(1.05	)		(0.02	)		(1.07	)
Operating costs per Mcfe		0.73		0.12		0.85		0.98		0.09		1.07		(0.25	)		0.03			(0.22	)

On a per Mcfe basis, oil and natural gas operating expenses for the six months ended June 30, 2010 decreased $0.26 per Mcfe from the same period in 2009, with lease operating expenses representing $0.27 of the decrease, offset by a $0.01 increase in workovers and other. 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. As discussed above, the increase in both Appalachia and Permian and other is a result of the 2009 divestitures of our Ohio and certain Northwestern Pennsylvania producing assets and certain non-strategic Permian producing assets.


	Six months ended June 30,
	2010						2009						Period to period 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	$	23,145	$	4,175	$	27,320	$	39,540	$	4,569	$	44,109	$	(16,395	)	$	(394	)	$	(16,789	)
Appalachia		9,259		216		9,475		14,672		697		15,369		(5,413	)		(481	)		(5,894	)
Permian and other		4,469		432		4,901		6,197		661		6,858		(1,728	)		(229	)		(1,957	)
Mid-Continent		—		—		—		12,982		400		13,382		(12,982	)		(400	)		(13,382	)

Total	$	36,873	$	4,823	$	41,696	$	73,391	$	6,327	$	79,718	$	(36,518	)	$	(1,504	)	$	(38,022	)


	Six months ended June 30,
	2010						2009						Period to period 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	$	0.57	$	0.10	$	0.67	$	0.86	$	0.10	$	0.96	$	(0.29	)	$	0.00		$	(0.29	)
Appalachia		1.54		0.04		1.58		1.44		0.07		1.51		0.10			(0.03	)		0.07
Permian and other		1.29		0.12		1.41		1.18		0.13		1.31		0.11			(0.01	)		0.10
Mid-Continent		—		—		—		1.13		0.03		1.16		(1.13	)		(0.03	)		(1.16	)
Operating costs per Mcfe		0.73		0.10		0.83		1.00		0.09		1.09		(0.27	)		0.01			(0.26	)

For the remainder of 2010, we expect our unit operating costs to remain flat, as we do not anticipate any significant inflation of our field service costs. Any potential increases in activity in our higher cost Vernon Field or Cotton Valley areas will be offset by our continued addition of lower cost (per Mcfe) Haynesville wells. We continue to seek new technologies and practices that will allow us to manage our field development costs across our portfolio.

Midstream operations

Until our adoption of the equity method of accounting in connection with TGGT 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.

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 which are reported under two separate bases. Gathering and transportation expenses totaled $12.9 million and $24.0 million for the three and six months ended June 30, 2010, compared to $4.1 million and $8.0 million for the three and six months ended June 30, 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 June 30, 2010 decreased by $0.8 million, or 9.0%, over the same period in 2009. Production and ad valorem taxes for the six months ended June 30, 2010 decreased by $5.4 million, or 24.8%, 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 7.2% of gross oil and natural gas sales for the three months ended June 30, 2010, compared with 6.4% during the same period in the prior year. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 6.6% of gross oil and natural gas sales for the six months ended June 30, 2010, compared with 6.8% during the same period in the prior year.

The increase in the percentage of revenue basis for the three months ended June 30, 2010 and the approximately flat change for the six months ended June 30, 2010 is primarily the result of increased volumes in the state of Louisiana, along with a delay in receipt of severance tax holidays on our deep wells in Louisiana. Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. 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 corresponding 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. This rate will decrease to $0.164 effective July 1, 2010. In addition, the Commonwealth of Pennsylvania has recently enacted legislation that raises revenue from the extraction of Marcellus shale natural gas with an effective date for implementation no later than January 1, 2011. We presently cannot quantify the impact of this legislation.

Overall, our severance and ad valorem tax rates per Mcfe were $0.32 per Mcfe for the three months ended June 30, 2010 compared with $0.26 per Mcfe for the three months ended June 30, 2009 and $0.33 per Mcfe for the six months ended June 30, 2010 compared with $0.30 per Mcfe for the six months ended June 30, 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.


	For the three months ended June 30,
	2010									2009
(in thousands, except per unit rate)	Revenue		Production (Mcfe)	Severance and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe		Revenue		Production (Mcfe)	Severance and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	90,354	22,097	$	6,666	7.4	%	$	0.30	$	82,778	23,341	$	4,956	6.0	%	$	0.21
Appalachia		11,912	2,669		506	4.2	%		0.19		21,930	5,025		590	2.7	%		0.12
Permian and other		16,078	1,781		1,349	8.4	%		0.76		15,185	2,402		1,718	11.3	%		0.72
Mid-Continent		—	—		—	N/A			N/A		26,359	5,750		2,098	8.0	%		0.36

Total	$	118,344	26,547	$	8,521	7.2	%		0.32	$	146,252	36,518	$	9,362	6.4	%		0.26


	For the six months ended June 30,
	2010									2009
(in thousands, except per unit rate)	Revenue		Production (Mcfe)	Severance and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe		Revenue		Production (Mcfe)	Severance and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	184,349	40,850	$	12,164	6.6	%	$	0.30	$	186,875	45,957	$	13,286	7.1	%	$	0.29
Appalachia		31,266	6,010		1,272	4.1	%		0.21		51,960	10,150		1,370	2.6	%		0.13
Permian and other		33,723	3,478		2,950	8.7	%		0.85		28,827	5,255		3,155	10.9	%		0.60
Mid-Continent		—	—		—	N/A			N/A		50,798	11,502		3,983	7.8	%		0.35

Total	$	249,338	50,338	$	16,386	6.6	%		0.33	$	318,460	72,864	$	21,794	6.8	%		0.30

Depletion

Our depletion expense for the three and six months ended June 30, 2010 decreased by $7.0 million and $47.9 million, or 14.5% and 38.9%, respectively, from the same periods 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 and the second quarter of 2010. These factors decreased our per unit depletion rate from $1.69 per Mcfe for the six months ended June 30, 2009 to $1.49 per Mcfe for the six months ended June 30, 2010. We expect the depletion rate to increase during 2010 as the East Texas/North Louisiana Carry is utilized.

Depreciation and amortization

Our depreciation and amortization costs for the three and six months ended June 30, 2010 decreased by $2.9 million and $4.9 million, or 40.5% and 35.1%, respectively, from the same periods in 2009. The primary reason for the decrease was the sale of our gas gathering assets to form our equity investment in TGGT during the third quarter of 2009.

Accretion of discount on asset retirement obligations for the three and six months ended June 30, 2010 decreased by $1.0 million and $2.0 million, or 50.4% and 48.9%, respectively, from the same periods in 2009. The decrease is due to the divestitures we completed in 2009 and 2010, including the sale of our Mid-Continent division, the East Texas/North Louisiana JV, and the Appalachia JV, offset by significant well additions and related future 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 three or six months ended June 30, 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 $4.10 per Mmbtu average price for Henry Hub and the $75.76 per Bbl average price for Cushing, Oklahoma.

For the six months ended June 30, 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 June 30, 2009, the spot price for natural gas at Henry Hub was $3.89 per Mmbtu and the spot oil price at Cushing, Oklahoma was $69.79 per Bbl.

General and administrative

The following table presents our general and administrative expenses for the three and six months ended June 30, 2010 and 2009:


	Three months ended June 30,						Quarter to quarter change		Six months ended June 30,						Period to period change
(in thousands, except per unit rate)	2010			2009			2010-2009		2010			2009			2010-2009
General and administrative costs:
Gross general and administrative expense	$	32,525		$	32,207		$	318	$	65,678		$	62,730		$	2,948
Operator overhead reimbursements		(4,102	)		(6,231	)		2,129		(7,872	)		(12,719	)		4,847
Capitalized acquisition and development charges		(2,557	)		(3,488	)		931		(5,521	)		(6,976	)		1,455

Net general and administrative expense	$	25,866		$	22,488		$	3,378	$	52,285		$	43,035		$	9,250

General and administrative expense per Mcfe	$	0.97		$	0.62		$	0.35	$	1.04		$	0.59		$	0.45

Our general and administrative costs for the three months ended June 30, 2010 were $25.9 million, or $0.97 per Mcfe, compared to $22.5 million, or $0.62 per Mcfe, for the same period in 2009, an increase of $3.4 million, or 15.0%. Our general and administrative costs for the six months ended June 30, 2010 were $52.3 million, or $1.04 per Mcfe, compared to $43.0 million, or $0.59 per Mcfe, for the same period in 2009, an increase of $9.3 million, or 21.5%.

Significant components of the overall increases for the three and six months ended June 30, 2010 include the following items:

•

increased salaries and benefit costs of $2.9 million and $5.1 million for the three and six months ended June 30, 2010, respectively, due primarily to technical employees hired to exploit our shale resource asset base;

•

increased costs of $0.3 million and $2.7 million for the three and six months ended June 30, 2010, respectively, due to various claims and settlements;

•

increased share-based compensation costs of $1.1 million and $2.8 million for the three and six months ended June 30, 2010, respectively, 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 and fees of $1.0 million for the six months ended June 30, 2010 due to expansion of our Dallas office;

•

increased technology costs of $0.5 million for the three months ended June 30, 2010 due to the timing of maintenance and licensing agreements;

•

increased travel costs of $0.9 million and $1.0 million for the three and six months ended June 30, 2010, respectively, primarily related to joint venture activities; and

•

decreases in operator overhead recoveries of $2.1 million and $4.8 million for the three and six months ended June 30, 2010, respectively, and capitalized charges of $0.9 million and $1.5 million for the three and six months ended June 30, 2010, respectively, both due to the 2009 divestitures.

These increases were partially offset by recoveries of technical and administrative service costs of $5.0 million and $10.1 million for the three and six months ended June 30, 2010, respectively, from our service agreement with BG Group.

Interest expense

Our interest expense decreased approximately $32.4 million and $57.9 million for the three and six months ended June 30, 2010 from the same period in 2009. The quarter and year to date decreases are 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, which was paid off on August 14, 2009, along with lower average balances on our credit agreement and higher capitalized interest. These decreases were partially offset by the write-off of deferred financing fees related to the consolidation of the EXCO Operating Credit Agreement into the EXCO Resources Credit Agreement. The following table presents the components of our interest expense:


	Three months ended June 30,						Quarter to quarter change			Six months ended June 30,						Period to period change
(in thousands)	2010			2009			2010-2009			2010			2009			2010-2009
Interest expense:
7¹/4 % senior notes due January 15, 2011	$	7,112		$	7,170		$	(58	)	$	14,239		$	14,354		$	(115	)
EXCO Resources Credit Agreement		3,760			7,269			(3,509	)		4,624			13,693			(9,069	)
EXCO Operating Credit Agreement (1)		1,441			8,772			(7,331	)		6,008			16,626			(10,618	)
Term Credit Agreement		—			7,583			(7,583	)		—			15,083			(15,083	)
Amortization of deferred financing costs on EXCO Resources Credit Agreement		942			918			24			1,293			1,695			(402	)
Amortization and write-off of deferred financing costs on EXCO Operating Credit Agreement (1)		3,943			754			3,189			4,436			1,508			2,928
Amortization of deferred financing costs on Term Credit Agreement		—			11,226			(11,226	)		—			22,329			(22,329	)
Interest rate swaps settlements		—			2,816			(2,816	)		2,063			4,486			(2,423	)
Fair market value adjustment on interest rate swaps		—			1,781			(1,781	)		(2,018	)		(4,005	)		1,987
Capitalized interest		(3,199	)		(1,436	)		(1,763	)		(6,114	)		(2,797	)		(3,317	)
Other interest expense		477			38			439			579			51			528

Total interest expense	$	14,476		$	46,891		$	(32,415	)	$	25,110		$	83,023		$	(57,913	)

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.

The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments. Our derivative activity is reported as a component of other income or expenses in our consolidated statements of operations.


	Three months ended June 30,						Quarter to quarter change			Six months ended June 30,						Period to period change
(in thousands)	2010			2009			2010 - 2009			2010			2009			2010 - 2009
Derivative financial instrument activities:
Cash settlements on derivative financial instruments, excluding early terminations	$	46,538		$	142,139		$	(95,601	)	$	85,649		$	240,568		$	(154,919	)
Cash settlements on early terminations of derivative financial instruments		—			—			—			37,936			—			37,936
Non-cash change in fair value of derivative financial instruments		(45,831	)		(173,156	)		127,325			(23,729	)		(50,201	)		26,472

Total derivative financial instrument activities	$	707		$	(31,017	)	$	31,724		$	99,856		$	190,367		$	(90,511	)

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 $4.37 during the six months ended June 30, 2009 to $4.95 during the six months ended June 30, 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 $4.95 to $6.65 per Mcfe during the six months ended June 30, 2010 and increased our price from $4.37 to $7.67 per Mcfe for the six months ended June 30, 2009. This decreased our period to period change from an increase of $0.58 per Mcfe before cash settlements on derivatives to a decrease of $1.02 per Mcfe after cash settlements on derivatives. Due to the first quarter 2010 early termination settlements, our realized price for the six months ended June 30, 2010 was further increased by $0.75 Mcfe to $7.40.


	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Period to period change
Realized pricing:	2010		2009		2010 - 2009			2010		2009		2010 - 2009
Oil per Bbl	$	74.44	$	56.08	$	18.36		$	74.83	$	46.34	$	28.49
Natural gas per Mcf		4.14		3.54		0.60			4.65		4.07		0.58

Natural gas equivalent per Mcfe	$	4.46	$	4.00	$	0.46		$	4.95	$	4.37	$	0.58
Cash settlements on derivative financial instruments, excluding early terminations		1.75		3.89		(2.14	)		1.70		3.30		(1.60	)

Net price per Mcfe, including derivative financial instruments before early terminations	$	6.21	$	7.89	$	(1.68	)	$	6.65	$	7.67	$	(1.02	)
Cash settlements on early terminations of derivative financial instruments		—		—		—			0.75		—		0.75

Net price per Mcfe, derivative financial instruments	$	6.21	$	7.89	$	(1.68	)	$	7.40	$	7.67	$	(0.27	)

Our total cash settlements for the three months ended June 30, 2010 increased revenue by $46.5 million, or $1.75 per Mcfe, compared to cash settlements increasing revenues by $142.1 million, or $3.89 per Mcfe, for the same period in 2009. Our total cash settlements for the six months ended June 30, 2010, including the derivatives settled early, increased revenue by $123.6 million, or $2.45 per Mcfe, compared to cash settlements decreasing revenues by $240.6 million, or $3.30 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 and six months ended June 30, 2010 resulted in losses of $45.8 million and $23.7 million compared to losses of $173.2 million and $50.2 million, respectively, 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 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 six months ended June 30, 2010, we had realized losses from payments of $2.1 million and non-cash unrealized gains of $2.0 million attributable to our interest rate swaps. For the three months ended June 30, 2009, we had realized losses from payments of $2.8 million and non-cash unrealized gains of $1.8 million. For the six months ended June 30, 2009, we had realized losses from payments of $4.5 million and non-cash unrealized gains of $4.0 million. These swaps expired on February 14, 2010 and as of June 30, 2010 we have not entered into any new interest rate swaps.

Income taxes

Our effective income tax rate for the three and six months ended June 30, 2010 was an expense of 0.8% and 0.7%, respectively, and for the three and six months ended June 30, 2009 was an expense of 1.5% and 0.2%, respectively. For the three and six months ended June 30, 2010, we utilized a portion of our accumulated valuation allowance of $231.7 million and $277.7 million, respectively, and have accumulated approximately $400.0 million of valuation allowance, as of June 30, 2010, which can be used against future deferred tax benefits. For the three and six months ended June 30, 2009, we recognized a valuation allowance of $29.4 million and $458.6 million, respectively, against future deferred tax benefits. The 2009 valuation allowance increases were due primarily to non-cash ceiling test write-downs. 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 and six months ended June 30, 2010 would have been 40.6% and 40.5%, respectively, and for the three and six months ended June 30, 2009 would have been 40.0% and 39.0%, respectively. A substantial portion of our stock-based compensation included in our results of operations for the three and six months ended June 30, 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 rate change last year in our state income taxes.

Our liquidity, capital resources and capital commitments

Overview

Our financial strategy is to limit capital expenditures for drilling, development and midstream expenditures to cash flows from operations. We use a combination of cash flows from operations, available borrowings under our credit agreement and proceeds from divestitures, joint ventures and capital market transactions to fund acquisitions and capital expenditures that periodically exceed our cash flow from operations. As a result of our focus on shale basins, our recent acquisitions have been primarily undeveloped acreage as opposed to producing property acquisitions.

Presently, our net capital budget, as amended for the Common Transaction, Southwestern Transaction, equity contributions to TGGT and acreage reimbursements from BG Group is approximately $546.8 million for 2010. We are presently contractually obligated to spend $213.6 million. The amended capital budget reflects a 2.2% increase from 2009 actual capital expenditures, excluding acquisitions. The remaining 2010 capital budget of $253.0 million is net of expected East Texas/North Louisiana Carry and acreage reimbursements from BG Group. We have a $150.0 million drilling carry arising from the Appalachia JV. Utilization of that carry will commence during the third quarter of 2010.

We generally do not establish a budget for acquisitions, as they tend to be opportunity driven. We typically fund acquisitions with borrowings under our credit agreement and the issuance of equity and debt securities. Our ability to borrow from sources other than our credit agreement is subject to restrictions imposed by our lenders and the indenture governing our 7¹/4% Senior Notes due January 15, 2011, or Senior Notes. These agreements contain restrictions on incurring indebtedness and pledging our assets. Any future acquisitions will likely be focused on supplementing our shale resource holdings in our East Texas/North Louisiana and Appalachia areas as economic conditions permit.

Cash flows from operations represent the primary sources of liquidity to fund our operations and capital expenditures programs while unused borrowing capacity under our credit agreement is our primary source used for acquisitions. 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 June 30, 2010 and July 29, 2010.


(in thousands)	June 30, 2010		July 29, 2010
Cash (1)	$	173,273	$	147,123
Drawings under credit agreement		477,500		497,500
Senior Notes (2)		444,720		444,720

Total debt		922,220		942,220

Net debt	$	748,947	$	795,097

Borrowing base	$	1,200,000	$	1,200,000
Total of unused borrowing base (1) (3)	$	707,298	$	687,298
Unused borrowing base plus cash (1) (3)	$	880,571	$	834,421

(1)	Includes restricted cash of $75.2 million at June 30, 2010 and $116.2 million at July 29, 2010.

(2)	Excludes unamortized bond premium of $2.1 million at June 30, 2010 and $1.8 million at July 29, 2010.

(3)	Net of $15.2 million in letters of credit at June 30, 2010 and July 29, 2010.

Recent events affecting liquidity

We closed the Appalachia JV on June 1, 2010 which resulted in net proceeds of approximately $835.2 million, subject to final closing adjustments and used $780.0 million of those proceeds to reduce the outstanding balance on our credit agreement. Upon closing of the Appalachia JV, the borrowing base on our credit agreement was reduced to $1.2 billion from $1.3 billion. We expect the impacts from the Appalachia JV to our capital resources and liquidity will include the following:

•

a reduction in net operating cash flow from the sale of 50% of the existing shallow production representing approximately 17.5 Mmcfe per day sold to BG Group;

•

increases in drilling and development activities, including an increase from one horizontal drilling rig to three by the end of 2010.

•

decreases in Appalachian drilling costs arising from the benefit of the Appalachia Carry equal to 75% of EXCO’s share of drilling and development costs;

•

increased availability and reduced interest costs under EXCO’s credit agreement resulting from the reduction of $780.0 million from the Appalachia JV; and

•

increase in midstream capital expenditures to construct gathering systems, pipelines and other midstream infrastructure to support future production from the Marcellus Shale Play;

On May 14, 2010, EXCO and BG Group jointly closed the purchase of Common Resources, L.L.C., or the Common Transaction. The total purchase price paid at the closing was approximately $441.6 million ($220.8 million net to EXCO), subject to customary post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under our credit agreement. We jointly acquired 8 producing Haynesville horizontal wells and approximately 27,600 net acres (13,800 net to EXCO) prospective for the Haynesville and Bossier shales in the Shelby Trough in East Texas as a result of the Common Transaction. The Common Transaction created a second major focus area for us outside of our core DeSoto Parish position. The development of these assets are governed by our East Texas/North Louisiana JV.

On June 30, 2010, EXCO and BG Group jointly closed the purchase of properties in Shelby, San Augustine and Nacogdoches Counties, Texas representing 9 producing Haynesville horizontal wells and approximately 20,000 net acres (10,000 net to EXCO) prospective for the Haynesville and Bossier Shales from Southwestern Energy Company, or the Southwestern Transaction. The total purchase price paid at the closing was $355.8 million ($177.9 million net to EXCO), subject to customary post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under our credit agreement. The development of these assets is governed by the East Texas/North Louisiana JV. The majority of the assets acquired in the Southwestern Transaction represent incremental working interests in properties that EXCO and BG Group acquired in the Common Transaction.

The capital and credit markets have remained constrained and unpredictable through the first half 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. The instability in the U.S. credit markets has been heightened by critical deficit problems and instability in the European markets.

In addition to the instability in the U.S and international 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 second quarter of 2010. As of July 29, 2010, the spot prices for oil and natural gas were $78.36 per Bbl and $4.76 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 July 29, 2010 for natural gas have also declined from the 2010 average NYMEX future prices as of December 31, 2009 by $0.81 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.

Other regulatory matters which may affect our capital resources and liquidity include recent legislation addressing derivatives and other financial reforms and proposed changes in income tax benefits available to the energy industry. As a result of this financial reform legislation, we expect increases in the costs of derivatives, borrowing costs and regulatory compliance costs. In addition, the recently enacted healthcare legislation is expected to increase the costs of our employee benefit programs and impact our results of operations and liquidity. Presently, we are not able to quantify these impacts.

Our capital budget for 2010 focuses on Haynesville and Bossier shale plays in East Texas/North Louisiana and the Marcellus shale play in Appalachia. The East Texas/North Louisiana JV and the Appalachia JV reduced our ownership interest in our East Texas/North Louisiana and Appalachia properties by 50%. Provisions in our joint ventures with BG Group to fund 75% of our share of drilling and development costs on horizontal wells provide us with substantial economic benefit toward development of these shale resources. As of June 30, 2010, approximately $237.8 million of the East Texas/North Louisiana Carry remains unfunded and all of the $150.0 million in Appalachia is unfunded. While the East Texas/North Louisiana Carry in the Haynesville and Bossier shale plays and the Appalachia Carry in the Marcellus shale play reduce our capital expenditures, the instability of the credit markets and ongoing low natural gas prices remain areas of significant concern.

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 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. The effectiveness of our derivative financial instruments may also impact our future cash flows. While we continue to evaluate opportunities to enter into derivative financial instruments, our recent percentage of expected production covered by derivative financial instruments has decreased compared to previous years due to our reduced debt, uncertainty surrounding regulation of derivative financial instruments and low commodity prices.

Our Senior Notes, which have a principal balance of $444.7 million, mature on January 15, 2011. We believe that our cash flows from operations and amounts available to us under our credit agreement 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.

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. 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 income taxes.

Net cash provided by operating activities was $181.9 million for the six months ended June 30, 2010 compared with $226.9 million for the six months ended June 30, 2009. The 19.7% decrease is attributable primarily to lower production resulting from divestitures and 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 July 29, 2010, our cash and cash equivalents balance was $116.2 million and our restricted cash account, which is principally used for Haynesville development operations, was $147.1 million.

We made cash dividend payments to our common shareholders of $6.4 million on June 15, 2010.

Investing activities and transactions

Our investing activities consist primarily of drilling and development expenditures, capital contributions to our jointly-owned midstream ventures and acquisitions. Our recent acquisitions have been focused primarily on undeveloped shale acreage and have been funded primarily with borrowings under our credit agreement. We also receive reimbursements from BG Group on these acquisitions when they elect to participate. Future acquisitions are dependent on oil and natural gas prices, availability of attractive acreage and availability of borrowing capacity under our credit agreement.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the three and six months ended June 30, 2010 and 2009 and does not include expected reimbursements from BG Group of $192.0 million:


	Three months ended June 30,				Six months ended June 30,
(in thousands)	2010		2009		2010		2009
Capital expenditures:
Acquisitions	$	443,571	$	386	$	452,269	$	393
Lease purchases		18,122		7,256		67,385		18,246
Development capital expenditures		102,602		84,691		167,595		197,717
Midstream capital additions		—		19,699		—		33,143
Seismic		5,571		2,370		9,721		8,353
Gas Gathering (1)		3,895		854		6,023		1,173
Corporate and other		10,936		8,978		20,893		17,109

Total capital expenditures	$	584,697	$	124,234	$	723,886	$	276,134

(1)	Principally Vernon Gathering and Appalachia-related expenditures.

Future capital expenditures 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 July 29, 2010, we have total debt outstanding aggregating $942.2 million consisting of borrowings under the EXCO Resources Credit Agreement of $497.5 million and $444.7 million of Senior Notes due on January 15, 2011. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended, has a borrowing base of $1.2 billion. On June 30, 2010, we had $477.5 million of outstanding indebtedness and $707.3 million of available borrowing capacity under the credit agreement. The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries which are jointly held with BG Group. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group. On July 19, 2010, the EXCO Resources Credit Agreement was further amended to allow for stock repurchases of up to $200.0 million.

As of June 30, 2010, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which 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

•

The foregoing description is not complete and is qualified in its entirety by the EXCO Resources Credit Agreement.

7¹/4% senior notes due January 15, 2011

As of June 30, 2010, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at June 30, 2010 was $2.1 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.0 million on June 30, 2010.

Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year. Our last interest payment on the Senior Notes is scheduled for January 15, 2011. The Senior Notes are currently callable at par plus accrued interest upon 30 days notice.

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.

In connection with our entrance into the amended EXCO Resources Credit Agreement as of April 30, 2010, EXCO Operating Company and certain subsidiaries became guarantor subsidiaries of the Senior Notes. However, certain other subsidiaries, including TGGT and Common Resources, L.L.C., are 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 June 30, 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:
Q3 2010	13,940	$	7.16	113	$	114.96
Q4 2010	13,940		7.21	113		114.96
2011	31,025		6.55	548		111.32
2012	16,470		6.05	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 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.

Off-balance sheet arrangements

We have no arrangements or any guarantees of off balance sheet debt to third parties.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at June 30, 2010:


	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
Senior Notes (1)	$	444,720	$	—	$	—	$	—	$	444,720
Long-term debt - EXCO Resources Credit Agreement (2)		—		477,500		—		—		477,500
Firm transportation services and other fixed commitments (3)		38,092		63,680		62,490		151,289		315,551
Operating leases		5,390		8,563		6,542		933		21,428
Drilling contracts		69,711		54,458		5,900		—		130,069

Total contractual obligations	$	557,913	$	604,201	$	74,932	$	152,222	$	1,389,268

(1)	Our Senior Notes are due on January 15, 2011. The remaining interest obligation of $16.1 million is due January 15, 2011.

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

(3)

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.

The following table sets forth our oil and natural gas derivative financial instruments measured at fair value as of June 30, 2010.


(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at June 30, 2010
Natural gas:
Swaps:
Remainder of 2010	27,880	$	7.19	$	65,026
2011	31,025		6.55		36,686
2012	16,470		6.05		5,921
2013	5,475		5.99		571

Total natural gas	80,850				108,204


Oil:
Swaps:
Remainder of 2010	226		114.96		8,465
2011	548		111.32		17,018
2012	92		109.30		2,445

Total oil	866				27,928


Total oil and natural gas and derivatives				$	136,132

At June 30, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $76.73 and $79.38, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2010 and for 2011 were $4.85 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 June 30, 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 226 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 226 Mbbls. For example, for a hedged volume of 226 Mbbls, if the settlement price is $115.96 per Bbl then other income would decrease by $0.2 million. Conversely, if the settlement price is $113.96 per Bbl, other income would increase by $0.2 million.

Interest rate risk

At June 30, 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 7¹/4% 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 June 30, 2010, we had approximately $477.5 million in outstanding borrowings under our credit agreements. A 1% change in interest rates based on the variable borrowings as of June 30, 2010 would result in an increase or decrease in our interest costs of $4.8 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 agreement 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 effective as of June 30, 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 June 30, 2010 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1A.

Risk Factors

We conduct a substantial portion of our operations through joint ventures, and our failure to continue such joint ventures or resolve any material disagreements with our partners could have a material adverse effect on the success of these operations, our financial condition and our results of operations.

We conduct substantial portion of our operations through joint ventures with third parties, principally BG Group, and as a result, the continuation of such joint ventures is vital to our continued success. We may also enter into other joint venture arrangements in the future. In many instances we depend on these third parties for elements of these arrangements that are important to the success of the joint venture, such as agreed payments of substantial carried costs pertaining to the joint venture and their share of capital and other costs of the joint venture. The performance of these third party obligations or their ability to meet their obligations under these arrangements are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected. If our current or future joint venture partners are unable to meet their obligations, we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights that may cause disputes among our joint venture parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint ventures and/or our ability to enter into future joint ventures.

Such joint venture arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

•

our joint venture partners may share certain approval rights over major decisions;

•

the possibility that our joint venture partners might become insolvent or bankrupt, leaving us liable for their shares of joint venture liabilities;

•

the possibility that we may incur liabilities as a result of an action taken by our joint venture partners;

•

that such our joint venture partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;

•

disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and prevent our officers and directors from focusing their time and effort on our business; and

•

that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture, and an impasse could be reached which might have a negative influence on the joint venture.

In addition, in the event that any of our partners were to decide to terminate its relationship with us in any of these companies or sell its interest in any of these companies, we may not be able to replace our partner or raise the necessary financing to purchase our partner’s interest. As a result, the failure to continue some of our joint ventures or to resolve disagreements with our partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations.

Our joint ventures with BG Group contemplate that we will make significant capital expenditures and subject us to certain legal and financial terms that could adversely affect us.

On August 14, 2009 we closed two joint venture transactions with BG Group, which involved the sale of an undivided 50% interest in an area of mutual interest in certain oil and natural gas properties in East Texas and North Louisiana and a 50% interest in certain midstream operations. The upstream transaction operates as a joint venture pursuant to a joint development agreement under which EXCO acts as the operator. The midstream transaction functions as a ⁵⁰/50 joint venture between EXCO and BG Group, with neither party having control over the management of, or a controlling beneficial economic interest in, the operations.

On June 1, 2010, we closed our Appalachian joint venture with BG Group. Pursuant to the agreements governing the joint venture, EXCO and BG Group agreed to jointly explore and develop their Appalachian properties, particularly the Marcellus shale. EXCO and BG Group each own a 50% interest in an operating company which will operate the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. In addition, certain midstream assets owned by EXCO were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which EXCO and BG Group will pursue the construction and expansion of gathering systems, pipeline systems and treating facilities for future anticipated future production from the Marcellus shale.

Each of these joint ventures may require us to make significant capital expenditures. If we do not timely meet our financial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be adversely affected and other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations.

EXCO has unconditionally guaranteed its subsidiaries’ performance of the joint venture agreements under the Appalachia joint ventures.

Certain of our undeveloped leasehold acreage, including acreage recently acquired, is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We have leasehold interests in excess of 67,000 net acres across all of our shale plays that are not currently held by production and are subject to leases with primary or renewed terms expiring over the next several years, including approximately 16,000 net acres prospective for the Haynesville and Bossier shales that we recently acquired in the Common Transaction and the Southwestern Transaction. Unless we establish production in paying quantities on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

While we intend to drill sufficient wells to hold the vast majority of our leasehold interests in all of our major plays, our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey cap-and-trade legislation, or ACES. The purpose of ACES is to control and reduce emissions of greenhouse gases, or GHGs, in the United States. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to warming of the Earth’s atmosphere resulting in climatic changes. ACES would establish a cap on total emissions of GHGs from certain categories of emission sources in the United States and require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACES, those categories of sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACES’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. If enacted, the net effect of ACES would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACES, the Senate legislation would need to be reconciled with ACES, and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance system that results in fewer allowances being issued over time, but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate will act on climate change legislation or how any bill approved by the Senate would be reconciled with ACES, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

The U.S. Environmental Protection Agency, or EPA, has also taken recent action related to greenhouse gases under existing authority of the federal Clean Air Act. On December 7, 2009, the EPA issued a notice of its finding and determination that emissions of carbon dioxide, methane, and other GHGs may reasonably be anticipated to endanger the public health and public welfare by, among other things, increasing ground-level ozone, altering the climate, contributing to a rise in sea levels, and harming water resources, agriculture, wildlife, and ecosystems. On March 31, 2010, EPA promulgated regulations controlling GHG emissions from motor vehicles. As a result, EPA was required to begin regulating emissions of GHGs under existing permitting provisions of the federal Clean Air Act. Those permitting provisions could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those permitting requirements. On May 13, 2010, EPA published its “Tailoring Rule” to regulate the permitting of GHG sources under the Clean Air Act’s PSD and Title V programs. Under this rule, permitting requirements, including emission limitations, will be phased in over the next several years depending on the types of facilities and on their GHG emissions. Any limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. On September 22, 2009, EPA finalized a GHG reporting rule, which will require large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions, and, on April 10, 2010, published a proposal to expand that rule to cover oil and gas operations. Although this rule and the proposed amendment to it do not limit the amount of GHGs that can be emitted, they could require us to incur costs to monitor, recordkeep and report emissions of GHGs associated with our operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, or the Dodd-Frank Act, which is aimed to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulating certain derivative products, but many aspects of these laws are subject to further rulemaking and will take effect over several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining derivative financial instrument arrangements. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain derivative arrangements. In particular, the Dodd-Frank Act could result in the implementation of (a) position limits and (b) additional regulatory requirements on our derivative arrangements, which could include new margin, reporting, and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. The imposition of these types of requirements or limitations could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. It should be further noted that the use of derivative arrangements can play an important role in our acquisition strategies; therefore, any limitations or changes in our use of derivative arrangements could also affect our future ability to conduct acquisitions.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, including, for example, the Fracturing Responsibility and Awareness of Chemicals Act, sponsored by Senators Bob Casey (D-PA) and Charles Schumer (D-NY). Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. These bills, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance. In addition, a number of states, such as New York and Pennsylvania, are considering or have implemented more stringent regulatory requirements applicable to fracing, which, such as in the case of New York, could include a moratorium on drilling.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

On July 19, 2010, we announced the adoption of a share repurchase program to purchase up to $200.0 million of our common stock. We have not repurchased any shares pursuant to such share repurchase program to date.

Item 6.

Exhibits

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

SIGNATURES

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

EXCO RESOURCES, INC.

(Registrant)


Date: August 4, 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

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.

2.9		Membership Interest Transfer Agreement, dated as of May 9, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

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

3.2		Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.

3.3		Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.

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

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



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

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

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

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

4.1		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2008 filed February 26, 2009 and incorporated by reference herein.

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

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

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

4.5		Form of 7¹/4% Global Note Due 2011, filed as an Exhibit to EXCO’s 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.

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.

4.13		Ninth Supplemental Indenture, dated April 30, 2010, by and among EXCO Resources, Inc., EXCO Partners GP, LLC, EXCO GP Partners Old, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, Vernon Gathering, LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.



4.14		Tenth Supplemental Indenture, May 9, 2010, EXCO Resources, Inc., EXCO Holding (PA), Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

4.15		Eleventh Supplemental Indenture, May 28, 2010, EXCO Resources, Inc., EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company (PA), LLC, BG Production Company (WV), LLC, EXCO Resources (PA), LLC, Appalachia Midstream, LLC, EXCO Resources (XA), LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.1		Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as 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 7¹/4% 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.

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.

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		Ninth Supplemental Indenture, dated April 30, 2010, by and among EXCO Resources, Inc., EXCO Partners GP, LLC, EXCO GP Partners Old, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, Vernon Gathering, LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.34		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.

10.35		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.

10.36		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.

10.37		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.

10.38		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.

10.39		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.

10.40		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.

10.41		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.

10.42		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.

10.43		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.

10.44		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.



10.45		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.

10.46		Tenth Supplemental Indenture, May 9, 2010, EXCO Resources, Inc., EXCO Holding (PA), Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.47		Eleventh Supplemental Indenture, May 28, 2010, EXCO Resources, Inc., EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company (PA), LLC, BG Production Company (WV), LLC, EXCO Resources (PA), LLC, Appalachia Midstream, LLC, EXCO Resources (XA), LLC and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.48		Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.49		Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.50		Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.51		Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.52		Membership Interest Transfer Agreement, dated as of May 9, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.53		Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.54		Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.55		Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.56		Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.57		Credit Agreement, dated as of April 30, 2010, among EXCO Resources, Inc., 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, Wells Fargo Securities, LLC, as Co-Lead Arranger, Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 16, 2010 and filed on June 22, 2010 and incorporated by reference herein.



10.58		First Amendment to Credit Agreement, dated as of July 16, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 16, 2010 and filed on June 22, 2010 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.

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Calculation Linkbase Document

101.DEF**		XBRL Taxonomy Definition Linkbase Document

101.LAB**		XBRL Taxonomy Label Linkbase Document

101.PRE**		XBRL Taxonomy Presentation Linkbase Document

*	These exhibits are management contracts.

Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.