EXCO RESOURCES INC - FORM 10-Q

EXCO RESOURCES INC - FORM 10-Q - November 4, 2009

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EX-32.1 - CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906 - EXCO RESOURCES INC	dex321.htm
EX-2.10 - PURCHASE AND SALE AGREEMENT BETWEEN EXCO RESOURCES AND SHERIDAN HOLDING COMPANY - EXCO RESOURCES INC	dex210.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 302 - EXCO RESOURCES INC	dex312.htm
EX-31.3 - CERTIFICATION OF CAO PURSUANT TO SECTION 302 - EXCO RESOURCES INC	dex313.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 302 - EXCO RESOURCES INC	dex311.htm
EX-2.9 - PURCHASE AND SALE AGREEMENT BETWEEN EXCO RESOURCES AND NORTH COAST ENERGY, INC. - EXCO RESOURCES INC	dex29.htm

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 September 30, 2009

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

For the transition period from to

Commission File Number 0-9204

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)


Texas		74-1492779
(State of incorporation)		(I.R.S. Employer Identification No.)


12377 Merit Drive Suite 1700, LB 82 Dallas, Texas		75251
(Address of principal executive offices)		(Zip Code)

(214) 368-2084

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files). YES ¨ NO ¨

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

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 October 30, 2009 was 211,677,939.

EXCO RESOURCES, INC.

INDEX


PART I.	FINANCIAL INFORMATION	3

Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at September 30, 2009 and December 31, 2008	3
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008	5
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2009 and 2008	7
	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 4.	Controls and Procedures	55

PART II.	OTHER INFORMATION	55

Item 1A.	Risk Factors	55
Item 6.	Exhibits	57
	Signatures	57
	Index to Exhibits	58

PART I—FINANCIAL INFORMATION

Item 1.

Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	September 30, 2009			December 31, 2008
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	55,681		$	57,139
Restricted cash		69,983			—
Accounts receivable:
Oil and natural gas		40,356			130,970
Joint interest		35,070			22,807
Interest and other		6,545			5,895
Inventory		28,864			42,479
Derivative financial instruments		203,641			247,614
Deferred income taxes		—			—
Other		8,578			6,136

Total current assets		448,718			513,040

Equity investment in TGGT Holdings, LLC		216,631			—
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		246,272			481,596
Proved developed and undeveloped oil and natural gas properties		2,200,915			3,578,344
Accumulated depletion		(1,103,901	)		(936,088	)

Oil and natural gas properties, net		1,343,286			3,123,852

Gas gathering assets		188,648			485,201
Accumulated depreciation and amortization		(21,885	)		(32,232	)

Gas gathering assets, net		166,763			452,969

Office and field equipment, net		30,390			25,647
Derivative financial instruments		85,943			173,003
Deferred financing costs, net		12,356			62,884
Other assets		2,653			880
Goodwill		324,756			470,077

Total assets	$	2,631,496		$	4,822,352

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands, except per share and share data)	September 30, 2009			December 31, 2008
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	78,914		$	172,400
Accrued interest payable		8,173			28,746
Revenues and royalties payable		79,323			108,130
Income taxes payable		1,060			160
Current portion of asset retirement obligations		16			1,830
Derivative financial instruments		13,772			11,607

Total current liabilities		181,258			322,873

Long-term debt, net of current maturities		1,689,277			3,019,738
Asset retirement obligations and other long-term liabilities		116,251			125,279
Deferred income taxes		8,661			9,371
Derivative financial instruments		24,386			12,590
Commitments and contingencies		—			—

Shareholders’ equity:
Preferred stock, $0.001 par value; authorized shares - 10,000,000; none issued and outstanding		—			—
Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 211,508,191 at September 30, 2009 and 210,968,931 at December 31, 2008		212			211
Additional paid-in capital		3,088,200			3,070,766
Accumulated deficit		(2,476,749	)		(1,738,476	)

Total shareholders’ equity		611,663			1,332,501

Total liabilities and shareholders’ equity	$	2,631,496		$	4,822,352

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share data)	2009			2008			2009			2008
Revenues:
Oil and natural gas	$	125,493		$	402,407		$	443,953		$	1,155,986
Midstream		5,375			27,004			35,330			61,852

Total revenues		130,868			429,411			479,283			1,217,838

Costs and expenses:
Oil and natural gas production		43,026			63,002			144,538			177,526
Midstream operating expenses		5,411			28,820			35,580			59,671
Gathering and transportation		4,927			3,672			12,879			10,503
Depreciation, depletion and amortization		50,709			126,207			187,683			346,705
Write-down of oil and natural gas properties		—			1,193,105			1,293,579			1,193,105
Gain on divestitures		(460,626	)		—			(460,626	)		—
Accretion of discount on asset retirement obligations		1,767			1,482			5,856			4,271
General and administrative		21,647			21,002			64,682			63,286

Total costs and expenses		(333,139	)		1,437,290			1,284,171			1,855,067

Operating income (loss)		464,007			(1,007,879	)		(804,888	)		(637,229	)
Other income (expense):
Interest expense		(46,737	)		(44,874	)		(129,760	)		(101,167	)
Gain (loss) on derivative financial instruments		14,518			900,313			204,885			(103,534	)
Other income (expense)		47			1,820			(7,895	)		5,496
Equity method loss in TGGT Holdings, LLC		(426	)		—			(426	)		—

Total other income (expense)		(32,598	)		857,259			66,804			(199,205	)

Income (loss) before income taxes		431,409			(150,620	)		(738,084	)		(836,434	)
Income tax expense (benefit)		(1,921	)		(4,291	)		189			(264,352	)

Net income (loss)		433,330			(146,329	)		(738,273	)		(572,082	)
Preferred stock dividends		—			(6,997	)		—			(76,997	)

Net income (loss) available to common shareholders	$	433,330		$	(153,326	)	$	(738,273	)	$	(649,079	)

Earnings (loss) per common share:
Basic
Net income (loss) available to common shareholders	$	2.05		$	(0.80	)	$	(3.50	)	$	(4.84	)

Weighted average number of common shares outstanding		211,266			191,452			211,118			134,006

Diluted
Net income (loss) available to common shareholders	$	2.03		$	(0.80	)	$	(3.50	)	$	(4.84	)

Weighted average common and common equivalent shares outstanding		213,235			191,452			211,118			134,006

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,
(in thousands)	2009			2008
Operating Activities:
Net loss	$	(738,273	)	$	(572,082	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss (gain) on sale of other assets		—			20
Depreciation, depletion and amortization		187,683			346,705
Stock option compensation expense		9,863			10,842
Write-down of oil and natural gas properties		1,293,579			1,193,105
Gain on divestitures		(460,626	)		—
Equity method loss in TGGT Holdings, LLC		426			—
Accretion of discount on asset retirement obligations		5,856			4,271
Non-cash change in fair value of derivatives		144,996			(59,004	)
Cash settlements of assumed derivatives		(141,782	)		96,504
Deferred income taxes		(711	)		(264,657	)
Amortization of deferred financing costs and premium on 7¹/4% senior notes due 2011 and discount on long-term debt		44,327			6,527
Effect of changes in:
Accounts receivable		66,961			(27,569	)
Other current assets		(5,094	)		570
Accounts payable and other current liabilities		(57,348	)		76,785

Net cash provided by operating activities		349,857			812,017

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(388,859	)		(741,654	)
Property and midstream acquisitions		(67,774	)		(745,219	)
Net proceeds from disposition of property and equipment and other		60,774			—
Restricted cash		(69,983	)		—
Equity investment in TGGT Holdings, LLC		(47,500	)		—
Deposit on pending divestitures		14,500			—
Net proceeds from disposition of oil and natural gas properties, gathering systems and equipment		1,348,604			1,736

Net cash provided by (used in) investing activities		849,762			(1,485,137	)

Financing Activities:
Borrowings under credit agreements		52,949			1,065,185
Repayments under credit agreements		(1,080,740	)		(476,200	)
Borrowings under senior unsecured credit term agreement		—			300,000
Repayments under senior unsecured credit term agreement		(300,000	)		—
Proceeds from issuance of common stock		5,400			14,465
Payment of preferred stock dividends		—			(82,827	)
Settlements of derivative financial instruments with a financing element		141,782			(96,504	)
Deferred financing costs		(20,468	)		(11,374	)

Net cash provided by (used in) financing activities		(1,201,077	)		712,745

Net increase (decrease) in cash		(1,458	)		39,625
Cash at beginning of period		57,139			55,510

Cash at end of period	$	55,681		$	95,135


Supplemental Cash Flow Information:
Interest paid	$	90,010		$	109,017

Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	2,122		$	2,263

Capitalized interest	$	3,937		$	1,925

Issuance of common stock for director services	$	50		$	120

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


				Additional paid-in capital		Accumulated deficit			Total shareholders’ equity
	Common Stock
(in thousands)	Shares	Amount
Balance at December 31, 2008	210,969	$	211	$	3,070,766	$	(1,738,476	)	$	1,332,501
Issuance of common stock	539		1		5,450		—			5,451
Share-based compensation	—		—		11,984		—			11,984
Net loss	—		—		—		(738,273	)		(738,273	)

Balance at September 30, 2009	211,508	$	212	$	3,088,200	$	(2,476,749	)	$	611,663


Balance at December 31, 2007	104,579	$	105	$	1,043,645	$	71,992		$	1,115,742
Issuance of common stock	1,084		1		14,584		—			14,585
Preferred stock conversion	105,263		105		1,992,170		—			1,992,275
Preferred stock dividends	—		—		—		(76,997	)		(76,997	)
Share-based compensation	—		—		13,105		—			13,105
Net loss	—		—		—		(572,082	)		(572,082	)

Balance at September 30, 2008	210,926	$	211	$	3,063,504	$	(577,087	)	$	2,486,628

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.

EXCO Resources, Inc., a Texas corporation, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, as of August 14, 2009, we hold a 50% equity interest in a midstream joint venture which owns gathering systems and pipelines in East Texas and North Louisiana. Our assets in East Texas/North Louisiana, including our equity interest in the midstream operations, are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries, collectively, EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt.

The accompanying condensed consolidated balance sheets as of September 30, 2009 and December 31, 2008, the statements of operations for the three and nine months ended September 30, 2009 and 2008, the statements of cash flows for the nine months ended September 30, 2009 and 2008 and the changes in shareholders’ equity for the nine months ended September 30, 2009 and 2008, are for EXCO and its subsidiaries. The condensed 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 September 30, 2009 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Beginning in the fourth quarter of 2008, we reclassified our derivative financial instrument activities and other income items to the other income (expense) caption on our Consolidated Statements of Operations. Previously, we reported these items as a component of revenues. We have reclassified prior year amounts to conform to current year reporting. Additionally, as a result of our midstream transaction on August 14, 2009 as discussed in “Note 2. Significant recent activities,” we no longer report our midstream operations as a separate business segment. Effective August 14, 2009, we account for our midstream operations as an equity method investment. Our gathering system in Louisiana that supports our Vernon Field operations, which was previously reported within our midstream segment, is now reported in “Gathering and transportation” on the Condensed Consolidated Statement of Operations.

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 August 11, 2009, we closed a sale of properties located in East Texas, or the East Texas Transaction, with Encore Operating, LP, or Encore. Pursuant to the East Texas Transaction, we sold all of our interests in certain oil and natural gas properties located in our Overton Field and Gladewater area of East Texas. We received $156.7 million in cash at closing, after customary preliminary closing adjustments.

Also on August 11, 2009, we closed a sale of properties located in Texas and Oklahoma, or the Mid-Continent Transaction, with Encore. Pursuant to the Mid-Continent Transaction, we sold all of our interests in certain oil and gas properties located in our Mid-Continent operating area. We received $199.4 million in cash at closing, after customary preliminary closing adjustments.

Proceeds from the transactions pursuant to the East Texas Transaction and the Mid-Continent Transaction were used to repay a portion of our revolving credit agreements.

On August 14, 2009, we closed a sale and joint development transaction with BG Group, plc, or BG Group, for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which included most of our oil and natural gas assets in East Texas/North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), or the BG Upstream Transaction. The BG Upstream Transaction includes agreements for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We received $727.0 million in cash at closing, after closing adjustments and the adjustments necessary to reflect the January 1, 2009 effective date. Pursuant to this transaction, BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, BG Group funding of the $400.0 million commitment will be satisfied solely through drilling of deep right wells as defined in the agreement.

The transactions with BG Group and Encore caused a significant alteration to our full cost pool and a gain of $362.3 million was recorded as a result of these transactions.

In addition, on August 14, 2009, we closed the sale to an affiliate of BG Group of a 50% interest in a newly formed company, TGGT Holdings, LLC, or TGGT, which now holds most of our East Texas and North Louisiana midstream assets, or the BG Midstream Transaction. Our Vernon Field midstream assets were excluded from the BG Midstream Transaction. Pursuant to the contribution agreement, we contributed TGG Pipeline, Ltd., or TGG, which owns intrastate pipelines in East Texas and North Louisiana, and Talco Midstream Assets, Ltd., or Talco, which owns gathering assets in East Texas and North Louisiana, to TGGT. BG Group contributed $269.2 million in cash to TGGT and we received those funds from TGGT as a special distribution at closing. EXCO Operating now owns 50% of TGGT and an affiliate of BG Group owns 50% of TGGT. The effective date of this transaction was also January 1, 2009. We adopted the equity method of accounting for our interest in TGGT upon its formation. The BG Midstream Transaction resulted in recognition of a gain of $98.3 million.

The total cash proceeds of $996.2 million from the BG Upstream Transaction and the BG Midstream Transaction were used to repay EXCO Operating’s $300.0 million senior unsecured term credit agreement, creation of an evergreen escrow funding account to develop the Haynesville operations, and a working capital contribution to TGGT, with the remainder applied to the outstanding balances under the EXCO Operating credit agreement.

On September 29, 2009, we reached an agreement with EV Energy Partners, L.P., along with certain institutional partnerships managed by EnerVest, Ltd. to sell our Ohio and certain Northwestern Pennsylvania producing assets for $145.0 million, subject to customary purchase price adjustments. The sale is expected to close in November 2009 and is effective as of September 1, 2009.

On September 30, 2009, we reached an agreement with Sheridan Holding Company I, LLC to sell all of our remaining assets in Oklahoma for $540.0 million, subject to customary purchase price adjustments. The sale is expected to close in November 2009 and is effective as of October 1, 2009.

3.	Recent accounting pronouncements

On June 30, 2009, the Financial Accounting Standards Board, or the FASB, issued Update No. 2009-01-Topic 105-Generally Accepted Accounting Principles-amendments based on-Statement of Financial Accounting Standards No. 168-The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or ASU 2009-01. ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. ASU 2009-01 superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification became nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009.

On June 12, 2009, the FASB issued FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R),” or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of September 30, 2009, we do not have any variable interest entities and as such, the final rule will not have an effect on our financial statements and disclosures.

transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

On May 28, 2009, the FASB issued FASB Accounting Standards Codification, or ASC Subtopic 855-10 for Subsequent Events. ASC 855-10 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. ASC 855-10 is effective for interim and annual periods ending after June 15, 2009.

On April 9, 2009, the FASB issued FASB ASC paragraph 820-10-65-4 for Fair Value Measurements and Disclosures. ASC 820-10-65-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. ASC 820-10-65-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph FASB ASU Section 320-10-50 for the Scope Section of Subtopic 305-10 for Investments – Debt and Equity Securities. ASC 820-10-65-4 is effective for interim periods ending after June 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 9, 2009, the FASB issued FASB ASC Section 825-10-65 for Derivatives and Hedging. ASC 825-10-65 amended Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. ASC 825-10-65 also amends APB Opinion No. 28, “Interim Financial Reporting,” to require fair value disclosures in summarized financial information at interim reporting periods. ASC 825-10-65 was effective for interim periods ending after June 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 1, 2009, the FASB issued FASB ASC Subtopic 805-20 for Business Combinations. ASC 805-20 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business Combinations,” to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted ASC 805-20 on January 1, 2009.

In March 2008, the FASB issued FASB ASC Section 815-10-65 for Derivatives and Hedging. ASC 815-10-65 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. ASC 815-10-65 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

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

•

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

•

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

•

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

•

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

•

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

•

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

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

4.	Significant accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in our Annual Report on Form 10-K for the year ended December 31, 2008.

In addition, as a result of our 50% ownership interest in TGGT, we have adopted the equity method of accounting. See “Note 13. Equity investment.”

5.	Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, 2009:


(in thousands)
Asset retirement obligation at January 1, 2009	$	120,671
Activity during the nine months ended September 30, 2009:
Liabilities incurred during the period		721
Liabilities settled during the period		(2,696	)
Reduction to retirement obligations due to divestitures		(23,513	)
Accretion of discount		5,856

Asset retirement obligations at September 30, 2009		101,039
Less current portion		16

Long-term portion	$	101,023

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 requires that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs, which totaled $246.3 million and $481.6 million as of September 30, 2009 and December 31, 2008, respectively, are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to the depletable full cost pool as a result of extensions or discoveries from drilling operations. We expect these costs to be evaluated in one to ten years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties and all estimated future development costs related to Proved Reserves is divided by the total quantities of Proved Reserves to determine the unit amortization rate. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, which is attributable to our acquisition, exploration, exploitation and development activities.

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves. Our BG Upstream Transaction, East Texas Transaction and Mid-Continent Transaction divestiture transactions were considered significant and we recognized gains on these sales of $362.3 million.

At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our Proved Reserves using current period-end prices, discounted at 10%, and adjusted for related income tax effects (ceiling test). When computing our ceiling test, we evaluate the limitation at the end of each reporting period. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting period, we subsequently evaluate the limitation based on price changes that occur after the balance sheet date to assess impairment as currently permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results.

We recognized a ceiling test write-down of $1.3 billion for the nine months ended September 30, 2009 to our proved oil and natural gas properties. For the three months ended September 30, 2009, we would have incurred an after-tax ceiling test write-down of $43.5 million. However, subsequent price increases for natural gas eliminated the need for a write-down. For the three and nine months ended September 30, 2008, we recognized a ceiling test write-down of $1.2 billion to our proved oil and natural gas properties.

Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. On September 30, 2009, the spot price for natural gas at Henry Hub was $3.30 per Mmbtu and the spot oil price at Cushing, Oklahoma was $70.43 per Bbl. On September 30, 2008, the spot price for natural gas at Henry Hub was $7.12 per Mmbtu and the spot oil price at Cushing, Oklahoma was $100.67 per Bbl. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. There can be no assurance that basis premiums in Appalachia will continue. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance.

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

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 nine months ended September 30, 2009 and 2008 equals the net income (loss) available to common shareholders divided by the weighted average common shares outstanding during the period. Diluted earnings (loss) per common share for the three and nine months ended September 30, 2009 and 2008 is computed in the same manner as basic earnings (loss) per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, including our preferred stock outstanding during the first half of 2008, whether exercisable or not. Since we incurred net losses for the nine months ended September 30, 2009 and the three and nine months ended September 30, 2008, we have excluded the potential common stock equivalents from the assumed exercise of stock options of 14,677,233 for the nine months ended September 30, 2009, and 12,353,376 and 12,387,593 for the three and nine months ended September 30, 2008, respectively, as they were antidilutive. We have also excluded 19,439,891 and 76,336,899 shares of common stock equivalents from the assumed conversion of the preferred stock from the computation of loss per share for the three and nine months ended September 30, 2008, respectively, as they were antidilutive. As a result of the preferred stock converting to common stock during the third quarter of 2008, there was no impact to 2009.

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


	Three months ended September 30,					Nine months ended September 30,
(in thousands, except per share amounts)	2009		2008			2009			2008
Basic income (loss) per common share:
Net income (loss)	$	433,330	$	(146,329	)	$	(738,273	)	$	(572,082	)
Preferred stock dividends		—		6,997			—			76,997

Net income (loss) available to common shareholders	$	433,330	$	(153,326	)	$	(738,273	)	$	(649,079	)

Shares:
Weighted average number of common shares outstanding		211,266		191,452			211,118			134,006

Basic income (loss) per common share:
Net income (loss) available to common shareholders per common share	$	2.05	$	(0.80	)	$	(3.50	)	$	(4.84	)

Diluted income (loss) per share:
Net income (loss) available to common shareholders	$	433,330	$	(153,326	)	$	(738,273	)	$	(649,079	)

Shares:
Weighted average number of common shares outstanding		211,266		191,452			211,118			134,006
Dilutive effect of stock options		1,969		—			—			—

Weighted average common shares and common stock equivalent shares outstanding		213,235		191,452			211,118			134,006

Diluted income (loss) per share:
Net income (loss) available to common shareholders per common share	$	2.03	$	(0.80	)	$	(3.50	)	$	(4.84	)

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 daily closing prices from five comparable public companies during the period when we were privately held. Total share-based compensation to be recognized on unvested awards as of September 30, 2009 is $18.5 million over a weighted average period of 0.91 years.

The following is a reconciliation of our stock option expense for the three and nine months ended September 30, 2009 and 2008:


	Three months ended September 30,				Nine months ended September 30,
	2009		2008		2009		2008
General and administrative expense	$	2,764	$	2,985	$	7,865	$	7,553

Lease operating expense		619		1,169		1,998		3,289


Total share-based compensation expense		3,383		4,154		9,863		10,842

Share-based compensation capitalized		942		987		2,122		2,263


Total share-based compensation	$	4,325	$	5,141	$	11,985	$	13,105

During the nine months ended September 30, 2009, options to purchase 317,600 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. During the nine months ended September 30, 2008, options to purchase 1,360,600 shares were granted under the 2005 Incentive Plan at prices ranging from $15.15 to $38.01 per share with fair values ranging from $5.39 to $14.27 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. On June 4, 2009, our shareholders approved an amendment to the 2005 Incentive Plan to increase the number of shares authorized for issuance by an additional 3,000,000 shares. The number of shares available to be granted under the 2005 Incentive Plan as of September 30, 2009 was 6,612,175 shares. At December 31, 2008, there were 3,342,450 shares available to be granted under the 2005 Incentive Plan.

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	September 30, 2009			December 31, 2008
Commodity contracts	Derivative financial instruments - Current assets	$	203,641		$	247,614
Commodity contracts	Derivative financial instruments - Long-term assets		85,943			173,003
Commodity contracts	Derivative financial instruments - Current liabilities		(8,144	)		(2,734	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(24,386	)		(11,585	)
Interest rate contracts	Derivative financial instruments - Current liabilities		(5,628	)		(8,873	)
Interest rate contracts	Derivative financial instruments - Long-term liabilities		—			(1,005	)

Net derivatives		$	251,426		$	396,420

The Effect of Derivative Financial Instruments


		Three months ended September 30,						Nine months ended September 30,
(in thousands)	Statement of Operations location	2009			2008			2009			2008
Commodity contracts (1)	Gain (loss) on derivative financial instruments	$	14,518		$	900,313		$	204,885		$	(103,534	)
Interest rate contracts (2)	Interest (expense) income		(3,304	)		(2,052	)		(3,785	)		6,079

Net gain (loss)		$	11,214		$	898,261		$	201,100		$	(97,455	)

(1)	Included in these amounts are cash settlements, including net cash receipts of $113,563 and $354,131 for the three and nine months ended September 30, 2009, respectively, and net cash payments of $70,019 and $157,383 for the three and nine months ended September 30, 2008, respectively.

(2)	Included in these amounts are cash settlements, including net cash payments of $3,550 and $8,036 for the three and nine months ended September 30, 2009, respectively, and net cash receipts of $163 and $924 for the three and nine months ended September 30, 2008, respectively.

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from or cash disbursement to our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Unrealized fair value adjustments included in Gain (loss) on derivative financial instruments on the Condensed Consolidated Statements of Operations, which do not impact cash flows, were a loss of $99.0 million and a gain of $970.3 million for the three months ended September 30, 2009 and 2008, respectively, and were a loss of $149.2 million and a gain of $53.9 million for the nine months ended September 30, 2009 and 2008, respectively. Unrealized fair value adjustments included in Interest expense on the Condensed Consolidated Statements of Operations, which do not impact cash flows, were a gain of $0.2 million and a loss of $2.2 million for the three months ended September 30, 2009 and 2008, respectively, and were gains of $4.3 million and $5.2 million for the nine months ended September 30, 2009 and 2008, respectively.

We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. As of September 30, 2009 and December 31, 2008, we had a net asset position of $251.4 million and $396.4 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 for the nine months ended September 30, 2009 and the year ended December 31, 2008:


	For the nine months ended September 30, 2009
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	257,054		$	—	$	257,054
Interest rate swaps		—		(5,628	)		—		(5,628	)

	$	—	$	251,426		$	—	$	251,426


	For the year ended December 31, 2008
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	406,298		$	—	$	406,298
Interest rate swaps		—		(9,878	)		—		(9,878	)

	$	—	$	396,420		$	—	$	396,420

In accordance with FASB 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, in part by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

Oil and natural gas derivatives

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

Appalachia derivatives. In connection with our September 29, 2009 sales agreement with EnerVest, we entered into Appalachian basin swaps, natural gas collars and basis swaps on behalf of EnerVest. Pursuant to the sales agreement, EXCO has certain rights, which eliminate our exposure to gains or losses on these derivative financial instruments in the event the transaction does not close.

The following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value as of September 30, 2009:


(in thousands, except prices)	Volume Mmbtu/Bbl	Floor and ceiling, weighted average strike price			Fair value at September 30, 2009
Natural gas:
Remainder of 2009	23,450	$	8.08		$	77,469
2010	66,298		7.62			92,472
2011	12,775		7.48			7,691
2012	5,490		5.91			(5,524	)
2013	5,475		5.99			(5,256	)

Total natural gas	113,488					166,852


Basis swaps:
Remainder of 2009	920		(1.10	)		(773	)

Total basis swaps	920					(773	)


Oil:
Remainder of 2009	398		80.66			3,780
2010	1,568		104.64			46,723
2011	1,095		112.99			37,876
2012	92		109.30			2,596

Total oil	3,153					90,975


Total oil and natural gas derivatives					$	257,054

At December 31, 2008, we had outstanding derivative contracts to mitigate price volatility covering 168,658 Mmcf of natural gas and 4,335 Mbbls of oil. At September 30, 2009, the average forward NYMEX natural gas price per Mmbtu for the remainder of 2009 and for 2010 were $4.75 and $6.21, respectively, and the average forward NYMEX oil prices per Bbl for the remainder of 2009 and for 2010 were $71.08 and $74.38, respectively.

Our derivative financial instruments used to mitigate price volatility covered 80.9% and 76.8% of our total equivalent Mcfe production for the three and nine months ended September 30, 2009, respectively, and 80.0% and 79.7% of our total equivalent Mcfe production for the three and nine months ended September 30, 2008, respectively.

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at 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 have classified our interest rate swaps and their related fair value tier as Level 2.

During the three and nine months ended September 30, 2009, we recognized increases of $3.3 million and $3.8 million, respectively, in interest expense related to our interest rate swaps. For the three and nine months ended September 30, 2008, we recognized an increase of $2.1 million and a decrease of $6.1 million, respectively, in interest expense related to our interest rate swaps. As of September 30, 2009 and December 31, 2008, the fair value of our interest rate swaps was a liability of $5.6 million and $9.9 million, respectively.

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 7¹/4% senior notes due January 15, 2011, or Senior Notes, is $442.5 million with a carrying amount of $449.6 million as of September 30, 2009. 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)	September 30, 2009		December 31, 2008
EXCO Resources Credit Agreement	$	751,430	$	1,048,951
EXCO Operating Credit Agreement		488,215		1,218,485
Term Credit Agreement		—		300,000
7¹/4% senior notes due 2011		444,720		444,720
Unamortized premium on 7¹/4% senior notes due 2011		4,912		7,582

Total debt		1,689,277		3,019,738
Less current maturities		—		—

Total long term debt	$	1,689,277	$	3,019,738

Credit agreements

EXCO Resources credit agreement

The EXCO Resources credit agreement, as amended, or the EXCO Resources Credit Agreement, currently has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At September 30, 2009, we had $751.4 million of outstanding indebtedness under the EXCO Resources Credit Agreement. As of October 2, 2009, after the borrowing base redetermination discussed below, the available borrowing capacity was $83.4 million, net of outstanding letters of credit. The borrowing base is redetermined semi-annually, with EXCO and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO may have in place derivative financial instruments covering no more than 80% of its forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have in place mortgages covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012.

On October 2, 2009, we entered into a fifth amendment to the EXCO Resources Credit Agreement which, among other things, modified the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the fifth 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 borrowing base availability under the EXCO Resources Credit Agreement and (iii) payment of such dividend is permitted under EXCO’s 7¹/4% Senior Notes Indenture.

Also on October 2, 2009, the lenders agreed to consents which (i) established the borrowing base under the EXCO Resources Credit Agreement at $850.0 million, (ii) approved the proposed sale of certain Appalachia properties and extended the deadline for consummation of the sale transaction to November 30, 2009, (iii) set the estimated loan value for the Appalachia properties proposed sale at $100.0 million with reduction in the borrowing base effective with the closing of such transaction and (iv) permit EXCO to receive non-cash consideration from the proposed sale of the Appalachia properties in an amount not to exceed 5.0% of the value of total sales consideration received from such sale. In addition to the Appalachia properties, the lenders assigned a $300.0 million loan value to certain Mid-Continent properties which are being sold and provided for requirements to unwind certain hedges under the EXCO Resources Credit Agreement in connection with the pending sales.

The interest rate ranges from LIBOR plus 175 basis points, or bps, to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. At September 30, 2009, the one month LIBOR was 0.25%, which would result in an interest rate of approximately 2.5% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

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

•

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

•

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

•

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

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

EXCO Operating credit agreement

The EXCO Operating credit agreement, as amended, or the EXCO Operating Credit Agreement, currently has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At September 30, 2009, we had $488.2 million of outstanding indebtedness and $361.8 million of available borrowing capacity under the EXCO Operating Credit Agreement. The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may have in place derivative financial instruments covering no more than 80% of the forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012.

On October 16, 2009, the lenders agreed to consents which (i) confirmed the borrowing base under the EXCO Operating Credit Agreement at $850.0 million until the next borrowing base redetermination date, (ii) provide for EXCO Operating to grant to lenders a first priority lien and security interest in all of its equity interest in TGGT, representing EXCO Operating’s 50% interest in the midstream assets contributed in connection with the BG Midstream Transaction and (iii) by November 30, 2009, consummate transactions to unwind oil and natural gas derivatives with respect to notional volumes of oil and natural gas with respect to sold production volumes which had been waived under a consent granted on July 29, 2009.

The interest rate ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending on borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps, depending upon borrowing base usage. At September 30, 2009, the one month LIBOR was 0.25%, which would result in an interest rate of approximately 2.25% on any new indebtedness we may incur under the EXCO Operating Credit Agreement.

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

•

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

•

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

•

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

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

Term credit agreement

On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, with an aggregate balance of $300.0 million. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating provided for additional fees on unpaid principal amounts, or duration fees, as defined in the agreement. These included a 5% fee on the unpaid principal on June 15, 2009 and an additional 3% fee on any unpaid outstanding balance as of September 15, 2009. On June 15, 2009 we remitted the first duration fee payment of $15.0 million.

In connection with the closings of the BG Upstream Transaction, the BG Midstream Transaction and the East Texas Transaction, EXCO Operating repaid the outstanding $300.0 million under the Term Credit Agreement. As a consequence of the early payment of the Term Credit Agreement, EXCO Operating avoided payment of a $9.0 million duration fee that would have been due on September 15, 2009.

The unamortized balance of deferred financing costs attributable to the Term Credit Agreement of approximately $11.6 million was written off and is included in interest expense in the quarter ended September 30, 2009.

7¹/4% Senior Notes due January 15, 2011

As of September 30, 2009 and December 31, 2008, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at September 30, 2009 and December 31, 2008 was $4.9 million and $7.6 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $442.5 million on September 30, 2009. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.

11.

Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws. We apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial operating losses primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties. As a result of these cumulative financial operating losses, we have provided valuation allowances of approximately $825.6 million until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowance does not impact future utilization of the underlying tax attributes.

12.

Operating segments

We follow FASB ASC Topic 280 for Segment Reporting when reporting operating segments. Prior to the August 14, 2009 sale of a 50% interest in our midstream investment, as discussed below and in “Note 2. Significant recent activities,” our reportable segments consisted of exploration and production and midstream. Our exploration and production operational segment and midstream segment were managed separately because of the nature of their products and services. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment was responsible for purchasing, gathering, transporting, processing and treating natural gas. We evaluated the performance of our operating segments based on segment profits, which included segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and segment costs and expenses. Segment profit generally excluded income taxes, interest income, interest expense, unallocated corporate expenses, depreciation and depletion, asset retirement obligations, and gains and losses associated with ceiling test write-downs and asset sales, other income and expense, and income from equity investments.

As discussed in “Note 2. Significant recent activities,” on August 14, 2009 we closed the BG Midstream Transaction and contributed TGG and Talco to TGGT. We received net sales proceeds of $269.2 million at closing, including preliminary closing adjustments. We own 50% of TGGT and now account for our interest using the equity method (see “Note 13. Equity investment”).

As a result of this sale, 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.

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


(in thousands)	Exploration and production			Midstream		Intercompany eliminations			Consolidated total
For the three months ended September 30, 2009:
Third party revenues	$	125,493		$	5,375	$	—		$	130,868
Intersegment revenues		(4,324	)		8,896		(4,572	)		—

Total revenues	$	121,169		$	14,271	$	(4,572	)	$	130,868


Segment profit	$	73,216		$	4,288	$	—		$	77,504


For the three months ended September 30, 2008:
Third party revenues	$	402,407		$	27,004	$	—		$	429,411
Intersegment revenues		(9,664	)		22,254		(12,590	)		—

Total revenues	$	392,743		$	49,258	$	(12,590	)	$	429,411


Segment profit	$	326,069		$	7,848	$	—		$	333,917


For the nine months ended September 30, 2009:
Third party revenues	$	443,953		$	35,330	$	—		$	479,283
Intersegment revenues		(20,356	)		41,148		(20,792	)		—

Total revenues	$	423,597		$	76,478	$	(20,792	)	$	479,283


Segment profit	$	266,180		$	20,106	$	—		$	286,286


For the nine months ended September 30, 2008:
Third party revenues	$	1,155,986		$	61,852	$	—		$	1,217,838
Intersegment revenues		(24,734	)		44,063		(19,329	)		—

Total revenues	$	1,131,252		$	105,915	$	(19,329	)	$	1,217,838


Segment profit	$	943,223		$	26,915	$	—		$	970,138


As of September 30, 2009:
Total assets	$	2,631,496		$	—	$	—		$	2,631,496


As of December 31, 2008:
Total assets	$	4,392,218		$	430,134	$	—		$	4,822,352

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


	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2009			2008			2009			2008
Segment profits	$	77,504		$	333,917		$	286,286		$	970,138
Depreciation, depletion and amortization		(50,709	)		(126,207	)		(187,683	)		(346,705	)
Write-down of oil and natural gas properties		—			(1,193,105	)		(1,293,579	)		(1,193,105	)
Gain on divestitures		460,626			—			460,626			—
Accretion of discount on asset retirement obligations		(1,767	)		(1,482	)		(5,856	)		(4,271	)
General and administrative		(21,647	)		(21,002	)		(64,682	)		(63,286	)
Interest expense		(46,737	)		(44,874	)		(129,760	)		(101,167	)
Gain (loss) on derivative financial instruments		14,518			900,313			204,885			(103,534	)
Other income (loss)		47			1,820			(7,895	)		5,496
Equity method loss on TGGT Holdings, LLC		(426	)		—			(426	)		—

Income (loss) before income taxes	$	431,409		$	(150,620	)	$	(738,084	)	$	(836,434	)

13.

Equity investment

In connection with the sale of 50% of our interest in our midstream assets to BG Group, as discussed in “Note 2. Significant recent activities” and “Note 12. Operating segments,” TGGT now holds substantially all of our East Texas/North Louisiana midstream assets. Our 50% ownership interest in TGGT is accounted for under the equity method. As a result, the midstream assets were recorded as an investment in TGGT at our historical cost of $158.1 million plus a $20.0 million working capital contribution upon TGGT’s formation. In September 2009, we made an additional $27.5 million working capital contribution to TGGT to fund its expansion of gathering and treating facilities.

At September 30, 2009, our equity investment in TGGT exceeded our book value of assets by $44.1 million, of which $55.5 million represents the difference in the historical basis of our contribution and the fair value of BG Group’s contribution. The $55.5 million is being amortized over the life of the underlying assets, offset by $11.4 million of goodwill included in our investment.

The following table presents summarized financial information of TGGT:


(in thousands)	As of September 30, 2009
Assets
Total current assets		120,035
Property and equipment, net		438,137

Total assets	$	558,172

Liabilities and members’ equity
Total current liabilities		36,640
Members’ equity:
Total members’ equity		521,532

Total liabilities and members’ equity	$	558,172


	For the 48 day period from August 14, 2009 to September 30, 2009
Revenues
Gas sales	$	5,304
Condensate, shrinkage and loss revenues		1,288
Gathering, compression and other services		3,087

Total revenues		9,679

Costs and expenses:
Gas purchases		5,495
Operating expenses		2,784
Depreciation expense		1,524
Other operating expenses		728

Total costs and expenses		10,531

Net income (loss)	$	(852	)

EXCO’s equity in TGGT earnings (loss)	$	(426	)

14.

Dividends

On October 1, 2009 our Board of Directors approved the commencement of a dividend program at an initial quarterly cash dividend rate of $0.025 per share of EXCO’s common stock. The first quarterly dividend of $0.025 per share was paid on October 26, 2009 to holders of record on October 12, 2009. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to the approval of EXCO’s Board of Directors.

15.

Subsequent events

We evaluated our activity after September 30, 2009 until the date of issuance, November 4, 2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.

16.

Condensed consolidating financial statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The Senior Notes are jointly and severally guaranteed by some of our subsidiaries (referred to collectively as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of EXCO Resources, or Resources, and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries.

EXCO Operating and its subsidiaries are designated as “Non-Guarantor Subsidiaries” in the accompanying condensed consolidating financial statements. There are no other Non-Guarantor Subsidiaries.

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

•

Resources;

•

the Guarantor Subsidiaries on a combined basis;

•

the Non-Guarantor Subsidiaries;

•

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

•

EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the Guarantor Subsidiaries and 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)

September 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	32,201		$	2,849		$	20,631		$	—		$	55,681
Restricted cash		—			14,500			55,483			—			69,983
Other current assets		136,295			21,048			165,711						323,054

Total current assets		168,496			38,397			241,825			—			448,718

Equity investment in TGGT Holdings, LLC		—			—			216,631			—			216,631
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		60,817			112,185			73,270			—			246,272
Proved developed and undeveloped oil and natural gas properties		579,331			427,928			1,193,656			—			2,200,915
Accumulated depletion		(273,466	)		(168,302	)		(662,133	)		—			(1,103,901	)

Oil and natural gas properties, net		366,682			371,811			604,793			—			1,343,286

Gas gathering, office and field equpment, net		8,901			54,122			134,130			—			197,153
Investments in and advances to affiliates		171,974			—			—			(171,974	)		—
Derivative financial instruments		67,500			—			18,443			—			85,943
Deferred financing costs, net		7,427			—			4,929			—			12,356
Other assets		2			1,050			1,601			—			2,653
Goodwill		93,200			164,469			67,087			—			324,756

Total assets	$	884,182		$	629,849		$	1,289,439		$	(171,974	)	$	2,631,496


Liabilities and shareholders’ equity
Current liabilities	$	54,632		$	34,855		$	91,771		$	—		$	181,258
Long-term debt		1,201,062			—			488,215			—			1,689,277
Deferred income taxes		8,661			—			—			—			8,661
Other liabilities		28,821			82,617			29,199			—			140,637
Payable to parent		(1,020,657	)		975,552			45,105			—			—
Total shareholders’ equity		611,663			(463,175	)		635,149			(171,974	)		611,663

Total liabilities and shareholders’ equity	$	884,182		$	629,849		$	1,289,439		$	(171,974	)	$	2,631,496

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2008


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	8,618		$	12,360		$	36,161		$	—		$	57,139
Other current assets		162,607			29,935			263,359			—			455,901

Total current assets		171,225			42,295			299,520			—			513,040

Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		85,061			119,940			276,595			—			481,596
Proved developed and undeveloped oil and natural gas properties		940,529			673,814			1,964,001			—			3,578,344
Accumulated depletion		(232,261	)		(145,103	)		(558,724	)		—			(936,088	)

Oil and natural gas properties, net		793,329			648,651			1,681,872			—			3,123,852

Gas gathering, office and field equipment, net		8,582			55,404			414,630			—			478,616
Investments in and advances to affiliates		802,902			—			—			(802,902	)		—
Derivative financial instruments		120,097			—			52,906			—			173,003
Deferred financing costs, net		6,414			—			56,470			—			62,884
Other assets		2			678			200			—			880
Goodwill		110,800			164,469			194,808			—			470,077

Total assets	$	2,013,351		$	911,497		$	2,700,406		$	(802,902	)	$	4,822,352


Liabilities and shareholders’ equity
Current liabilities	$	66,871		$	50,256		$	205,746		$	—		$	322,873
Long-term debt		1,501,253			—			1,518,485			—			3,019,738
Deferred income taxes		9,371			—			—			—			9,371
Other liabilities		27,065			78,316			32,488			—			137,869
Payable to parent		(923,710	)		948,463			(24,753	)		—			—
Commitments and contingencies		—			—			—			—			—
Total shareholders’ equity		1,332,501			(165,538	)		968,440			(802,902	)		1,332,501

Total liabilities and shareholders’ equity	$	2,013,351		$	911,497		$	2,700,406		$	(802,902	)	$	4,822,352

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	37,260		$	18,981		$	69,252		$	—		$	125,493
Midstream		—			—			5,375			—			5,375

Total revenues		37,260			18,981			74,627			—			130,868

Costs and expenses:
Oil and natural gas production		10,992			7,987			24,047			—			43,026
Midstream operating expenses		—			—			5,411			—			5,411
Gathering and transportation		—			751			4,176			—			4,927
Depreciation, depletion and amortization		12,819			7,424			30,466			—			50,709
Write-down of oil and natural gas properties		—			—			—			—			—
Gain on divestitures		(98,581	)		—			(362,045	)		—			(460,626	)
Accretion of discount on asset retirement obligations		422			853			492			—			1,767
General and administrative		6,472			1,675			13,500			—			21,647

Total costs and expenses		(67,876	)		18,690			(283,953	)		—			(333,139	)

Operating income		105,136			291			358,580			—			464,007
Other income (expense):
Interest expense		(17,025	)		—			(29,712	)		—			(46,737	)
Gain (loss) on derivative financial instruments		7,053			(548	)		8,013			—			14,518
Other income (expense)		6,809			(5,734	)		(1,028	)		—			47
Equity method loss in TGGT Holdings, LLC		—			—			(426	)		—			(426	)
Equity in earnings of subsidiaries		329,436			—			—			(329,436	)		—

Total other income (expense)		326,273			(6,282	)		(23,153	)		(329,436	)		(32,598	)

Income (loss) before income taxes		431,409			(5,991	)		335,427			(329,436	)		431,409
Income tax expense (benefit)		(1,921	)		—			—			—			(1,921	)

Net income (loss)		433,330			(5,991	)		335,427			(329,436	)		433,330
Preferred stock dividends		—			—			—			—			—

Net income (loss) available to common shareholders	$	433,330		$	(5,991	)	$	335,427		$	(329,436	)	$	433,330

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2008


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	116,326		$	58,473		$	227,608		$	—	$	402,407
Midstream		—			—			27,004			—		27,004

Total revenues		116,326			58,473			254,612			—		429,411

Costs and expenses:
Oil and natural gas production		19,625			9,473			33,904			—		63,002
Midstream operating expenses		—			—			28,820			—		28,820
Gathering and transportation		56			832			2,784			—		3,672
Depreciation, depletion and amortization		39,919			16,856			69,432			—		126,207
Write-down of oil and natural gas properties		198,440			359,350			635,315			—		1,193,105
Accretion of discount on asset retirement obligations		417			723			342			—		1,482
General and administrative		11,688			4,814			4,500			—		21,002

Total costs and expenses		270,145			392,048			775,097			—		1,437,290

Operating income (loss)		(153,819	)		(333,575	)		(520,485	)		—		(1,007,879	)
Other income (expense):
Interest expense		(19,530	)		—			(25,344	)		—		(44,874	)
Gain on derivative financial instruments		385,132			50,456			464,725			—		900,313
Other income (expense)		7,157			(6,217	)		880			—		1,820
Equity in earnings of subsidiaries		(255,828	)		—			—			255,828		—

Total other income (expense)		116,931			44,239			440,261			255,828		857,259

Income (loss) before income taxes		(36,888	)		(289,336	)		(80,224	)		255,828		(150,620	)
Income tax expense (benefit)		109,441			(113,732	)		—			—		(4,291	)

Net income (loss)		(146,329	)		(175,604	)		(80,224	)		255,828		(146,329	)
Preferred stock dividends		(6,997	)		—			—			—		(6,997	)

Net income (loss) available to common shareholders	$	(153,326	)	$	(175,604	)	$	(80,224	)	$	255,828	$	(153,326	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	116,885		$	70,940		$	256,128		$	—	$	443,953
Midstream		—			—			35,330			—		35,330

Total revenues		116,885			70,940			291,458			—		479,283

Costs and expenses:
Oil and natural gas production		38,367			24,726			81,445			—		144,538
Midstream operating expenses		—			—			35,580			—		35,580
Gathering and transportation		87			2,789			10,003			—		12,879
Depreciation, depletion and amortization		43,782			26,962			116,939			—		187,683
Write-down of oil and natural gas properties		279,632			282,073			731,874			—		1,293,579
Gain on divestitures		(98,581	)		—			(362,045	)		—		(460,626	)
Accretion of discount on asset retirement obligations		1,444			2,661			1,751			—		5,856
General and administrative		12,186			11,996			40,500			—		64,682

Total costs and expenses		276,917			351,207			656,047			—		1,284,171

Operating loss		(160,032	)		(280,267	)		(364,589	)		—		(804,888	)
Other income (expense):
Interest expense		(45,161	)		—			(84,599	)		—		(129,760	)
Gain on derivative financial instruments		78,059			6,551			120,275			—		204,885
Other income (expense)		19,977			(23,921	)		(3,951	)		—		(7,895	)
Equity method loss in TGGT Holdings, LLC		—			—			(426	)		—		(426	)
Equity in earnings of subsidiaries		(630,927	)		—			—			630,927		—

Total other income (expense)		(578,052	)		(17,370	)		31,299			630,927		66,804

Income (loss) before income taxes		(738,084	)		(297,637	)		(333,290	)		630,927		(738,084	)
Income tax expense		189			—			—			—		189

Net income (loss)		(738,273	)		(297,637	)		(333,290	)		630,927		(738,273	)
Preferred stock dividends		—			—			—			—		—

Net income (loss) available to common shareholders	$	(738,273	)	$	(297,637	)	$	(333,290	)	$	630,927	$	(738,273	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2008


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	336,290		$	167,819		$	651,877		$	—	$	1,155,986
Midstream		—			—			61,852			—		61,852

Total revenues		336,290			167,819			713,729			—		1,217,838

Costs and expenses:
Oil and natural gas production		57,734			26,653			93,139			—		177,526
Midstream operating expenses		—			—			59,671			—		59,671
Gathering and transportation		173			2,246			8,084			—		10,503
Depreciation, depletion and amortization		91,456			48,966			206,283			—		346,705
Write-down of oil and natural gas properties		198,440			359,350			635,315			—		1,193,105
Accretion of discount on asset retirement obligations		1,232			2,014			1,025			—		4,271
General and administrative		36,543			13,243			13,500			—		63,286

Total costs and expenses		385,578			452,472			1,017,017			—		1,855,067

Operating loss		(49,288	)		(284,653	)		(303,288	)		—		(637,229	)
Other income (expense):
Interest expense		(51,525	)		—			(49,642	)		—		(101,167	)
Gain (loss) on derivative financial instruments		(28,618	)		(9,478	)		(65,438	)		—		(103,534	)
Other income (expense)		22,294			(18,865	)		2,067			—		5,496
Equity in earnings of subsidiaries		(606,593	)		—			—			606,593		—

Total other income (expense)		(664,442	)		(28,343	)		(113,013	)		606,593		(199,205	)

Income (loss) before income taxes		(713,730	)		(312,996	)		(416,301	)		606,593		(836,434	)
Income tax expense (benefit)		(141,648	)		(122,704	)		—			—		(264,352	)

Net income (loss)		(572,082	)		(190,292	)		(416,301	)		606,593		(572,082	)
Preferred stock dividends		(76,997	)		—			—			—		(76,997	)

Net income (loss) available to common shareholders	$	(649,079	)	$	(190,292	)	$	(416,301	)	$	606,593	$	(649,079	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2009


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	165,582		$	10,649		$	173,626		$	—	$	349,857

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(40,053	)		(44,402	)		(372,178	)		—		(456,633	)

Restricted cash		—			(14,500	)		(55,483	)		—		(69,983	)
Equity investment in TGGT Holdings, LLC		—			—			(47,500	)		—		(47,500	)
Deposit on pending property divestitures		—			14,500			—			—		14,500
Net proceeds from dispositions		262,808			(46	)		1,146,616			—		1,409,378
Advances/investments with affiliates		(113,107	)		24,287			88,820			—		—

Net cash provided by (used in) investing activities		109,648			(20,161	)		760,275			—		849,762

Financing Activities:
Borrowings under credit agreements		14,979			—			37,970			—		52,949
Repayments under credit agreements		(312,500	)		—			(768,240	)		—		(1,080,740	)
Repayments under senior unsecured credit term agreement		—			—			(300,000	)		—		(300,000	)
Proceeds from issuance of common stock, net		5,400			—			—			—		5,400
Settlement of derivative financial instruments with a financing element		45,859			—			95,923			—		141,782
Deferred financing costs and other		(5,386	)		—			(15,082	)		—		(20,468	)

Net cash used in financing activities		(251,648	)		—			(949,429	)		—		(1,201,077	)

Net increase (decrease) in cash		23,582			(9,512	)		(15,528	)		—		(1,458	)
Cash at the beginning of the period		8,617			12,360			36,162			—		57,139

Cash at end of period	$	32,199		$	2,848		$	20,634		$	—	$	55,681

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2008


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	219,779		$	89,856		$	502,382		$	—	$	812,017

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(160,259	)		(156,431	)		(424,964	)		—		(741,654	)
Property and midstream acquisitions		(400,660	)		(437	)		(344,122	)		—		(745,219	)
Advance on pending acquisition		—			—			—			—		—
Proceeds from dispositions of property and equipment		1,288			282			166			—		1,736
Advances/investments with affiliates		3,179			64,439			(67,618	)		—		—

Net cash used in investing activities		(556,452	)		(92,147	)		(836,538	)		—		(1,485,137	)

Financing Activities:
Borrowings under credit agreements		750,000			—			315,185			—		1,065,185
Repayments under credit agreements		(296,500	)		—			(179,700	)		—		(476,200	)
Borrowings under senior unsecured credit term agreement		—			—			300,000			—		300,000
Proceeds from issuance of common stock		14,465			—			—			—		14,465
Payment of preferred stock dividends		(82,827	)		—			—			—		(82,827	)
Settlements of derivative financial instruments with a financing element		(51,399	)		—			(45,105	)		—		(96,504	)
Deferred financing costs		(707	)		—			(10,667	)				(11,374	)

Net cash provided by financing activities		333,032			—			379,713			—		712,745

Net increase (decrease) in cash		(3,641	)		(2,291	)		45,557			—		39,625
Cash at beginning of the period		23,069			7,250			25,191			—		55,510

Cash at end of period	$	19,428		$	4,959		$	70,748		$	—	$	95,135

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 Haynesville/Bossier shale play in East Texas/North Louisiana and the Marcellus and Huron shale plays in Appalachia;

•

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;

•

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

•

decisions whether or not to enter into derivative financial instruments;

•

events similar to those of September 11, 2001;

•

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

•

fluctuations in interest rates; and

•

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

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2008.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, we hold a 50% equity interest in a joint venture which owns gathering systems and pipelines in East Texas and North Louisiana. Our assets in East Texas and North Louisiana, including our equity interest in midstream operations, are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries, collectively, EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt.

We currently have two credit agreements: one at EXCO Resources, or the EXCO Resources Credit Agreement, which currently has a borrowing base of $850.0 million and one at EXCO Operating, or the EXCO Operating Credit Agreement, which currently has a borrowing base of $850.0 million. We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and exploitation projects and entering into beneficial joint development agreements. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. We also have an asset divestiture program to supplement our development programs and enhance concentration on core operating areas, particularly the Haynesville and Marcellus shale resource plays. 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.

Oil and natural gas prices have historically been volatile. On September 30, 2009, the spot market price for natural gas at Henry Hub was $3.30 per Mmbtu, a 53.7% decrease from September 30, 2008. The price of oil has also shown significant volatility, with a $70.43 per Bbl spot market price for oil at Cushing, Oklahoma at September 30, 2009, a 30.0% decrease from September 30, 2008. During the nine months ended September 30, 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $50.89 per Bbl and $3.88 per Mcf, respectively, compared with the nine months ended September 30, 2008 average realized prices of $111.66 per Bbl and $9.96 per Mcf, respectively. It is impossible to predict the duration or outcome of these price declines, their long-term impact on drilling and operating costs and their impacts, whether favorable or unfavorable, to our results of operations and liquidity.

Like other 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 adding additional reserves through acquisitions.

At the end of the first quarter of 2009, we revised our expected capital expenditure estimate to approximately $500.0 million in response to price declines which affected our vertical drilling economics. We do not budget for acquisitions as these transactions are opportunistic in nature. Presently, our focus is on drilling and leasing activities in our Haynesville shale area in East Texas/North Louisiana. We expect our capital expenditures for 2009 will be approximately $535 million. If the estimated purchase price adjustment for capital expenditures since the effective date of the transactions with BG Group, plc, or BG Group, is considered, our 2009 capital expenditures would be approximately $400 million. Our future growth will depend upon our ability to continue to identify and add oil and natural gas reserves in excess of production at a reasonable cost. We plan to maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

In line with management’s divestiture goals established in the fourth quarter of 2008, we have completed the sale of certain assets, including our joint venture transactions with BG Group, resulting in net cash proceeds of approximately $1.4 billion after customary closing and post closing adjustments during the nine months ended September 30, 2009. We have reached agreements to close asset sales in the fourth quarter of 2009 for total proceeds of approximately $685.0 million, subject to customary closing adjustments.

On August 11, 2009, we closed a sale of properties located in East Texas, or the East Texas Transaction, to an affiliate of Encore Acquisition Company, or Encore. Pursuant to the East Texas Transaction, we sold all of our interests in certain oil and natural gas properties located in our Overton Field and Gladewater area of East Texas. We received $156.7 million in cash at closing, including customary preliminary closing adjustments.

The proceeds from the East Texas Transaction and the Mid-Continent Transaction were used to pay down a portion of our revolving credit agreements.

On August 14, 2009, we closed a sale and joint development transaction with BG Group for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which included most of our oil and natural gas assets in East Texas and North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), or the BG Upstream Transaction. The transaction with BG Group includes agreements for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We received $727.0 million in cash at closing, including customary preliminary closing adjustments. Pursuant to this transaction, BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, BG Group funding of the $400.0 million commitment will be earned solely through drilling of deep right wells as defined in the agreement. There is no obligation by us to repay any of the $400.0 million commitment to BG Group. The joint development transaction had an effective date of January 1, 2009.

The transactions with Encore and BG Group caused a significant alteration to our full cost pool and a gain of $362.3 million was recorded as a result of these transactions.

In addition, on August 14, 2009, we also closed a sale to an affiliate of BG Group of a 50% interest in a newly formed company, TGGT Holdings, LLC, or TGGT, which now holds most of our East Texas/North Louisiana midstream assets, or the BG Midstream Transaction. Our Vernon Field midstream assets were excluded from the BG Midstream Transaction. Pursuant to the contribution agreement, we contributed TGG Pipeline, Ltd., or TGG, which owns intrastate pipelines in East Texas and North

Louisiana, and Talco Midstream Assets, Ltd., or Talco, which owns gathering assets in East Texas and North Louisiana, to TGGT. BG Group contributed $269.2 million in cash to TGGT and we received a special distribution from TGGT of the same amount at closing. EXCO Operating now owns 50% of TGGT and the affiliate of BG Group owns 50% of TGGT. We adopted the equity method of accounting for our interest in TGGT upon formation. The BG Midstream Transaction resulted in recognition of a gain of $98.3 million.

The total aggregate cash proceeds of $996.2 million from the BG Upstream Transaction and the BG Midstream Transaction were used to repay EXCO Operating’s $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, creation of an evergreen escrow funding account to develop the Haynesville operations, and a working capital contribution to TGGT, with the remainder applied to the outstanding balances under the EXCO Operating credit agreement.

On September 29, 2009 we reached an agreement with EV Energy Partners, L.P., along with certain institutional partnerships managed by EnerVest, Ltd., or EnerVest, to sell our Ohio and certain Northwestern Pennsylvania producing assets for $145.0 million, subject to customary purchase price adjustments. The sale is expected to close in November 2009 and is effective as of September 1, 2009.

On September 30, 2009 we reached an agreement with Sheridan Holding Company I, LLC to sell all of our remaining assets in Oklahoma for $540.0 million. The sale is expected to close in November 2009, after customary closing adjustments, and is effective as of October 1, 2009.

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, accounting for income taxes, and our equity investment as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2008, except for the policy related to our equity investment, which is addressed “Note 13. Equity investment” in our Notes to the Condensed Consolidated Financial Statements.

Recent accounting pronouncements

On June 30, 2009, the Financial Accounting Standards Board, or the FASB, issued Update No. 2009-01-Topic 105-Generally Accepted Accounting Principles-amendments based on-Statement of Financial Accounting Standards No. 168-The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or ASU 2009-01. ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date ASU 2009-01 the Codification superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009.

On June 12, 2009, the FASB issued FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R),” or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of September 30, 2009, we do not have any variable interest entities and as such, the final rule does not have an effect on our financial statements and disclosures.

On June 12, 2009, the FASB issued FASB Statement No. 166, “Accounting for Transfers of Financial Assets,” or SFAS No. 166. SFAS No. 166 is a revision to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

On April 9, 2009, the FASB issued FASB ASC paragraph 820-10-65-4 for Fair Value Measurements and Disclosures. ASC 820-10-65-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. ASC 820-10-65-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph FASB ASU Section 320-10-50 for the Scope Section of Subtopic 305-10 for Investments – Debt and Equity Securities. ASC 820-10-65-4 is effective for interim periods ending after June 15, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 9, 2009, the FASB issued FASB ASC Section 825-10-65 for Derivatives and Hedging. ASC 825-10-65 amended Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. ASC 825-10-65 also amends APB Opinion No. 28, “Interim Financial Reporting” to require fair value disclosures in summarized financial information at interim reporting periods. ASC 825-10-65 was effective for interim periods ending after June 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

•

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

•

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

•

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

•

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

Our results of operations

A summary of key financial data for the three and nine months ended September 30, 2009 and 2008 related to our results of operations is presented below:


	Three months ended September 30,						Quarter change			Nine months ended September 30,						Year to date change
(dollars in thousands, except per unit prices)	2009			2008			2009-2008			2009			2008			2009-2008
Production:
Oil (Mbbls)		355			590			(235	)		1,367			1,643			(276	)
Natural gas (Mmcf)		29,806			33,017			(3,211	)		96,598			97,687			(1,089	)
Total production (Mmcfe) (1)		31,936			36,557			(4,621	)		104,800			107,545			(2,745	)
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	22,678		$	68,456		$	(45,778	)	$	69,571		$	183,454		$	(113,883	)
Natural gas		102,815			333,951			(231,136	)		374,382			972,532			(598,150	)

Total oil and natural gas	$	125,493		$	402,407		$	(276,914	)	$	443,953		$	1,155,986		$	(712,033	)

Midstream operations: (2)
Midstream revenues (before intersegment eliminations)	$	14,271		$	49,258		$	(34,987	)	$	76,478		$	105,915		$	(29,437	)
Midstream operating expenses (before intersegment eliminations)		9,983			41,410			(31,427	)		56,372			79,000			(22,628	)

Midstream operating profit (before intersegment eliminations)		4,288			7,848			(3,560	)		20,106			26,915			(6,809	)
Intersegment eliminations		(4,324	)		(9,664	)		5,340			(20,356	)		(24,734	)		4,378

Midstream operating income (loss) (after intersegment eliminations)	$	(36	)	$	(1,816	)	$	1,780		$	(250	)	$	2,181		$	(2,431	)

Oil and natural gas derivative financial instruments:
Cash settlements (payments) on derivative financial instruments	$	113,563		$	(70,019	)	$	183,582		$	354,131		$	(157,383	)	$	511,514
Non-cash change in fair value of derivative financial instruments		(99,045	)		970,332			(1,069,377	)		(149,246	)		53,849			(203,095	)

Total derivative financial instrument activities	$	14,518		$	900,313		$	(885,795	)	$	204,885		$	(103,534	)	$	308,419

Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	63.88		$	116.03		$	(52.15	)	$	50.89		$	111.66		$	(60.77	)
Natural gas (per Mcf)		3.45			10.11			(6.66	)		3.88			9.96			(6.08	)
Natural gas equivalent (per Mcfe)		3.93			11.01			(7.08	)		4.24			10.75			(6.51	)
Costs and expenses:
Oil and natural gas operating costs (3)	$	32,374		$	42,313		$	(9,939	)	$	112,092		$	116,094		$	(4,002	)
Production and ad valorem taxes		10,652			20,689			(10,037	)		32,446			61,432			(28,986	)
Gathering and transportation		4,927			3,672			1,255			12,879			10,503			2,376
Depletion		44,735			119,800			(75,065	)		167,812			328,879			(161,067	)
Depreciation and amortization		5,974			6,407			(433	)		19,871			17,826			2,045
General and administrative (4)		21,647			21,002			645			64,682			63,286			1,396
Interest expense, net, including impacts of interest rate swaps		46,737			44,874			1,863			129,760			101,167			28,593
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	1.01		$	1.16		$	(0.15	)	$	1.07		$	1.08		$	(0.01	)
Production and ad valorem taxes		0.33			0.57			(0.24	)		0.31			0.57			(0.26	)
Gathering and transportation		0.15			0.10			0.05			0.12			0.10			0.02
Depletion		1.40			3.28			(1.88	)		1.60			3.06			(1.46	)
Depreciation and amortization		0.19			0.18			0.01			0.19			0.17			0.02
General and administrative		0.68			0.57			0.11			0.62			0.59			0.03
Net Income (loss)	$	433,330		$	(146,329	)	$	579,659		$	(738,273	)	$	(572,082	)	$	(166,191	)
Preferred Stock dividends		—			(6,997	)		6,997			—			(76,997	)		76,997

Income (loss) available to common shareholders	$	433,330		$	(153,326	)	$	586,656		$	(738,273	)	$	(649,079	)	$	(89,194	)

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

(2)

Upon closing of the BG Midstream Transaction on August 14, 2009 of 50% of our interest in our East Texas/North Louisiana midstream operations (excluding the Vernon Field midstream assets), our Midstream operations no longer meet the criteria to be designated as a separate business segment. As of August 14, 2009, all operating activity, including intercompany eliminations, for the Vernon Field midstream assets was merged into “Gathering and transportation” expense, as management now evaluates the business as one segment.

(3)	Share-based compensation included in oil and natural gas operating costs is $0.6 million, $2.0 million, $1.2 million and $3.3 million for the three and nine months ended September 30, 2009 and 2008, respectively.

(4)	Share-based compensation included in general and administrative expenses are $2.8 million, $7.9 million, $3.0 million and $7.6 million for the three and nine months ended September 30, 2009 and 2008, respectively.

The following is a discussion of our financial condition and results of operations for the three and nine months ended September 30, 2009 and 2008.

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

•

our 2009 divestures, including the joint venture transactions with BG Group;

•

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

•

the impact of our 2009 natural gas production volumes from our horizontal drilling activities in the Haynesville shale;

•

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

•

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

•

the impact of ceiling test write-downs in 2009 and 2008;

•

gains on sales of assets in 2009;

•

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

•

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

•

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

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 recession which continues to put downward pressure on oil and natural gas prices and demand;

•

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

•

the availability of imported oil and natural gas;

•

actions taken by foreign oil producing nations;

•

the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;

•

the cost and availability of other competitive fuels;

•

fluctuating and seasonal demand for oil, natural gas and refined products;

•

the extent of governmental regulation and taxation (under both present and future legislation) of the production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels; and

•

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

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

Marketing arrangements

We produce oil and natural gas. We do not refine or process the oil or natural gas 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 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 reserves. 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 September 30, 2009, we reported net income available to common shareholders of $433.3 million, compared to a net loss available to common shareholders of $153.3 million for the three months ended September 30, 2008. For the nine months ended September 30, 2009, we reported a net loss available to common shareholders of $738.3 million, compared to a net loss available to common shareholders of $649.1 million for the nine months ended September 30, 2008.

During the nine months ended September 30, 2009, we have closed divestiture transactions totaling approximately $1.4 billion. We have executed agreements to complete additional divestitures prior to December 31, 2009 to further refine our portfolio. Upon closing these divestitures in the fourth quarter of 2009, we will no longer operate in the Mid-Continent region and our primary focus will be exploration of the Haynesville/Bossier shales in East Texas/North Louisiana and the Marcellus shale in Appalachia.

Our results of operations for the three months ended September 30, 2009 are impacted by the BG Upstream Transaction, the BG Midstream Transaction and the sales to Encore. The impacts of these divestitures are summarized as follows:

•

production, revenues, operating expenses and related severance and ad valorem taxes for the three months ended September 30, 2009 reflect the period assets sold to BG Group and Encore, as well as other smaller sales completed during the nine months ended September 30, 2009, and a 48 day period of post-sale interests. We retained a 50% ownership in the net producing assets that were sold to BG Group while we retained no ownership in the producing assets sold to Encore and the smaller divestitures during the period;

•

we discontinued reporting our midstream operations as a separate business segment on August 14, 2009 as a result of the BG Midstream Transaction. We now report our 50% equity investment in TGGT in Equity method loss in TGGT Holdings, LLC on the Condensed Consolidated Statements of Operations; and

•

we recognized a gain from BG Group and Encore divestitures during the three months ended September 30, 2009 of $460.6 million.

The comparability of the three and nine months ended September 30, 2009 and the prior year periods are affected by these divestitures. Our results of operations beginning in the fourth quarter of 2009 will also be affected by the full impact of the third quarter divestitures and the asset sales expected to occur in the fourth quarter.

For the three months ended September 30, 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $63.88 per Bbl and $3.45 per Mcf, respectively, compared with the three months ended September 30, 2008 average realized prices of $116.03 per Bbl and $10.11 per Mcf, respectively. For the nine months ended September 30, 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $50.89 per Bbl and $3.88 per Mcf, respectively, compared with the nine months ended September 30, 2008 average realized prices of $111.66 per Bbl and $9.96 per Mcf, respectively. Derivative financial instruments, which we use to mitigate price volatility, also have a significant impact on our results of operations, since we do not designate our derivative financial instruments as hedges and are required to mark the non-cash changes in the fair value of our derivatives to market at the end of each reporting period.

Oil and natural gas revenues, production and prices

The following table presents our revenues, production and prices by major producing areas for the three and nine months ended September 30, 2009 and 2008:


	Three months ended September 30,
	2009					2008					Quarter change
(in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mmcfe		Production (Mmcfe)	Revenue		$/Mmcfe		Production (Mmcfe)		Revenue			$/Mmcfe
Producing region:
East Texas/North Louisiana	20,573	$	69,252	$	3.37	22,170	$	227,608	$	10.27	(1,597	)	$	(158,356	)	$	(6.90	)
Mid-Continent	4,722		22,830		4.83	6,091		72,007		11.82	(1,369	)		(49,177	)		(6.99	)
Appalachia	4,743		18,981		4.00	5,335		58,473		10.96	(592	)		(39,492	)		(6.96	)
Permian and other	1,898		14,430		7.60	2,961		44,319		14.97	(1,063	)		(29,889	)		(7.36	)

Total	31,936	$	125,493	$	3.93	36,557	$	402,407	$	11.01	(4,621	)	$	(276,914	)	$	(7.08	)


	Nine months ended September 30,
	2009					2008					Year to date change
(in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mmcfe		Production (Mmcfe)	Revenue		$/Mmcfe		Production (Mmcfe)		Revenue			$/Mmcfe
Producing region:
East Texas/North Louisiana	66,530	$	256,128	$	3.85	65,222	$	651,878	$	9.99	1,308		$	(395,750	)	$	(6.14	)
Mid-Continent	16,224		73,628		4.54	18,158		208,532		11.48	(1,934	)		(134,904	)		(6.95	)
Appalachia	14,893		70,940		4.76	15,376		167,818		10.91	(483	)		(96,878	)		(6.15	)
Permian and other	7,153		43,257		6.05	8,789		127,758		14.54	(1,636	)		(84,501	)		(8.49	)

Total	104,800	$	443,953	$	4.24	107,545	$	1,155,986	$	10.75	(2,745	)	$	(712,033	)	$	(6.51	)

For the three months ended September 30, 2009, total oil and natural gas revenues were $125.5 million, a 68.8% decrease from the three months ended September 30, 2008 total oil and natural gas revenues of $402.4 million. For the three months ended September 30, 2009, natural gas represented 81.9% of our oil and natural gas revenues and 93.3% of equivalent production, compared with the three months ended September 30, 2008, where natural gas represented 83.0% of our oil and natural gas revenues and 90.3% of equivalent production. Total equivalent production volumes were 31.9 Bcfe for the three months ended September 30, 2009, a 12.7% decrease from the prior year’s comparable period production of 36.6 Bcfe. The net decrease in 2009 volumes were attributable to our 2009 divestiture program and declines attributable to suspension of vertical drilling activities in all of our regions. These declines were partially offset by increased production from our Haynesville shale drilling program. To summarize, the net decrease of 4.6 Bcfe that occurred for the three months ended September 30, 2009 from the three months ended September 30, 2008 reflects increased production from our Haynesville drilling program of 4.8 Bcfe which was more than offset by declines from our Vernon Field of 2.3 Bcfe, reduced volumes attributable to the East Texas Transaction and the Mid-Continent Transaction of 2.8 Bcfe, a decrease of 2.7 Bcfe from the sale of non-Haynesville shallow production in the BG Upstream Transaction and other declines in Appalachia, Permian and other divestitures completed during the quarter.

For the nine months ended September 30, 2009, total oil and natural gas revenues were $444.0 million, a 61.6% decrease from the nine months ended September 30, 2008 total oil and natural gas revenues of $1.2 billion. For the nine months ended September 30, 2009, natural gas represented 84.3% of our oil and natural gas revenues and 92.2% of equivalent production, compared with the nine months ended September 30, 2008, where natural gas represented 84.1% of our oil and natural gas revenues and 90.8% of equivalent production. Total equivalent production volumes were 104.8 Bcfe for the nine months ended September 30, 2009, a 2.6% decrease over the prior year’s comparable period production of 107.6 Bcfe. The net decrease in production volumes of 2.8 Bcfe for the nine months ended September 30, 2009 compared with the nine months ended September 30, 2008 reflects increases from our Haynesville development of 10.5 Bcfe and a 3.4 Bcfe increase in volumes arising from our July 2008 acquisition of producing oil and natural gas assets in the Danville field in East Texas. These increases of 13.9 Bcfe were more than offset by declines in our Vernon field of 5.8 Bcfe and normal declines combined with suspension of drilling operations in our Permian and Appalachia regions of 1.6 Bcfe. The impacts of the East Texas Transaction and the Mid-Continent Transaction and other divestitures, in combination with normal declines and suspended drilling activities in those areas further reduced volumes by 5.1 Bcfe. Finally, our non-Haynesville East Texas/North Louisiana properties volumes decreased by 4.2 Bcfe, again due to the combination of suspended vertical drilling operations resulting in normal declines and the sale of 50% of the shallow assets in the BG Upstream Transaction.

The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, decreased to $63.88 per Bbl for the three months ended September 30, 2009 from $116.03 per Bbl, or 44.9%, for the three months ended September 30, 2008. For the nine months ended September 30, 2009, the average sales price of oil, excluding derivative financial instruments, was $50.89 per Bbl compared with an average of $111.66 per Bbl for the nine months ended September 30, 2008, a decrease of 54.4%. The average sales price of natural gas per Mcf, excluding the impact of derivative financial instruments, decreased to $3.45 per Mcf for the three months ended September 30, 2009 from $10.11 per Mcf, or 65.9%, for the three months ended September 30, 2008 and decreased to $3.88 per Mcf for the nine months ended September 30, 2009 from $9.96 per Mcf, or 61.0%, for the nine months ended September 30, 2008. The prices 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 a change of $0.10 per Mcf of natural gas sold, using our average production for the month of September 2009, which reflects the full impact of our divestiture program to date, would result in an annual increase or decrease in revenues of approximately $9.8 million and a change of $1.00 per Bbl of oil sold would result in an annual increase or decrease in revenues of approximately $1.1 million without considering the effects of derivative financial instruments.

Midstream revenues

Until our adoption of the equity method of accounting in connection with the BG Midstream Transaction, our midstream revenues were principally derived from three of our wholly-owned subsidiaries: TGG, which owns intrastate pipelines in East Texas and North Louisiana, Talco and Vernon Gathering, LLC. Revenues in our midstream segment were 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.

On August 14, 2009, we closed the BG Midstream Transaction. TGGT now holds our East Texas/North Louisiana midstream assets, exclusive of the Vernon Field midstream assets. Effective August 14, 2009, TGGT is now accounted for as an equity investment on our balance sheet and net operations of Vernon Gathering are now reflected in Gathering and transportation on our Condensed Consolidated Statements of Operations.

Prior to the sale on August 14, 2009, we evaluated our midstream operations as if they were a stand alone operation. Accordingly, the results of operations discussed below are prior to intercompany eliminations.

For the period from July 1, 2009 to August 13, 2009, midstream revenues were $5.4 million compared with $27.0 million for the three months ended September 30, 2008. The decrease in sales reflects the formation of TGGT during the third quarter of 2009 and our change in reporting midstream operations.

For the nine months ended September 30, 2009, midstream revenues were $35.3 million compared with $61.9 million for the nine months ended September 30, 2008. The decrease in sales for the nine months ended September 30, 2009 is due to the combination of lower prices received from the sales of natural gas we purchased for resale, lower condensate prices and the adoption of the equity method of accounting for TGGT’s operations on August 14, 2009.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and nine months ended September 30, 2009 were $32.4 million and $112.1 million, respectively, a decrease of $9.9 million, or 23.5%, and $4.0 million, or 3.4%, respectively, from the same periods in 2008. The decrease in total dollar value for the three months ended September 30, 2009 from September 30, 2008 is due primarily to our divestiture activities, primarily the BG Group and Encore transactions. Management believes that analyses on a per Mcfe basis provide a more meaningful measure than the absolute dollar variance. The following tables summarize direct operating expenses and unit rates per Mcfe for the three and nine months ended September 30, 2009 and 2008:


	Three months ended September 30,				Quarter change			Nine months ended September 30,				Year change
(in thousands)	2009		2008		2009 - 2008			2009		2008		2009 - 2008
Lease operating expense	$	28,655	$	37,804	$	(9,149	)	$	102,046	$	106,190	$	(4,144	)
Workovers		3,100		3,340		(240	)		8,048		6,615		1,433
Stock-based compensation (non-cash)		619		1,169		(550	)		1,998		3,289		(1,291	)

Total oil and natural gas operating costs	$	32,374	$	42,313	$	(9,939	)	$	112,092	$	116,094	$	(4,002	)


	Three months ended September 30,				Quarter change			Nine months ended September 30,				Year change
(per Mcfe)	2009		2008		2009 - 2008			2009		2008		2009 - 2008
Lease operating expense	$	0.90	$	1.04	$	(0.14	)	$	0.97	$	0.99	$	(0.02	)
Workovers		0.09		0.09		—			0.08		0.06		0.02
Stock-based compensation (non-cash)		0.02		0.03		(0.01	)		0.02		0.03		(0.01	)

Total oil and natural gas operating costs	$	1.01	$	1.16	$	(0.15	)	$	1.07	$	1.08	$	(0.01	)

On a per Mcfe basis, oil and natural gas operating expenses for the three months ended September 30, 2009 decreased $0.15 per Mcfe from the same period in 2008. The decreases in total lease operating expense for the three months ended September 30, 2009 compared to the same period in 2008 reflects impacts from divestitures in 2009 combined with lower overall operating costs in field services and fuel costs. Our per Mcfe costs are expected to decrease due to increased volumes from our lower operating cost Haynesville wells where lease operating expenses were $0.11 per Mcfe.

Oil and natural gas operating expenses for the nine months ended September 30, 2009 decreased by $0.01 per Mcfe for the nine months ended September 30, 2009 from the same period in 2008. The decrease in lease operating expense for the nine months ended September 30, 2009 when compared to the same period in 2008 are the result of asset sales in 2009 and lower operating costs in our East Texas/North Louisiana area where increasing volumes from Haynesville wells benefit the unit rate. Benefits from the Haynesville results are offset by declining volumes from our base production that tend to increase the unit rate.

Midstream operating expenses

Our midstream operating expenses for the three and nine months ended September 30, 2009 decreased $23.4 million and $24.1 million from the same periods in 2008, respectively. The decrease in midstream operating expenses for the three and nine months ended September 30, 2009 was primarily attributable to a decline in the prices we paid for the natural gas we purchased for resale along with the August 14, 2009 sale of our midstream segment, excluding the Vernon Gathering system, and related adoption of the equity method of accounting for TGGT’s operations. These decreases were offset by increases in both operating expenses and gas purchases resulting from the 2008 New Waskom and Danville acquisitions as well as the expansion of our gathering and transportation facilities in the East Texas/North Louisiana operating area in support of our Haynesville projects.

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 $4.9 million and $12.9 million for the three and nine months ended September 30, 2009, respectively, compared to $3.7 million and $10.5 million for the three and nine months ended September 30, 2008, respectively.

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.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended September 30, 2009 decreased by $10.0 million, or 48.5%, over the same period in 2008. Production and ad valorem taxes for the nine months ended September 30, 2009 decreased by $29.0 million, or 47.2%, over the same period in 2008. However, on a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 8.5% of gross oil and natural gas revenues for the three months ended September 30, 2009, compared with 5.1% for the same period in the prior year, and 7.3% of gross oil and natural gas sales for the

nine months ended September 30, 2009, compared with 5.3% for the same period in the prior year. The increase in the percentage of revenue basis is primarily the result of the different taxing jurisdictions in which we operate. Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. In Louisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis. 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 complicated by certain severance tax holidays on deep wells. Approval of these holidays in on a well by well basis, and credits are not recognized until approvals are received. Accordingly, a 50% decline in the average sales price per Mcf in Louisiana would double the effective production tax rate as a percentage of revenue. In our other operating areas, production taxes are predominantly price dependent. Ad valorem assessments vary widely. As we complete our divestiture activities in the fourth quarter of 2009, our effective rates for production and ad valorem taxes will also change as we eliminate our Mid-Continent operations and reduce our shallow Appalachia volumes.

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

Overall, our production and ad valorem tax rates per Mcfe were $0.33 per Mcfe for the three months ended September 30, 2009 compared with $0.57 per Mcfe for the three months ended September 30, 2008 and $0.31 per Mcfe for the nine months ended September 30, 2009 compared with $0.57 per Mcfe for the nine months ended September 30, 2008. 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.


	Three months ended September 30,
	2009									2008
(in thousands, except per unit rate)	Revenue		Production (Mmcfe)	Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe		Revenue		Production (Mmcfe)	Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	69,252	20,573	$	6,510	9.4	%	$	0.32	$	227,608	22,170	$	10,410	4.6	%	$	0.47
Mid-Continent		22,830	4,722		2,051	9.0	%		0.43		72,007	6,091		5,274	7.3	%		0.87
Appalachia		18,981	4,743		543	2.9	%		0.11		58,473	5,335		1,518	2.6	%		0.28
Permian and other		14,430	1,898		1,548	10.7	%		0.82		44,319	2,961		3,487	7.9	%		1.18

Total	$	125,493	31,936	$	10,652	8.5	%	$	0.33	$	402,407	36,557	$	20,689	5.1	%	$	0.57


	Nine months ended September 30,
	2009									2008
(in thousands, except per unit rate)	Revenue		Production (Mmcfe)	Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe		Revenue		Production (Mmcfe)	Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	256,128	66,530	$	19,796	7.7	%	$	0.30	$	651,878	65,222	$	31,042	4.8	%	$	0.48
Mid-Continent		73,628	16,224		6,034	8.2	%		0.37		208,532	18,158		15,638	7.5	%		0.86
Appalachia		70,940	14,893		1,913	2.7	%		0.13		167,818	15,376		4,484	2.7	%		0.29
Permian and other		43,257	7,153		4,703	10.9	%		0.66		127,758	8,789		10,268	8.0	%		1.17

Total	$	443,953	104,800	$	32,446	7.3	%	$	0.31	$	1,155,986	107,545	$	61,432	5.3	%	$	0.57

Depletion

Our depletion expense for the three and nine months ended September 30, 2009 decreased by $75.1 million and $161.1 million, or 62.7% and 49.0%, respectively, from the same periods in 2008. The primary reason for the decrease was the lower full cost pool amortization base resulting from $4.1 billion of ceiling test write-downs during 2008 and 2009. These write-downs decreased our per unit depletion rate from $3.28 per Mcfe and $3.06 per Mcfe for the three and nine months ended September 30, 2008, respectively, to $1.40 per Mcfe and $1.60 per Mcfe for the three and nine months ended September 30, 2009, respectively.

Depreciation and amortization

Our depreciation and amortization costs for the three months ended September 30, 2009 decreased by $0.4 million, or 6.8%, from the same period in 2008, due to the contribution of our TGG and Talco assets to TGGT on August 14, 2009. Our depreciation and amortization costs for the nine months ended September 30, 2009 increased by $2.0 million, or 11.5%, from the same period in 2008, due to the increase in our gas gathering asset base which includes our July 2008 Danville acquisition.

Accretion of discount on asset retirement obligations for the three and nine months ended September 30, 2009 increased by $0.3 million and $1.6 million, or 19.2% and 37.1%, respectively, from the same periods in 2008. The increase is due to the combination of significant well additions and related plugging liabilities in connection with our 2008 acquisitions, revisions to previous estimates, and increased estimates for the costs to plug and abandon properties, partially offset by the properties sold in August 2009 to BG Group and Encore.

Write-down of oil and natural gas properties

We recognized a ceiling test write-down of our oil and natural gas properties of $1.3 billion for the nine months ended September 30, 2009. For the three months ended September 30, 2009, we would have incurred a ceiling test write-down of $43.5 million. However, subsequent price increases for natural gas eliminated the need for a write-down. The new oil and gas reporting requirements contained within SEC Release 33-8995, which will become effective on December 31, 2009, no longer provide for subsequent price changes for ceiling test computations. For the three and nine months ended September 30, 2008, we recognized a ceiling test write-down of $1.2 billion to our proved oil and natural gas properties.

Under full cost accounting, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. On September 30, 2009, the spot price for natural gas at Henry Hub was $3.30 per Mmbtu and the spot oil price at Cushing, Oklahoma was $70.43 per Bbl. On September 30, 2008, the spot price for natural gas at Henry Hub was $7.12 per Mmbtu and the spot oil price at Cushing, Oklahoma was $100.67 per Bbl. Natural gas, which is sold at other natural gas marketing hubs where we conduct our operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we typically have received a premium to Henry Hub. There can be no assurance that positive basis differentials in Appalachia will continue.

General and administrative

The following table presents our general and administrative expenses for the three months ended September 30, 2009 and 2008, and changes for the quarters then ended.


	Three months ended September 30,						Quarter change 2009-2008		Nine months ended September 30,						Year to date change 2009-2008
(in thousands, except per unit rate)	2009			2008			Quarter change 2009-2008		2009			2008			Year to date change 2009-2008
General and administrative costs:
Gross general and administrative expense	$	31,479		$	31,047		$	432	$	94,209		$	89,613		$	4,596
Operator overhead reimbursements		(6,461	)		(6,604	)		143		(19,180	)		(18,305	)		(875	)
Capitalized acquisition and development charges		(3,371	)		(3,441	)		70		(10,347	)		(8,022	)		(2,325	)

Net general and administrative expense	$	21,647		$	21,002		$	645	$	64,682		$	63,286		$	1,396


General and administrative expense per Mcfe	$	0.68		$	0.57		$	0.11	$	0.62		$	0.59		$	0.03

Our general and administrative costs for the three months ended September 30, 2009 were $21.6 million, or $0.68 per Mcfe, compared to $21.0 million, or $0.57 per Mcfe, for the same period in 2008, an increase of $0.6 million, or 3.1%. Our general and administrative costs for the nine months ended September 30, 2009 were $64.7 million, or $0.62 per Mcfe, compared to $63.3 million, or $0.59 per Mcfe, for the same period in 2008, an increase of $1.4 million, or 2.2%.

The primary components of the $0.6 million increase for the three months ended September 30, 2009 was increased personnel costs of $2.8 million due primarily to expansion of our technical staff in 2008 and 2009 to exploit our shale resource asset base and rent increase of $0.2 million resulting from this expansion. The increases are offset by a $2.1 million decrease in legal expense and a $0.4 million decline in information technology costs due to the prior year costs incurred for the 2008 acquisitions.

The primary components of the net increase of $1.4 million for the nine months ended September 30, 2009 were higher personnel costs of $10.8 million due to additional employees related to expansion of technical staff to exploit our shale resource asset base and increased rent of $0.8 million resulting from this expansion.

These increases were offset by the following items:

•

decreased legal fees of $5.2 million due to the first quarter 2008 cancellation of a proposed master limited partnership and reduced reserves for claims;

•

decreased franchise and property taxes of $1.7 million due primarily to lower equity as a result of 2008 and 2009 ceiling test write-downs and recapitalization of our corporate structure;

•

decreased information and technology costs of $1.2 million due primarily to prior year costs incurred in connection with additional personnel;

•

increased operator overhead recoveries of $0.9 million due to the 2008 acquisitions; and

•

increased capitalized salary costs of $2.3 million due to the previously discussed expansion of technical personnel.

Interest expense

Our interest expense for the three and nine months ended September 30, 2009 increased by $1.9 million and $28.6 million, or 4.2% and 28.3%, from the same periods in 2008. For the three months ended September 30, 2009 compared with the three months ended September 30, 2008, interest and amortization of related financing costs associated with our Term Credit Agreement used to finance our 2008 acquisition of oil and natural gas properties in the Danville field in East Texas increased by $8.5 million. Interest expense also increased by $1.3 million from settlements and fair value adjustments from interest rate swaps. The increases of $9.8 million were partially offset by lower interest costs of $8.4 million on the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement. Decreased interest costs from our credit agreements are largely the result of lower LIBOR in 2009 compared with 2008.

The increased interest expenses for the nine months ended September 30, 2009 compared with the nine months ended September 30, 2008 of $28.6 million is the result of the Term Credit Agreement costs of $45.9 million and increased expense of $9.9 million from realized and unrealized interest losses on derivative financial instruments. The increases were partially offset by lower revolving credit agreement costs of $25.1 million.


	Three months ended September 30,						Quarter change 2009-2008			Nine months ended September 30,						Year to date change 2009-2008
(in thousands)	2009			2008			Quarter change 2009-2008			2009			2008			Year to date change 2009-2008
Interest expense:
7¹/4% senior notes due 2011	$	7,156		$	7,212		$	(56	)	$	21,510		$	21,675		$	(165	)
EXCO Resources Credit Agreement		6,093			11,528			(5,435	)		19,786			32,190			(12,404	)
EXCO Operating Credit Agreement		5,110			12,848			(7,738	)		21,736			39,979			(18,243	)
Term Credit Agreements		4,669			6,286			(1,617	)		19,752			6,286			13,466
Amortization of deferred financing costs on EXCO Resources Credit Agreement		2,675			493			2,182			4,370			1,463			2,907
Amortization and write-off of deferred financing costs on EXCO Operating Credit Agreement		3,362			754			2,608			4,870			2,260			2,610
Amortization of deferred financing costs on Term Credit Agreements		15,426			5,312			10,114			37,755			5,312			32,443
Interest rate swaps settlements		3,550			(163	)		3,713			8,036			(924	)		8,960
Fair market value adjustment on interest rate swaps		(245	)		2,215			(2,460	)		(4,250	)		(5,155	)		905
Capitalized interest		(1,140	)		(1,609	)		469			(3,937	)		(1,925	)		(2,012	)
Other interest expense		81			(2	)		83			132			6			126

Total interest expense	$	46,737		$	44,874		$	1,863		$	129,760		$	101,167		$	28,593

Upon closings of the BG Upstream Transaction, the BG Midstream Transaction, the East Texas Transaction and the Mid-Continent Transaction, we paid off the Term Credit Agreement and reduced outstanding debt on the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement by approximately $723.0 million. Subsequent to closing of these divestiture transactions, we reduced outstanding borrowings on our credit agreements to a total of $1.2 billion as of September 30, 2009, a decrease of $1.1 billion from outstanding borrowings of $2.3 billion under the credit agreements as of June 30, 2009.

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, service debt and achieve a more predictable cash flow in connection with our activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

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


	Three months ended September 30,						Quarter change 2009-2008			Nine months ended September 30,						Year to date change 2009-2008
(in thousands)	2009			2008			Quarter change 2009-2008			2009			2008			Year to date change 2009-2008
Derivative financial instrument activities:
Cash settlements on derivative financial instruments	$	113,563		$	(70,019	)	$	183,582		$	354,131		$	(157,383	)	$	511,514
Non-cash change in fair value of derivative financial instruments		(99,045	)		970,332			(1,069,377	)		(149,246	)		53,849			(203,095	)

Total derivative financial instrument activities	$	14,518		$	900,313		$	(885,795	)	$	204,885		$	(103,534	)	$	308,419

Our non-cash mark-to-market changes in the fair value of our oil and natural gas derivative financial instruments for the three and nine months ended September 30, 2009 resulted in a loss of $99.0 million and $149.2 million, respectively, compared to a gain of $970.3 million and $53.9 million for the same periods 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.

The use of derivative financial instruments allows us to limit the impacts of volatile price fluctuations associated with oil and natural gas. The following table presents our natural gas prices, before the impact of derivative financial instruments, where average realized prices per Mcfe dropped from $10.75 during the nine months ended September 30, 2008 to $4.24 during the nine months ended September 30, 2009. This volatility was offset somewhat from realized settlements of our derivatives, where average realized prices per Mcfe after the impact of our derivative financial instruments increased our price from $4.24 to $7.62 per Mcfe during the nine months ended September 30, 2009 and decreased our price from $10.75 to $9.29 per Mcfe for the nine months ended September 30, 2008. This decreased our year to date change from $6.51 per Mcfe before cash settlements on derivatives to $1.67 per Mcfe after cash settlements on derivatives. Using the same calculations, our quarter to quarter change decreased from $7.08 per Mcfe before cash settlements on derivatives to $1.60 per Mcfe after cash settlements on derivatives.


	Three months ended September 30,					Quarter change 2009-2008			Nine months ended September 30,					Year to date change 2009-2008
Realized pricing:	2009		2008			Quarter change 2009-2008			2009		2008			Year to date change 2009-2008
Oil per Bbl	$	63.88	$	116.03		$	(52.15	)	$	50.89	$	111.66		$	(60.77	)
Natural gas per Mcf		3.45		10.11			(6.66	)		3.88		9.96			(6.08	)

Natural gas equivalent per Mcfe	$	3.93	$	11.01		$	(7.08	)	$	4.24	$	10.75		$	(6.51	)
Effect of cash settlements on derivatives		3.56		(1.92	)		5.48			3.38		(1.46	)		4.84

Net price per Mcfe, including derivative financial instruments	$	7.49	$	9.09		$	(1.60	)	$	7.62	$	9.29		$	(1.67	)

Our cash settlements for the three months ended September 30, 2009 increased income by $113.6 million, or $3.56 per Mcfe, compared to cash payments which decreased income by $70.0 million, or $1.92 per Mcfe, for the same period in 2008. Our cash settlements for the nine months ended September 30, 2009 increased income by $354.1 million, or $3.38 per Mcfe, compared to cash payments which decreased income by $157.4 million, or $1.46 per Mcfe, for the same period in 2008. As noted above, the significant fluctuations between settlements of receipts on our derivative financial instruments demonstrate the volatility in prices.

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

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. For the three months ended September 30, 2009, we had realized losses from payments of $3.6 million and $0.2 million of non-cash unrealized gains attributable to our interest rate swaps, compared to realized gains from settlements of $0.2 million and non-cash unrealized losses of $2.2 million for the same period in 2008. For the nine months ended September 30, 2009, we had realized losses from payments of $8.0 million and $4.3 million of non-cash unrealized gains attributable to our interest rate swaps, compared to realized gains from settlements of $0.9 million and non-cash unrealized gains of $5.2 million for the same period in 2008.

Other Income

Other income consists of interest earned on our cash balances, miscellaneous gathering income which was not designated as a component of our midstream segment, income or losses resulting from periodic re-evaluation from natural gas imbalances and non-recurring items that do not impact our operations. For the nine months ended September 30, 2009, net other expense was $7.9 million compared with $5.5 million net other income in the same period in 2008. For the three months ended September 30, 2009, we recognized approximately $47,000 of net other income compared to $1.8 million of other net income for the three months ended September 30, 2008. The net other expense for the nine months ended September 30, 2009 is due to two rig cancellations during the second quarter of 2009 that totaled $6.2 million.

Income taxes

Our effective income tax rate for the three and nine months ended September 30, 2009 was an expense of (0.5%) and zero, respectively, and for the three and nine months ended September 30, 2008, a benefit of 2.9% and 31.6%, respectively. For the three months ended September 30, 2009, we utilized a portion of our accumulated valuation allowance of $168.7 million. For the nine months ended September 30, 2009, we have accumulated $289.9 million of valuation allowance which can be used against future deferred tax benefits. For both the three and nine months ended September 30, 2008, we recognized a valuation allowance of $63.3 million against future deferred tax benefits. The valuation allowance for both 2009 and 2008 is primarily attributable to the ceiling test write-downs, which occurred in the last half of 2008 and the first quarter of 2009, 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 rate excluding the impact of the valuation allowance for the three and nine months ended September 30, 2009 would have been a benefit of 38.7% and 39.3%, respectively, and the effective tax rate excluding the impact of the valuation allowance for the three and nine months ended September 30, 2008 would have been a benefit of 44.9% and 39.2%, respectively. A substantial portion of our stock-based compensation included in our results of operations for the three and nine months ended September 30, 2009 and 2008 are in the form of incentive stock options which are not deductible for tax purposes until a disqualifying event occurs. The change in the tax rate from the prior year, without giving consideration to the impact of the deferred income tax valuation allowance, is mainly a result of a state rate change last year in our state income taxes.

Our liquidity, capital resources and capital commitments

Overview

Our financial strategy is to use a combination of cash flow from operations, bank financing, cash received from the sale of oil and natural gas properties and the issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. Historically, we have used acquisitions and vertical drilling as our primary vehicles for growth. However, the recent success we have encountered in the Haynesville shale play in East Texas/North Louisiana and the opportunities we believe are available in the Marcellus shale in Appalachia have caused us to shift our focus from an acquisition-oriented strategy to horizontal drilling, development and exploitation activities. As a result of the BG Upstream Transaction, we expect to increase our drilling and leasing activities within the AMI. Pursuant to the Joint Development Agreement, or JDA, with BG Group, BG Group has agreed to fund 75% of our 50% interest in deep drilling projects up to $400.0 million. As a result of this carried amount, our required capital expenditures will be substantially reduced during the carried period.

Cash flows from operations and unused borrowing capacity under our revolving credit agreements represent the primary source of liquidity to fund our operations and our capital expenditure programs. The primary factors impacting our cash flow from operations include (i) levels of production from our oil and natural gas properties, (ii) prices we receive for sales of oil and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs for our general and administrative activities and (v) interest expense and other financing related costs.

We have an objective of maintaining financing flexibility and using derivative financial instruments to mitigate oil and natural gas price fluctuations. During the last half of 2008 and through October of 2009, prices for natural gas have declined significantly. As a result of these price declines, many of our vertical drilling economics no longer meet our internal rate of return objectives. We expect our capital expenditures to be approximately $535 million in 2009.

In the fourth quarter of 2008, we commenced a program to divest various assets throughout our entire portfolio and engaged several different brokers to assist with these divestitures. Through October 30, 2009, we have closed the BG Upstream Transaction, the BG Midstream Transaction and completed the sale of certain oil and natural gas properties totaling approximately $1.4 billion in proceeds, after customary closing and post-closing adjustments. We expect to complete additional divestitures during 2009, including the sale of certain of our shallow oil and natural gas properties in Appalachia and all of the remaining assets in our Mid-Continent region. Proceeds from the fourth quarter sales are expected to exceed $685.0 million, subject to preliminary closing price adjustments.

The oil and natural gas asset sales and the joint venture transactions with BG Group provided us with substantial liquidity. We used these proceeds to pay down debt and expect to further reduce debt with proceeds from remaining 2009 sales transactions. Through October 30, 2009, we have reduced our outstanding debt by $1.4 billion from the June 30, 2009 outstanding balance, including payoff of the Term Credit Agreement. However, our oil and natural gas production, results of operations and future liquidity from operations will be reduced in the near term as a result of assets sales and the reduced interest in properties sold to the BG Group.

We generally do not establish a budget for acquisitions, as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders and the indenture governing our 7¹/4% Senior Notes due January 15, 2011, or Senior Notes, contains restrictions on incurring indebtedness and pledging our assets. In addition, disruptions in the credit and capital markets have limited the availability of financing to fund acquisitions.

As of October 30, 2009, the aggregate borrowing bases under our credit agreements, after the October, 2009 borrowing base redeterminations, totaled $1.7 billion, of which $1.2 billion was drawn. In addition, we have $444.7 million outstanding under our Senior Notes due on January 11, 2011. Pursuant to our most recent borrowing base redeterminations in October 2009, we have agreed to reduce the borrowing base of the EXCO Resources Credit Agreement by an additional $400.0 million upon closing of expected asset sales in Appalachia and in the Mid-Continent region. In connection with these sales, we may close certain oil and natural gas derivatives to comply with our credit agreements.

Recent events affecting liquidity

Encore transactions

On August 11, 2009, we closed on sales of assets contained within the East Texas Transaction and the Mid-Continent Transaction with Encore for aggregate cash proceeds of approximately $356.5 million, including preliminary closing adjustments. The oil and natural gas properties sold included (i) all of EXCO’s interests in its Gladewater area and Overton field in Gregg, Upshur and Smith counties in East Texas, or the East Texas Properties, and (ii) certain oil and natural gas properties in the Mid-Continent region of Oklahoma, Kansas and the Texas Panhandle, or the Mid-Continent Sale, collectively the Encore Transactions.

BG Group transactions

On August 14, 2009, we closed on the BG Upstream Transaction and the BG Midstream Transaction representing the sale of an undivided 50% interest in certain oil and natural gas properties in East Texas/North Louisiana and a 50% interest in certain midstream operations, respectively, in East Texas/North Louisiana for aggregate proceeds of approximately $996.2 million, including closing adjustments.

In addition, BG Group will fund 75% of our capital expenditures on certain drilling and completion activities within the AMI until the aggregate of such expenditures equals $400.0 million, or the BG Group Carry. The BG Group Carry is expected to be fully funded in 2011 or 2012. If BG Group defaults in the payment of the BG Group Carry, then EXCO has the right to require BG Group to reassign to EXCO a proportionate percentage of BG Group’s interest in the deep rights within the AMI. Upon the reassignment, the BG Group Carry will terminate.

Other than the BG Group Carry, each party will be responsible for its share of the costs and expenses associated with exploring, developing and producing the oil and natural gas assets in the AMI. To facilitate funding these costs and expenses and to provide security to each party, BG Group and EXCO have agreed to fund periodically an escrow account created by the parties with an amount equal to estimates of certain future expenses for the following three month period. In addition to this three month deposit, EXCO has agreed to fund one additional month of development costs into the escrow account and three additional months of operating expenses into the escrow account.

Credit agreements and debt reduction

Following consummation of the Encore Transactions, the BG Upstream Transaction and the BG Midstream Transaction, we repaid the Term Credit Agreement and reduced outstanding balances under our revolving credit facilities as follows:


(in thousands)
Repayment of Term Credit Agreement	$	300,000
Payments on EXCO Resources Credit Agreement		200,000
Payments on EXCO Operating Credit Agreement		723,000

Total debt reductions	$	1,223,000

In October 2009, the lenders under the EXCO Resources Credit Agreement and EXCO Operating Credit Agreement entered into amendments which resulted in an aggregate borrowing base of $1.7 billion and agreed upon reductions of $400.0 million upon completion of certain pending asset sales. In addition, the amendment provided for payments of cash dividends, subject to certain limitations on the drawn balance and agreements to reduce derivative percentages within the guidelines of each credit agreement.

The following table presents our expected debt balances and available borrowings under our credit agreements on a pro forma basis as of October 30, 2009 after giving effect to our expected fourth quarter divestitures:


(in thousands)	As of October 30, 2009		Expected fourth quarter 2009 divestitures			Pro forma
Borrowings (payments) under credit agreements	$	1,239,645	$	(685,000	)	$	554,645
7¹/4% senior notes due 2011		444,720		—			444,720

Total borrowings (payments)	$	1,684,365	$	(685,000	)	$	999,365

Borrowing base	$	1,700,000	$	(400,000	)	$	1,300,000
Unused borrowing base	$	460,355				$	745,355

Beginning in the fourth quarter of 2008, the United States government and the Federal Reserve implemented various programs and enacted legislation designed to provide liquidity to financial institutions, stabilize credit markets and provide other forms of economic stimulation to the economy. The impacts of these actions, many of which have yet to be fully implemented, on our industry and on us, cannot be determined at this time, nor can we determine the length of time that credit markets will remain constrained, and the ultimate impact on our ability to access capital is expected to be equally uncertain. As further discussed below, our capital budget for 2009 reflects reduced and more targeted capital expenditures for development and exploitation than in 2008 and prior years. The significant reduction in our drilling of conventional wells, combined with our asset sales and reduced interest arising from the BG Upstream Transaction, will impact our production volumes in future periods. However, the provision in the JDA for the BG Group to fund 75% of our share of drilling and development costs on new Haynesville and other deep rights wells spudded after closing, up to a maximum of $400.0 million, will allow us to accelerate our development of the Haynesville shale play while significantly reducing our development cost per Mcf. While our recent debt reduction combined with the value created by the carried portion of capital expenditures are favorable as they relate to our reliance on available credit, the credit markets remain an area of concern.

In addition to the continuing turmoil in the credit markets and related uncertainties, prices for natural gas have suffered a precipitous decline, which began in the third quarter of 2008 and has continued, reaching new lows for 2009 during the third quarter. Prices for oil and natural gas have continued to show significant volatility throughout the third quarter of 2009. As of October 30, 2009 the spot prices for oil and natural gas were $77.01 per Bbl and $4.10 per Mmbtu compared with $70.43 per Bbl and $3.30 per Mmbtu on September 30, 2009 and $44.60 per Bbl and $5.71 per Mmbtu on December 31, 2008. The oil and gas markets remain significantly below September 30, 2008 levels, on which date the spot prices for oil and natural gas were $100.67 per Bbl and $7.12 per Mmbtu, respectively. NYMEX future prices for oil and natural gas have also declined significantly since the third quarter of 2008, reflecting anticipated decreasing domestic and worldwide demand for oil and natural gas as a result of the global recession and uncertainties about the depth and length of the recession and the timing of a recovery. Each of the aforementioned events could impact our near-term, and perhaps long-term, liquidity and operating revenues resulting in changes to business plans or operations. As discussed in greater detail under “Item 3. Quantitative and Qualitative Disclosures About Market Risk,” we use derivative financial instruments to mitigate commodity price fluctuations and interest rate fluctuations to manage our debt service requirements.

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

While our cash provided from operations benefits from the use of derivative financial instruments, a portion of our expected 2009 sales volumes are not subject to derivative financial instruments. Accordingly, in periods where prices increase, we will not receive full benefit from those increases. Conversely, when prices decrease, we are also impacted negatively on the portion of our production not covered by derivative contracts. Beginning in the second half of 2008 and into 2009, oil and natural gas prices declined significantly. As a result, we received cash settlements from our oil and natural gas derivative counterparties during the three and nine months ended September 30, 2009 totaling $113.6 million and $354.1 million, respectively. We are required to settle our derivative financial instruments prior to receiving the payments for production, which is typically collected 30 to 60 days after our derivative settlements are closed. This timing between settlement of the derivative financial instruments and actual collection of the proceeds can create short-term borrowing requirements in periods of increasing prices. In periods of declining prices, we may experience temporary cash and liquidity increases from settlements of our derivative financial instruments.

Historical sources and uses of funds

Cash flows from operations

Our operating cash flows are driven by the quantities of our oil and natural gas production and the prices received from the sale of this production. Prices of oil and natural gas have historically been volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our indebtedness, general and administrative expenses and taxes on income. Prior to the formation of TGGT on August 14, 2009, cash flows from our midstream business segment were an available source of cash flows from operations. Presently, there is an aggressive capital expenditure program within TGGT. Consequently, we do not expect any cash distributions from that entity in the foreseeable future.

Net cash provided by operating activities was $349.9 million for the nine months ended September 30, 2009 compared with $812.0 million for the nine months ended September 30, 2008. The 56.9% decrease is attributable primarily to lower average oil and natural gas prices in the first three quarters of 2009 compared with average prices during the same period in 2008, offset by increases in cash settlements of our oil and natural gas derivatives. Also impacting our cash flow from operating activities in the 2009 period was production attributable to oil and natural gas properties sold, primarily from the East Texas Properties transaction and Mid-Continent Sale transactions (both of which closed on August 11, 2009) and the BG Upstream transaction, which closed on August 14, 2009. At September 30, 2009, our cash and cash equivalents balance was $55.7 million, a 2.6% decrease from December 31, 2008. On October 30, 2009, our cash and cash equivalent balance was $38.6 million.

Investing activities and transactions

Prior to 2009, a significant amount of our growth was from acquisitions of existing producing and non-producing oil and natural gas properties and related assets, including our midstream assets. These acquisitions were funded to a great extent by borrowings under credit agreements and term loan agreements, as well as issuance of equity. As discussed above, the deterioration in the U.S. and worldwide credit and equity markets has significantly diminished our ability to fund additional growth in the near term through these capital sources. However, consummation of asset sales and transactions with BG Group has provided significant liquidity and enabled us to significantly reduce our debt. In addition, BG Group’s carry obligation of $400.0 million will reduce our capital expenditures.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the three and nine months ended September 30, 2009 and 2008:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2009		2008		2009		2008
Capital expenditures:
Property acquisitions	$	3,396	$	245,069	$	3,789	$	722,247
Midstream acquisitions		—		10,974		—		66,641
Lease purchases		35,197		74,696		53,443		177,353
Development capital expenditures		61,274		201,356		258,991		489,693
Midstream capital additions		20,484		15,112		53,627		40,770
Corporate and other		8,590		16,284		35,225		41,407

Total capital expenditures	$	128,941	$	563,491	$	405,075	$	1,538,111

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

We expect our capital expenditures to total approximately $535.0 million for all of 2009, of which we are contractually obligated to spend $52.3 million as of September 30, 2009. We expect to utilize our current cash balances, cash flow generated from operations, and available funds under our credit agreements in 2009 to fund capital expenditures and acquisitions, if any. We continue to monitor the economics of drilling projects in light of the current commodity price environment, which we believe will result in reductions from our budgeted capital expenditures.

Future cash flows are subject to a number of variables including production volumes, which will be lower for the remainder of 2009 as a result of the asset sales discussed above, fluctuations in oil and natural gas prices, future asset sales and servicing of debt incurred. 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 October 30, 2009, we have total debt outstanding aggregating approximately $1.7 billion consisting of two revolving credit agreements maturing in March 2012 and Senior Notes due in January 2011. Terms and considerations of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, pursuant to the fifth amendment effective on October 2, 2009, has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. The borrowing base is redetermined semi-annually, with EXCO and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO may have in place derivative financial instruments covering no more than 80% of its forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have in place mortgages covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012.

On October 30, 2009, we had $751.4 million of outstanding indebtedness and $83.4 million of available borrowing capacity under the EXCO Resources Credit Agreement. The interest rate ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 basis points, or bps, to ABR plus 150 bps depending upon borrowing base usage. At October 30, 2009, the one month LIBOR was 0.24%, which would result in an interest rate of approximately 2.49% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

On October 2, 2009, we entered into the fifth amendment to the EXCO Resources Credit Agreement which, among other things, modified the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the fifth 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 borrowing base availability under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under EXCO’s 7¹/4% Senior Notes Indenture.

Also on October 2, 2009, the lenders agreed to consents which (i) established the borrowing base under the EXCO Resources Credit Agreement at $850.0 million, (ii) approved the proposed sale of the Appalachia properties and extended the deadline for consummation of the sale transaction to November 30, 2009, (iii) set the estimated loan value for the Appalachia properties proposed sale at $100.0 million with reduction in the borrowing base effective with the closing of such transaction of $100.0 million, and (iv) permit EXCO to receive non-cash consideration from the proposed sale of the Appalachia properties in an amount not to exceed 5.0% of the value of total sales consideration received from such sale. In addition to the Appalachia properties, the lenders assigned a $300.0 million loan value to certain Mid-Continent properties which are being sold.

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

•

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

•

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

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

EXCO Operating Credit Agreement

The EXCO Operating Credit Agreement, as amended, currently has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At October 30, 2009, we had $488.2 million of outstanding indebtedness and $361.8 million of available borrowing capacity under the EXCO Operating Credit Agreement. The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may have in place derivative financial instruments covering no more than 80% of the forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012.

On October 16, 2009, the lenders agreed to consents which (i) confirmed the borrowing base under the EXCO Operating Credit Agreement at $850.0 million until the next borrowing base redetermination date, (ii) provide for EXCO Operating to grant to lenders a first priority lien and security interest in all of its equity interest in TGGT, representing EXCO Operating’s retained 50% interest in the midstream assets contributed in connection with the BG Midstream Transaction, and (iii) by November 30, 2009, consummate transactions to unwind oil and natural gas derivatives with respect to notional volumes of oil and natural gas with respect to sold production volumes which have been waived by a July 29, 2009 consent.

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

•

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

•

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

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

Term Credit Agreement

On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement with an aggregate balance of $300.0 million. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating provided for additional fees on unpaid principal amounts, or duration fees, as defined in the agreement. These included a 5% fee on the unpaid principal on June 15, 2009 and an additional 3% fee on any unpaid outstanding balance as of September 15, 2009. On June 15, 2009 we remitted the first duration fee payment of $15.0 million.

In connection with the closings of the BG Upstream Transaction and the BG Midstream Transaction on August 14, 2009 and the East Texas Transaction on August 11, 2009, EXCO Operating repaid the Term Credit Agreement. As a consequence of the early payment of the unsecured term loan, EXCO Operating avoided payment of a $9.0 million duration fee that would have been due on September 15, 2009.

7¹/4% Senior Notes due January 15, 2011

As of September 30, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at September 30, 2009 was $4.9 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $442.5 million on September 30, 2009.

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

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

•

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

•

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

•

make investments;

•

create liens on our assets;

•

enter into sale/leaseback transactions;

•

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

•

engage in transactions with our affiliates;

•

transfer or issue shares of stock of subsidiaries;

•

transfer or sell assets; and

•

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

Derivative financial instruments

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

Oil and natural gas derivatives

Our 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 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 September 30, 2009, we had derivative financial instrument contracts in place for the volumes and prices shown below:


(in thousands, except prices)	Natural gas index swap volume - Mmbtu	Weighted average strike price per Mmbtu		Natural gas basis swap volume - Mmbtu	Weighted average strike price per Mmbtu			Oil volume - Bbls	Weighted average strike price per Bbl
Swaps:
Q4 2009	23,450	$	8.08	920	$	(1.10	)	398	$	80.66
2010	66,298		7.62	—		—		1,568		104.64
2011	12,775		7.48	—		—		1,095		112.99
2012	5,490		5.91	—		—		92		109.30
2013	5,475		5.99	—		—		—		—

Interest rate swaps

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at September 30, 2009:


	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
Long-term debt - Senior Notes (1)	$	—	$	444,720	$	—	$	—	$	444,720
Long-term debt - EXCO Resources Credit Agreement (2)		—		751,430		—		—		751,430
Long-term debt - EXCO Operating Credit Agreement (3)		—		488,215		—		—		488,215
Tubular commitment		2,400		—		—		—		2,400
Firm transportation services (4)		8,007		6,685		7,891		28,722		51,305
Operating leases and construction commitments		8,678		12,840		10,041		5,585		37,144
Drilling contracts		48,707		55,095		3,401		—		107,203

Total contractual cash obligations	$	67,792	$	1,758,985	$	21,333	$	34,307	$	1,882,417

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

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

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

(4)	Firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a shippers’ pipeline. Whether or not EXCO delivers the minimum quantity, we pay the fee as if the quantities were delivered.

The above table does not include a commitment for a new firm transportation agreement entered into with a shipper in the Haynesville shale producing region, which commits us to ship 237,500 Mmbtus per day for a ten year period. The annual commitment is approximately $26.0 million. This commitment is not effective until the shipper’s pipeline construction is completed. We expect this project to be completed by late 2009 or early 2010.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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

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 September 30, 2009.


(in thousands, except prices)	Volume Mmbtu/Bbl	Floor and ceiling, weighted average strike price			Fair value at September 30, 2009
Natural gas:
Remainder of 2009	23,450	$	8.08		$	77,469
2010	66,298		7.62			92,472
2011	12,775		7.48			7,691
2012	5,490		5.91			(5,524	)
2013	5,475		5.99			(5,256	)

Total natural gas	113,488					166,852


Basis swaps:
Remainder of 2009	920		(1.10	)		(773	)

Total basis swaps	920					(773	)


Oil:
Remainder of 2009	398		80.66			3,780
2010	1,568		104.64			46,723
2011	1,095		112.99			37,876
2012	92		109.30			2,596

Total oil	3,153					90,975


Total oil and natural gas derivatives					$	257,054

At September 30, 2009, the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2009 and for 2010 were $4.75 and $6.21, respectively and the average forward NYMEX oil prices per Bbl for the remainder of 2009 and for 2010 were $71.08 and $74.38, 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 September 30, 2009, for the remainder of 2009, if the settlement price exceeds the actual weighted average strike price of $80.66 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $80.66 per Bbl, multiplied by the hedged volume of 398 Mbbls. Conversely, if the settlement price is less than $80.66 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $80.66 per Bbl, multiplied by the hedged volume of 398 Mbbls. For example, for a hedged volume of 398 Mbbls, if the settlement price is $81.66 per Bbl then other income would decrease by $0.4 million. Conversely, if the settlement price is $79.66 per Bbl, other income would increase by $0.4 million.

Interest rate risk

At September 30, 2009, our exposure to interest rate changes related primarily to borrowings under our credit agreements and interest earned on our short-term investments. The interest rate is fixed at 7¹/4% on the $444.7 million outstanding on our Senior Notes. Interest is payable on borrowings under our credit agreements and the Term Credit Agreement based on a floating rate as more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity, capital resources and capital commitments.” At September 30, 2009, we had approximately $1.2 billion in outstanding borrowings under our credit agreements. A 1% change in interest rates based on the variable borrowings as of September 30, 2009 would result in an increase or decrease in our interest costs of $12.0 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. As of September 30, 2009, the fair value of our interest rate swaps was a liability of $5.6 million.

Item 4.

Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO’s disclosure controls and procedures were effective as of September 30, 2009 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to EXCO’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO’s internal control over financial reporting that occurred during the fiscal quarter ended September 30, 2009 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

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

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 ACESA. The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States. GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, most 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 ACESA’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. The net effect of ACESA will 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 ACESA, the Senate legislation would need to be reconciled with ACESA 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 permitting system that results in fewer allowances being issued each year 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 may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, 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 Environmental Protection Agency has also taken recent action related to greenhouse gases. On April 17, 2009, the U.S. Environmental Protection Agency, or “EPA,” issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” presented an endangerment to human health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere. Once finalized, EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take EPA several years to adopt and impose regulations limiting emissions of GHGs, 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 that will require large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. Although this rule does not limit the amount of GHGs that can be emitted, it 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.

Legislation has been proposed in Congress and by the Treasury Department to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Under proposed legislation, OTC derivative dealers and other major OTC derivative market participants could be subjected to substantial supervision and regulation. The legislation generally would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, to mandate clearance of derivative contracts through registered derivative clearing organizations, and to impose conservative capital and margin requirements and strong business conduct standards on OTC derivative transactions. The CFTC has conducted hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products, and whether position limits should be applied consistently across all markets and participants. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

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 require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would remove the exemption of hydraulic fracturing operations from the Safe Water Drinking Act and require the reporting and public disclosure of chemicals used in the fracturing process. 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 increase our costs of compliance.

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: November 4, 2009	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		Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search, Incorporated, as sellers, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.

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

2.3		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.

2.4		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.

2.5		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.

2.6		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.

2.7		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.

2.8		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.

2.9		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 herewith.

2.10		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 herewith.

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.

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

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

10.15		Amended and Restated Credit Agreement, dated as of March 30, 2007, among EXCO Partners Operating Partnership, LP, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole 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.

10.16		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.

10.17		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.

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

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

10.24		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.

10.25		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.

10.26		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.

10.27		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.

10.28		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.

10.29		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.

10.30		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.

10.31		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.

10.32		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.

10.33		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.

10.34		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 herewith as exhibit 2.9.

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 herewith as exhibit 2.10.

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

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

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

32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.

*	These exhibits are management contracts.

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