Exco Resources (EXCO) 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________

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

For the quarterly period ended September 30, 2012

OR

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

For the transition period from             to            

Commission File Number 001-32743

______________________________ 

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

______________________________

Texas	74-1492779
(State of incorporation)	(I.R.S. Employer Identification No.)
12377 Merit Drive Suite 1700, LB 82 Dallas, Texas	75251
(Address of principal executive offices)	(Zip Code)

(214) 368-2084

(Registrant’s telephone number, including area code)

______________________________

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

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

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

Large accelerated filer	x	Accelerated filer	o
Non-accelerated filer	o  (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  o    NO  x

The number of shares of common stock, par value $0.001 per share, outstanding as of October 24, 2012 was 216,659,769.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at September 30, 2012 and December 31, 2011	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011	2
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	2
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2012 and 2011	3
	Notes to Condensed Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	7
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27
Item 4.	Controls and Procedures	29
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
Item 6.	Exhibits	30
	Signatures	31

1

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	September 30, 2012			December 31, 2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	73,553		$	31,997
Restricted cash	67,306			155,925
Accounts receivable, net:
Oil and natural gas	63,443			88,518
Joint interest	58,886			170,918
Other	31,755			28,488
Inventory	6,591			8,345
Derivative financial instruments	57,997			164,002
Other	17,098			29,815
Total current assets	376,629			678,008
Equity investments	336,495			302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	546,477			667,342
Proved developed and undeveloped oil and natural gas properties	2,852,748			3,392,146
Accumulated depletion	(1,893,294		)	(1,657,165		)
Oil and natural gas properties, net	1,505,931			2,402,323
Gas gathering assets	130,792			136,203
Accumulated depreciation and amortization	(32,818		)	(29,104		)
Gas gathering assets, net	97,974			107,099
Office, field and other equipment, net	22,422			42,384
Deferred financing costs, net	23,938			29,622
Derivative financial instruments	8,391			11,034
Goodwill	218,256			218,256
Other assets	28			28
Total assets	$	2,590,064		$	3,791,587
See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)	September 30, 2012			December 31, 2011
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	96,888		$	117,968
Revenues and royalties payable	118,027			148,926
Accrued interest payable	3,233			17,973
Current portion of asset retirement obligations	732			732
Income taxes payable	—			—
Derivative financial instruments	2,948			1,800
Total current liabilities	221,828			287,399
Long-term debt	1,848,678			1,887,828
Deferred income taxes	—			—
Derivative financial instruments	34,542			—
Asset retirement obligations and other long-term liabilities	61,093			58,028
Commitments and contingencies	—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding	—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 217,154,647 shares issued and 216,615,426 shares outstanding at September 30, 2012; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011	215			215
Additional paid-in capital	3,196,871			3,181,063
Accumulated deficit	(2,765,684		)	(1,615,467		)
Treasury stock, at cost; 539,221 shares at September 30, 2012 and December 31, 2011	(7,479		)	(7,479		)
Total shareholders’ equity	423,923			1,558,332
Total liabilities and shareholders’ equity	$	2,590,064		$	3,791,587

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)	2012			2011			2012			2011
Revenues:
Oil and natural gas	$	141,621		$	207,274		$	394,447		$	575,330
Costs and expenses:
Oil and natural gas operating costs	17,425			21,101			59,084			60,843
Production and ad valorem taxes	6,689			6,653			20,671			18,700
Gathering and transportation	25,847			22,279			78,183			59,069
Depreciation, depletion and amortization	70,589			100,491			247,508			253,833
Write-down of oil and natural gas properties	318,044			—			1,022,709			—
Accretion of discount on asset retirement obligations	985			938			2,896			2,728
General and administrative	22,052			29,875			62,194			76,435
Other operating items	1,011			21,045			9,346			25,171
Total costs and expenses	462,642			202,382			1,502,591			496,779
Operating income (loss)	(321,021		)	4,892			(1,108,144		)	78,551
Other income (expense):
Interest expense	(17,935		)	(15,090		)	(55,068		)	(43,585		)
Gain (loss) on derivative financial instruments	(20,261		)	84,284			18,346			130,978
Other income	149			193			589			555
Equity income	12,894			10,666			20,021			22,749
Total other income (expense)	(25,153		)	80,053			(16,112		)	110,697
Income (loss) before income taxes	(346,174		)	84,945			(1,124,256		)	189,248
Income tax expense	—			—			—			—
Net income (loss)	$	(346,174	)	$	84,945		$	(1,124,256	)	$	189,248
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(1.62	)	$	0.40		$	(5.25	)	$	0.89
Weighted average common shares outstanding	214,301			214,068			214,204			213,831
Diluted:
Net income (loss)	$	(1.62	)	$	0.39		$	(5.25	)	$	0.87
Weighted average common and common equivalent shares outstanding	214,301			216,314			214,204			217,167

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(in thousands)	2012			2011
Operating Activities:
Net income (loss)	$	(1,124,256	)	$	189,248
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	247,508			253,833
Share-based compensation expense	8,072			7,537
Accretion of discount on asset retirement obligations	2,896			2,728
Write-down of oil and natural gas properties and other impairment losses on long-lived assets	1,022,709			6,800
Income from equity investments	(20,021		)	(22,749		)
Non-cash change in fair value of derivatives	144,339			(47,888		)
Deferred income taxes	—			—
Amortization of deferred financing costs and discount on the 2018 Notes	8,111			6,318
(Gain) loss on divestitures and sale of other assets	1,103			(1,071		)
Effect of changes in:
Accounts receivable	133,537			(82,803		)
Other current assets	6,019			(6,397		)
Accounts payable and other current liabilities	(15,240		)	49,778
Net cash provided by operating activities	414,777			355,334
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(409,616		)	(754,493		)
Property acquisitions	(2,748		)	(737,357		)
Equity method investments	(12,997		)	(13,969		)
Proceeds from disposition of property and equipment	22,640			428,332
Restricted cash	88,619			44,378
Net changes in advances (to) from Appalachia JV	6,849			3,306
Distributions from equity method investments	—			125,000
Deposit on acquisitions	—			464,151
Other	—			(5,750		)
Net cash used in investing activities	(307,253		)	(446,402		)
Financing Activities:
Borrowings under the EXCO Resources Credit Agreement	53,000			521,000
Repayments under the EXCO Resources Credit Agreement	(93,000		)	(397,500		)
Proceeds from issuance of common stock	1,397			11,776
Payment of common stock dividends	(25,740		)	(25,673		)
Deferred financing costs and other	(1,625		)	(6,346		)
Net cash provided by (used in) financing activities	(65,968		)	103,257
Net increase in cash	41,556			12,189
Cash at beginning of period	31,997			44,229
Cash at end of period	$	73,553		$	56,418
Supplemental Cash Flow Information:
Cash interest payments	$	78,447		$	70,758
Income tax payments	$	—		$	1,458
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	5,778		$	4,309
Capitalized interest	$	18,492		$	23,155
Issuance of common stock for director services	$	561		$	50
Accrued restricted stock dividends	$	221		$	—

See accompanying notes.

2

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common Stock				Treasury Stock					Additional paid-in capital		Accumulated deficit			Total shareholders’ equity
(in thousands)	Shares		Amount		Shares		Amount
Balance at December 31, 2010	213,736		$	214	(539	)	$	(7,479	)	$	3,151,513	$	(1,603,696	)	$	1,540,552
Issuance of common stock	908		1							11,825					11,826
Share-based compensation										11,846					11,846
Restricted stock issued, net of cancellations	667		—												—
Common stock dividends												(25,673		)	(25,673		)
Net income												189,248			189,248
Balance at September 30, 2011	215,311		$	215	(539	)	$	(7,479	)	$	3,175,184	$	(1,440,121	)	$	1,727,799
Balance at December 31, 2011	217,245		$	215	(539	)	$	(7,479	)	$	3,181,063	$	(1,615,467	)	$	1,558,332
Issuance of common stock	191		—							1,958					1,958
Share-based compensation										13,850					13,850
Restricted stock cancellations	(281	)	—												—
Common stock dividends												(25,961		)	(25,961		)
Net loss												(1,124,256		)	(1,124,256		)
Balance at September 30, 2012	217,155		$	215	(539	)	$	(7,479	)	$	3,196,871	$	(2,765,684	)	$	423,923

See accompanying notes.

3

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and basis of presentation

Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore U.S. oil and natural gas properties. Our principal operations are conducted in certain key U.S. oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia. Our midstream joint ventures are treated as a separate business segment.

Our primary strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and to leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content. Our shale resource plays and midstream operations are conducted through four joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows:

• East Texas/North Louisiana JV

A joint venture with BG Group covering an undivided 50% interest in a substantial portion of our assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale and conventional shallow producing assets, or the East Texas/North Louisiana JV. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating Company, LP, or EXCO Operating, serving as operator. We report the operating results and financial position of the East Texas/North Louisiana JV using proportional consolidation.

• TGGT

A joint venture with BG Group in which we each own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets. We use the equity method to account for our 50% investment in TGGT.

• Appalachia JV

A joint venture with BG Group covering our shallow producing assets and Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the joint venture's properties. The remaining 0.5% working interest is owned by a jointly owned operating entity, or OPCO, that manages the Appalachia JV operations. Under the terms of the joint development agreement, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $150.0 million, or the Appalachia Carry. As of September 30, 2012, the remaining balance of the Appalachia Carry was approximately $5.2 million. We use the equity method to account for our investment in OPCO and proportionally consolidate our 49.75% interest in the Appalachia JV.

• Appalachia Midstream JV

A joint venture with BG Group in which we each own a 50% interest in a midstream company, or the Appalachia Midstream JV, which will develop infrastructure and provide take-away capacity in the Marcellus shale. We use the equity method to account for our 50% investment in the Appalachia Midstream JV.

Our acquisition strategy for the past several years has been focused on the shale resources and consisted primarily of undeveloped acreage acquisitions. Our operations in the DeSoto Parish area of the Haynesville shale, or DeSoto Parish, are in the manufacturing phase and we have substantially completed our drilling activities to hold our acreage positions in Shelby, Nacogdoches and San Augustine Counties in East Texas, or the Shelby Area. Our Marcellus shale areas of interest have been identified and we have begun a development program in Northeast Pennsylvania and initiated an appraisal program in Central Pennsylvania. While we expect to continue to evaluate acquisition opportunities in our Haynesville/Bossier and Marcellus shale areas, we have also deployed our business development and technical staff to evaluate opportunities in new areas and additional joint venture opportunities in both existing and new areas. We are also evaluating certain divestitures to provide financial flexibility.

The accompanying Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011, Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months ended September 30, 2012 and 2011 are for EXCO and its subsidiaries. The condensed consolidated financial statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States, or GAAP.

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, 2012 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 consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 27, 2012.

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 accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 27, 2012.

3. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, 2012:

(in thousands)
Asset retirement obligations at January 1, 2012	$	58,088
Activity during the nine months ended September 30, 2012:
Liabilities incurred during the period	803
Liabilities settled during the period	(338		)
Adjustment to liability due to sales	(94		)
Accretion of discount	2,896
Asset retirement obligations at September 30, 2012	61,355
Less current portion	732
Long-term portion	$	60,623

Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. We have no assets that are legally restricted for purposes of settling asset retirement obligations.

4. Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $546.5 million and $667.3 million as of September 30, 2012 and December 31, 2011, respectively, and are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment and transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. We have impaired approximately $11.7 million of undeveloped properties during the first nine months of 2012.

When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, Subtopic835-20, Capitalization of Interest. We capitalize interest upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest.

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

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and Proved Reserves.

Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs, or ceiling test. The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling is less than the full cost pool, we must record a ceiling test write-down of our oil and natural gas properties to the value of the full cost ceiling. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying average price as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the period ended September 30, 2012, the trailing twelve month reference price was $94.97 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma, $49.62 per Bbl for natural gas liquids based on a percentage of the NYMEX oil price, and $2.83 per Mmbtu for natural gas at Henry Hub. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. 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 computations. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results. For the three and nine months ended September 30, 2012, we recognized a pre-tax ceiling test write-down of $318.0 million and $1,022.7 million, respectively, to our proved oil and natural gas properties. There were no ceiling test write-downs for the three and nine months ended September 30, 2011.

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

5. Earnings per share

We account for earnings per share in accordance with FASB ASC Subtopic 260-10, Earnings Per Share, or ASC 260-10. ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per share for the three and nine months ended September 30, 2012 and 2011 equals the net income divided by the weighted average common shares outstanding during the periods. Weighted average common shares outstanding is equal to the weighted average of all shares outstanding for the period, excluding restricted stock awards. Diluted earnings per common share for the three and nine months ended September 30, 2012 and 2011 are computed in the same manner as basic earnings per share after assuming the issuance of common stock for all potentially dilutive common stock equivalents, which include both stock options and restricted stock awards, whether exercisable or not. The computation of diluted earnings per share excluded 17,105,207 and 8,078,427 antidilutive common share equivalents for the three months ended September 30, 2012 and 2011, respectively, and 17,631,927 and 2,918,419 antidilutive common stock equivalents for the nine months ended September 30, 2012 and 2011, respectively.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share data)	2012			2011		2012			2011
Basic net income per common share:
Net income (loss)	$	(346,174	)	$	84,945	$	(1,124,256	)	$	189,248
Weighted average common shares outstanding	214,301			214,068		214,204			213,831
Net income (loss) per basic common share	$	(1.62	)	$	0.40	$	(5.25	)	$	0.89
Diluted net income per common share:
Net income (loss)	$	(346,174	)	$	84,945	$	(1,124,256	)	$	189,248
Weighted average common shares outstanding	214,301			214,068		214,204			213,831
Dilutive effect of:
Stock options	—			2,246		—			3,336
Restricted shares	—			—		—			—
Weighted average common and common equivalent shares outstanding	214,301			216,314		214,204			217,167
Net income (loss) per diluted common share	$	(1.62	)	$	0.39	$	(5.25	)	$	0.87

6. Derivative financial instruments

Our primary objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow in connection with our operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity 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.

We account for our derivative financial instruments in accordance with FASB ASC Topic 815, Derivatives and Hedging, or ASC 815, which 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. The table below outlines the classification of our derivative financial instruments on our Condensed Consolidated Balance Sheets and their financial impact in our Condensed Consolidated Statements of Operations.

Fair Value of Derivative Financial Instruments

(in thousands)	Balance Sheet location	September 30, 2012			December 31, 2011
Commodity contracts	Derivative financial instruments - Current assets	$	57,997		$	164,002
Commodity contracts	Derivative financial instruments - Long-term assets	8,391			11,034
Commodity contracts	Derivative financial instruments - Current liabilities	(2,948		)	(1,800		)
Commodity contracts	Derivative financial instruments - Long-term liabilities	(34,542		)	—
Net derivatives		$	28,898		$	173,236

Effect of Derivative Financial Instruments

		Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	Statements of Operations location	2012			2011		2012		2011
Commodity contracts (1)	Gain (loss) on derivative financial instruments	$	(20,261	)	$	84,284	$	18,346	$	130,978

(1) Included in these amounts are net cash receipts of $50,725 and $32,938 for the three months ended September 30, 2012 and 2011, respectively, and net cash receipts of $162,685 and $83,090 for the nine months ended September 30, 2012 and 2011, respectively.

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts are included in income with a corresponding increase or decrease in the Condensed Consolidated Balance Sheet fair value amounts. Unrealized fair value adjustments included in Gain (loss) on derivative financial instruments on the Condensed Consolidated Statement of Operations, which do not impact cash flows, were losses of $71.0 million and gains of $51.3 million for the three months ended September 30, 2012 and 2011, respectively, and losses of $144.3 million for the nine months ended September 30, 2012 and gains of $47.9 million for the nine months ended September 30, 2011.

Our natural gas and oil derivative instruments are comprised of swap and call option contracts. Swap contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In the second quarter of 2012, we entered into additional swap contracts and sold call options to certain counterparties.  Call options are financial contracts that give our trading counterparties the right, but not the obligation to buy an agreed quantity of natural gas from us at a certain time and price in the future. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. In exchange for selling this option, we received upfront proceeds which we used to obtain a higher fixed price on our swaps.   

We place our derivative financial instruments with the financial institutions that are lenders under the EXCO Resources Credit Agreement that we believe have high quality 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.

The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of September 30, 2012:

(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2012
Natural gas:
Swaps:
Remainder of 2012	20,240	$	5.27	$	39,178
2013	32,850	4.46		19,843
2014	27,375	4.25		1,828
2015	23,725	4.29		(1,794		)
Calls:
Remainder of 2012	—	—		—
2013	20,075	4.29		(4,406		)
2014	20,075	4.29		(9,391		)
2015	20,075	4.29		(13,281		)
Total natural gas	164,415			$	31,977
Oil:
Swaps:
Remainder of 2012	138	$	98.05	$	721
2013	365	99.96		2,238
2014	—	—		—
2015	—	—		—
Calls:
Remainder of 2012	—	—		—
2013	—	—		—
2014	365	100.00		(2,985		)
2015	365	100.00		(3,053		)
Total oil	1,233			$	(3,079	)
Total oil and natural gas derivatives				$	28,898

At December 31, 2011, we had outstanding derivative contracts to mitigate price volatility covering 85,995 Mmcf of natural gas and 275 Mbbls of oil. At September 30, 2012, the average forward NYMEX oil prices per Bbl for the remainder of 2012 and calendar years 2013, 2014 and 2015 were $92.72 and $93.70, $91.49 and $89.12, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2012 and calendar years 2013, 2014 and 2015 were $3.32 and $3.84, $4.18 and $4.37, respectively.

Our derivative financial instruments covered approximately 44.7% and 63.7% of production volumes for the three months ended September 30, 2012 and 2011, respectively, and approximately 42.8% and 57.6% of production volumes for the nine months ended September 30, 2012 and 2011, respectively.

7. Fair value measurements

We value our derivatives according to FASB ASC Topic 820, 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 categorize 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.

Fair value of derivative financial instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of September 30, 2012 and December 31, 2011. During the nine months ended September 30, 2012, there were no changes in the fair value level classifications.

	September 30, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	28,898	$	—	$	28,898
	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	173,236	$	—	$	173,236

We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis on the Condensed Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

The valuation of our commodity price derivatives, represented by oil and natural gas swaps, is discussed below.

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

Natural gas derivatives. Our natural gas derivatives are swap and call option contracts for notional Mmbtus of gas at posted price indexes, including NYMEX Henry Hub (HH) swap and call option contracts. 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 (iii) the applicable credit-adjusted risk-free rate curve, as described above and (iv) the implied rate of volatility inherent in the call option contracts. The implied rates of volatility were determined based on average NYMEX Henry Hub natural gas prices.

See further details on the fair value of our derivative financial instruments in “Note 6. Derivative financial instruments.”

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 carrying value of our EXCO Resources Credit Agreement approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods.

The estimated fair value of our 7.5% senior unsecured notes due September 15, 2018, or the 2018 Notes, for the periods ended September 30, 2012 and December 31, 2011 are presented below. The estimated fair value of the 2018 Notes has been calculated based on market quotes.

	September 30, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	702,750	$	—	$	—	$	702,750
	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	705,000	$	—	$	—	$	705,000

8. Long-term debt

Our total debt is summarized as follows:

(in thousands)	September 30, 2012			December 31, 2011
EXCO Resources Credit Agreement	$	1,107,500		$	1,147,500
2018 Notes	750,000			750,000
Unamortized discount on 2018 Notes	(8,822		)	(9,672		)
Total debt	$	1,848,678		$	1,887,828

Terms and conditions of each of these debt obligations are discussed below.

EXCO Resources Credit Agreement

As of September 30, 2012, the EXCO Resources Credit Agreement had a borrowing base of $1.4 billion, with $1.1 billion of outstanding indebtedness and $285.4 million of available borrowing capacity. On September 30, 2012, the one month LIBOR was 0.2%, which would result in an interest rate of approximately 2.7%. The borrowing base is redetermined semi-annually, with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. On April 27, 2012, we entered into the Sixth Amendment to the EXCO Resources Credit Agreement in conjunction with the regular semi-annual redetermination of the borrowing base and established the borrowing base at $1.4 billion, with an interest grid of LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps). Our consolidated funded debt to consolidated EBITDAX covenant, as defined in the agreement, increased to 4.5 to 1.0 from 4.0 to 1.0, effective at the end of any fiscal quarter ending on or after March 31, 2012. The Sixth Amendment also provided for asset sale procedures for sales of oil and natural gas properties or other material assets, including our interest in TGGT, whereby the proceeds from asset sales (over a minimum threshold) will be used to pay down the outstanding debt balance under the EXCO Resources Credit Agreement and will also reduce the borrowing base. The borrowing base reduction will be equal to the borrowing base value assigned to the assets sold (if any) plus cash proceeds in excess of the borrowing base value aggregating up to $200.0 million. We have not sold any assets that would reduce our borrowing base pursuant to the Sixth Amendment. The maturity date of the EXCO Resources Credit Agreement is April 1, 2016.

The majority of our subsidiaries are guarantors under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement permits investments, loans and advances to the unrestricted subsidiaries related to our joint ventures with certain limitations, and allows us to repurchase up to $200.0 million of our common stock, of which $7.5 million have been repurchased as of September 30, 2012.

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

The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common stock and provides that we may declare and pay cash dividends on our 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) we have at least 10% of our borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes.

As of September 30, 2012, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:

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

• not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2012.

While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement is sufficient to conduct our operations through 2013, there are certain risks arising from further declines in natural gas prices and production volumes that could impact our ability to meet debt covenants in future periods. In particular, our consolidated funded indebtedness to consolidated EBITDAX, as defined in the EXCO Resources Credit Agreement, is computed using the trailing twelve month EBITDAX. As a result, our ability to maintain compliance with this covenant may be negatively impacted when oil and/or natural gas prices decline for an extended period of time.

In addition to the covenants in the EXCO Resources Credit Agreement, the indenture governing our 2018 Notes contains a debt incurrence test on secured borrowings based on the greater of (i) $1.2 billion, subject to certain permanent reductions, or (ii) 75% of adjusted consolidated net tangible assets, or ACNTA, as defined in the indenture. A significant component of the ACNTA valuation is based on the PV-10 value of our Proved Reserves, computed using SEC pricing as of the beginning of each year. On January 1, 2012, the ACTNA limitation was $2.1 billion. We expect our January 1, 2013 ACNTA limitation to be reduced to the $1.2 billion limitation due to the significant decreases in 2012 natural gas prices used for SEC pricing. While ACNTA limits our ability to incur secured indebtedness, we are not prevented from incurring unsecured financing under the indenture.

In response to the declines in natural gas prices, we have reduced our drilling plans and we expect our production volumes will decrease during the remainder of 2012 and into 2013, and we have reduced operating and administrative expenses. The 2013 volumes of natural gas currently covered by derivative financial instruments are less than the volumes covered in 2012. We may enter into additional derivative financial instrument transactions as opportunities arise. The combination of a lower borrowing base, lower production volumes and reduced percentages of volumes covered by derivative financial instruments may result in our seeking alternative financing arrangements, further reducing costs or selling assets.

2018 Notes

The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group. Our equity investments with BG Group, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

As of September 30, 2012, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2012 was $8.8 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $702.8 million on September 30, 2012.

Interest accrues at 7.5% and is payable semi-annually in arrears on March 15th and September 15th of each year, beginning on March 15, 2011.

The indenture governing the 2018 Notes contains covenants, which may limit our ability and the ability of our restricted subsidiaries to:

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

• pay dividends on our capital stock (over $50.0 million per annum) or redeem, repurchase or retire our capital stock or subordinated debt;

• make certain 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.

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes.

9. Dividends

On September 4, 2012, our board of directors approved a cash dividend of $0.04 per share for the third quarter of 2012. The total cash dividend was $8.6 million, of which $8.6 million was paid on September 28, 2012 to holders of record on September 14, 2012 and $62,000 was accrued to be paid to restricted shareholders when their shares vest. Total dividends paid to our shareholders for the nine months ended September 30, 2012 were $26.0 million, of which $0.2 million will be paid to restricted shareholders when those shares vest.

Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the approval of our board of directors.

10. Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Also, we have tax net operating losses as a result of our drilling programs. For the three and nine months ended September 30, 2012, we estimate that we generated $136.3 million and $439.2 million, respectively, of valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $814.8 million as of September 30, 2012. The valuation allowances will continue to be recognized 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.

11. Segment information

We follow FASB ASC Topic 280, Segment Reporting, or ASC 280, when reporting operating segments. Pursuant to ASC 280, our reportable segments consist of exploration and production and midstream. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment, which consists of TGGT and the Appalachia Midstream JV, is accounted for using the equity method and is responsible for purchasing, gathering, transporting and treating natural gas.

Prior to formation of TGGT in August 2009, our reportable segments consisted of exploration and production and wholly-owned midstream subsidiaries that were consolidated in our financial statements. We evaluated the performance of our operating segments based on segment profits, which include segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and direct segment costs and expenses. Segment profit excludes items such as income taxes, interest income, interest expense, corporate expenses, write-down of oil and natural gas properties, depreciation and depletion and other items.

At the formation of TGGT on August 14, 2009, we determined that our midstream segment was no longer required due to the 50% reduction in the midstream segment’s profits and the application of equity method accounting. Due to the significant capital investments and growth within TGGT since its inception and the expected growth of the Appalachia Midstream JV, as of December 31, 2011, we designated our midstream equity investments as a reportable segment. As a result of the designation of the midstream segment, we have recast the three and nine months ended September 30, 2011 to reflect midstream as a segment. Our management evaluates TGGT’s and the Appalachia Midstream JV’s performance on a stand alone basis. The revenues and expenses used to compute the midstream’s segment profit represent TGGT’s and Appalachia Midstream’s results of operations without regard to our 50% ownership. Since we use the equity method of accounting for TGGT, we eliminate these revenues and expenses when reconciling to our consolidated results of operations and report our net share of midstream’s operations as equity income (loss). See “Note. 12—Equity investments” for additional details related to our equity investments, including our midstream segment.

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

4

(in thousands)	Exploration and production			Midstream		Equity investee and intercompany eliminations			Consolidated total
For the three months ended September 30, 2012:
Third party revenues	$	141,621		$	64,716	$	(64,716	)	$	141,621
Intersegment revenues	—			—		—			—
Total revenues	$	141,621		$	64,716	$	(64,716	)	$	141,621
Segment profit	$	91,660		$	48,493	$	(48,493	)	$	91,660
Equity income	$	1,668		$	11,226	$	—		$	12,894
For the three months ended September 30, 2011:
Third party revenues	$	207,274		$	64,180	$	(64,180	)	$	207,274
Intersegment revenues	—			—		—			—
Total revenues	$	207,274		$	64,180	$	(64,180	)	$	207,274
Segment profit	$	157,241		$	35,170	$	(35,170	)	$	157,241
Equity income	$	220		$	10,446	$	—		$	10,666
For the nine months ended September 30, 2012:
Third party revenues	$	394,447		$	191,572	$	(191,572	)	$	394,447
Intersegment revenues	—			—		—			—
Total revenues	$	394,447		$	191,572	$	(191,572	)	$	394,447
Segment profit	$	236,509		$	139,971	$	(139,971	)	$	236,509
Equity income (loss)	$	(77	)	$	20,098	$	—		$	20,021
For the nine months ended September 30, 2011:
Third party revenues	$	575,330		$	179,820	$	(179,820	)	$	575,330
Intersegment revenues	—			—		—			—
Total revenues	$	575,330		$	179,820	$	(179,820	)	$	575,330
Segment profit	$	436,718		$	99,500	$	(99,500	)	$	436,718
Equity income (loss)	$	337		$	22,412	$	—		$	22,749
As of September 30, 2012
Capital expenditures	$	375,396		$	113,577	$	(113,577	)	$	375,396
Goodwill	$	218,256		$	—	$	—		$	218,256
Total assets	$	2,590,064		$	1,275,190	$	(1,275,190	)	$	2,590,064
As of December 31, 2011
Capital expenditures	$	1,001,206		$	284,288	$	(284,288	)	$	1,001,206
Goodwill	$	218,256		$	—	$	—		$	218,256
Total assets	$	3,791,587		$	1,255,977	$	(1,255,977	)	$	3,791,587

5

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)	2012			2011			2012			2011
Segment profits	$	91,660		$	157,241		$	236,509		$	436,718
Depreciation, depletion and amortization	(70,589		)	(100,491		)	(247,508		)	(253,833		)
Write-down of oil and natural gas properties	(318,044		)	—			(1,022,709		)	—
Accretion of discount on asset retirement obligations	(985		)	(938		)	(2,896		)	(2,728		)
General and administrative	(22,052		)	(29,875		)	(62,194		)	(76,435		)
Other operating items	(1,011		)	(21,045		)	(9,346		)	(25,171		)
Interest expense	(17,935		)	(15,090		)	(55,068		)	(43,585		)
Gain (loss) on derivative financial instruments	(20,261		)	84,284			18,346			130,978
Other income	149			193			589			555
Equity income	12,894			10,666			20,021			22,749
Income (loss) before income taxes	$	(346,174	)	$	84,945		$	(1,124,256	)	$	189,248

12. Equity investments

We hold equity investments in four entities with BG Group, which are described below. We use the equity method of accounting for each investment.

• We have a 50% ownership in TGGT, which holds interests in midstream assets in East Texas and North Louisiana. In the first quarter of 2012, TGGT recorded an impairment of approximately $35.3 million of certain assets (approximately $17.7 million net to us) associated with the installation of temporary treating facilities in response to an incident at a TGGT amine treating facility in May 2011. After completion of an independent engineering study, the decision was made to activate the permanent facility affected by the incident since that facility had not sustained as much damage as was initially contemplated. The impairment primarily resulted from costs incurred related to temporary treating facilities that were not utilized or determined to have a shorter utilization period than originally anticipated. In addition, lower than expected throughput volumes at the facility as a result of reduced drilling contributed to the impairment. During the nine months ended September 30, 2012, EXCO and BG Group each contributed $0.6 million in assets to TGGT.

• We own a 50% interest in OPCO, which operates the Appalachia JV properties, subject to oversight from a management board having equal representation from EXCO and BG Group. During the nine months ended September 30, 2012, EXCO and BG Group each contributed $13.0 million to OPCO, which is equal to OPCO’s 0.5% interest in any property acquisitions and the capital contributions for OPCO’s drilling, facilities and operating budget requirements.

• We own a 50% interest in the Appalachia Midstream JV, through which we and BG Group will pursue the construction and expansion of gathering systems for anticipated future production from the Marcellus shale.

• We own a 50% interest in an entity that manages certain surface acreage.

The following tables present summarized consolidated financial information of our equity investments and a reconciliation of our investment to our proportionate 50% interest.

(in thousands)	September 30, 2012		December 31, 2011
Assets
Total current assets	$	153,390	$	227,911
Property and equipment, net	1,231,150		1,173,642
Other assets	8,282		6,570
Total assets	$	1,392,822	$	1,408,123
Liabilities and members’ equity
Total current liabilities	$	112,049	$	256,794
Total long term liabilities	527,604		462,669
Members’ equity:
Total members' equity	753,169		688,660
Total liabilities and members’ equity	$	1,392,822	$	1,408,123

	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2012		2011			2012		2011
Revenues
Oil and natural gas	$	115	$	130		$	307	$	386
Midstream	64,716		64,180			191,572		179,820
Total revenues	64,831		64,310			191,879		180,206
Costs and expenses:
Oil and natural gas production	60		17			176		21
Midstream operating	16,223		29,010			51,601		80,320
Write-down of oil and natural gas properties	—		—			1,230		—
Asset impairments, net of insurance recoveries	4,618		(4,282		)	39,961		9,178
General and administrative	5,522		5,240			19,275		15,620
Depreciation, depletion, and amortization	11,314		7,511			29,676		21,022
Other expenses	2,212		6,021			12,432		10,243
Total costs and expenses	39,949		43,517			154,351		136,404
Income before income taxes	24,882		20,793			37,528		43,802
Income tax expense	31		399			299		1,118
Net income	$	24,851	$	20,394		$	37,229	$	42,684
EXCO’s share of equity income before amortization	$	12,425	$	10,197		$	18,614	$	21,342
Amortization of the difference in the historical basis of our contribution	$	469	$	469		$	1,407	$	1,407
EXCO’s share of equity income after amortization	$	12,894	$	10,666		$	20,021	$	22,749

(in thousands)	September 30, 2012			December 31, 2011
Equity investments	$	336,495		$	302,833
Basis adjustment (1)	45,755			45,755
Cumulative amortization of basis adjustment (2)	(5,665		)	(4,258		)
EXCO’s 50% interest in equity investments	$	376,585		$	344,330

(1) Our equity in TGGT and OPCO, at inception, exceeded the book value of our investments by an aggregate of $45.8 million, comprised of an aggregate $57.2 million difference in the historical basis of our contribution and the fair value of BG Group’s contribution, offset by $11.4 million of goodwill included in our investment in TGGT.

(2) The aggregate $57.2 million basis difference is being amortized over the estimated life of the associated assets.

13. Related party transactions

TGGT provides us with gathering, treating and well connect services in the ordinary course of business. In addition, TGGT also purchases natural gas from us in certain areas. OPCO serves as the operator of our wells in the Appalachia JV. There are service agreements between us and TGGT and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three and nine months ended September 30, 2012 and 2011, these transactions included the following:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2012				2011				2012				2011
(in thousands)	TGGT		OPCO		TGGT		OPCO		TGGT		OPCO		TGGT		OPCO
Amounts paid:
Gathering, treating and well connect fees (1)	$	58,027			$	38,800			$	166,851			$	144,236
Advances to operator			$	31,805			$	14,423			$	58,582			$	38,084
Amounts received:
Natural gas purchases	3,390				8,227				12,115				24,451
General and administrative services	4,170		11,967		4,197		12,958		14,209		40,685		11,090		32,985
Purchase of gathering and other assets	—				—				—				3,422
Other	210				853				1,654				1,255
Total	$	7,770	$	11,967	$	13,277	$	12,958	$	27,978	$	40,685	$	40,218	$	32,985

(1) Represents the gross billings from TGGT.

As of September 30, 2012 and December 31, 2011, the amounts owed under the service agreements were as follows:

	September 30, 2012				December 31, 2011
(in thousands)	TGGT		OPCO		TGGT		OPCO
Amounts due to EXCO	$	2,493	$	3,939	$	8,236	$	8,178
Amounts due from EXCO (1)	17,017		127		39,422		—

(1) As OPCO is the operator of our wells in the Appalachia JV, we advance funds to OPCO on an as needed basis, which are included in Other current assets on our Condensed Consolidated Balance Sheets. Any amounts we owe are netted against the advance until the advances are utilized. If the advances are fully utilized, we record amounts owed in Accounts payable and accrued liabilities on our Condensed Consolidated Balance Sheets.

14. Subsequent event

On October 30, 2012, our banking group approved the Seventh Amendment to the EXCO Resources Credit Agreement, which established our borrowing base at $1.3 billion and, among other things, removed the mandatory asset sale procedures contained in the Sixth Amendment. There were no changes to the interest grid or covenants.

15. Condensed consolidating financial statements

As of September 30, 2012, the majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes. All of our non-guarantor subsidiaries are considered unrestricted subsidiaries under the indenture governing the 2018 Notes, with the exception of our equity investment in OPCO. As of and for the nine months ended September 30, 2012:

• Our equity method investment in OPCO represented $15.3 million of equity method investments and contributed $0.1 million of equity method losses; and

• Our interests in jointly held entities with BG Group, with the exception of OPCO, represented $321.2 million of equity method investments, or 12.4% of our total assets and contributed $20.1 million of equity method income.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some of our subsidiaries (referred to as Guarantor Subsidiaries). For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries. Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries.

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

• Resources;

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries;

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

• EXCO on a consolidated basis.

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

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	92,629		$	(19,076	)	$	—		$	—	$	73,553
Restricted cash	—			67,306			—			—		67,306
Other current assets	73,858			161,912			—			—		235,770
Total current assets	166,487			210,142			—			—		376,629
Equity investments	—			—			336,495			—		336,495
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	11,624			534,853			—			—		546,477
Proved developed and undeveloped oil and natural gas properties	501,946			2,350,802			—			—		2,852,748
Accumulated depletion	(330,572		)	(1,562,722		)	—			—		(1,893,294		)
Oil and natural gas properties, net	182,998			1,322,933			—			—		1,505,931
Gas gathering, office, field and other equipment, net	9,014			111,382			—			—		120,396
Investments in and advances to affiliates	(243,891		)	—			—			243,891		—
Deferred financing costs, net	23,938			—			—			—		23,938
Derivative financial instruments	7,150			1,241			—			—		8,391
Goodwill	38,100			180,156			—			—		218,256
Other assets	1			27			—			—		28
Total assets	$	183,797		$	1,825,881		$	336,495		$	243,891	$	2,590,064
Liabilities and shareholders' equity
Current liabilities	$	31,286		$	190,542		$	—		$	—	$	221,828
Long-term debt	1,848,678			—			—			—		1,848,678
Deferred income taxes	—			—			—			—		—
Other long-term liabilities	42,667			52,968			—			—		95,635
Payable to parent	(2,162,757		)	2,168,913			(6,156		)	—		—
Total shareholders' equity	423,923			(586,542		)	342,651			243,891		423,923
Total liabilities and shareholders' equity	$	183,797		$	1,825,881		$	336,495		$	243,891	$	2,590,064

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	78,664		$	(46,667	)	$	—		$	—		$	31,997
Restricted cash	—			155,925			—			—			155,925
Other current assets	177,709			312,377			—			—			490,086
Total current assets	256,373			421,635			—			—			678,008
Equity investments	—			—			302,833			—			302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	15,942			651,400			—			—			667,342
Proved developed and undeveloped oil and natural gas properties	464,898			2,927,248			—			—			3,392,146
Accumulated depletion	(327,218		)	(1,329,947		)	—			—			(1,657,165		)
Oil and natural gas properties, net	153,622			2,248,701			—			—			2,402,323
Gas gathering, office, field and other equipment, net	27,815			121,668			—			—			149,483
Investments in and advances to affiliates	869,387			—			—			(869,387		)	—
Deferred financing costs, net	29,622			—			—			—			29,622
Derivative financial instruments	5,998			5,036			—			—			11,034
Goodwill	38,100			180,156			—			—			218,256
Other assets	3			25			—			—			28
Total assets	$	1,380,920		$	2,977,221		$	302,833		$	(869,387	)	$	3,791,587
Liabilities and shareholders' equity
Current liabilities	$	39,395		$	248,004		$	—		$	—		$	287,399
Long-term debt	1,887,828			—			—			—			1,887,828
Deferred income taxes	—			—			—			—			—
Other long-term liabilities	7,740			50,288			—			—			58,028
Payable to parent	(2,112,375		)	2,118,531			(6,156		)	—			—
Total shareholders' equity	1,558,332			560,398			308,989			(869,387		)	1,558,332
Total liabilities and shareholders' equity	$	1,380,920		$	2,977,221		$	302,833		$	(869,387	)	$	3,791,587

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries		Eliminations		Consolidated
Revenues:
Oil and natural gas	$	18,815		$	122,806		$	—	$	—	$	141,621
Costs and expenses:
Oil and natural gas production	4,856			19,258			—		—		24,114
Gathering and transportation	—			25,847			—		—		25,847
Depreciation, depletion and amortization	8,848			61,741			—		—		70,589
Write-down of oil and natural gas properties	—			318,044			—		—		318,044
Accretion of discount on asset retirement obligations	134			851			—		—		985
General and administrative	4,761			17,291			—		—		22,052
Other operating items	(182		)	1,193			—		—		1,011
Total costs and expenses	18,417			444,225			—		—		462,642
Operating income (loss)	398			(321,419		)	—		—		(321,021		)
Other income (expense):
Interest expense	(17,935		)	—			—		—		(17,935		)
Loss on derivative financial instruments	(19,674		)	(587		)	—		—		(20,261		)
Other income	78			71			—		—		149
Income from equity investments	—			—			12,894		—		12,894
Equity in earnings of subsidiaries	(309,041		)	—			—		309,041		—
Total other income (expense)	(346,572		)	(516		)	12,894		309,041		(25,153		)
Income (loss) before income taxes	(346,174		)	(321,935		)	12,894		309,041		(346,174		)
Income tax expense	—			—			—		—		—
Net income (loss)	$	(346,174	)	$	(321,935	)	$	12,894	$	309,041	$	(346,174	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	22,725		$	184,549		$	—		$	—		$	207,274
Costs and expenses:
Oil and natural gas production	4,987			22,767			—			—			27,754
Gathering and transportation	1			22,278			—			—			22,279
Depreciation, depletion and amortization	11,609			88,733			149			—			100,491
Accretion of discount on asset retirement obligations	113			825			—			—			938
General and administrative	10,059			19,816			—			—			29,875
Other operating items	15,753			5,568			(276		)	—			21,045
Total costs and expenses	42,522			159,987			(127		)	—			202,382
Operating income (loss)	(19,797		)	24,562			127			—			4,892
Other income (expense):
Interest expense	(15,089		)	(1		)	—			—			(15,090		)
Gain on derivative financial instruments	74,063			10,221			—			—			84,284
Other income	77			116			—			—			193
Income from equity investments	—			—			10,666			—			10,666
Equity in earnings of subsidiaries	45,691			—			—			(45,691		)	—
Total other income (expense)	104,742			10,336			10,666			(45,691		)	80,053
Income (loss) before income taxes	84,945			34,898			10,793			(45,691		)	84,945
Income tax expense	—			—			—			—			—
Net income (loss)	$	84,945		$	34,898		$	10,793		$	(45,691	)	$	84,945

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries		Eliminations		Consolidated
Revenues:
Oil and natural gas	$	61,079		$	333,368		$	—	$	—	$	394,447
Costs and expenses:
Oil and natural gas production	14,735			65,020			—		—		79,755
Gathering and transportation	—			78,183			—		—		78,183
Depreciation, depletion and amortization	8,376			239,132			—		—		247,508
Write-down of oil and natural gas properties	—			1,022,709			—		—		1,022,709
Accretion of discount on asset retirement obligations	390			2,506			—		—		2,896
General and administrative	9,330			52,864			—		—		62,194
Other operating items	(163		)	9,509			—		—		9,346
Total costs and expenses	32,668			1,469,923			—		—		1,502,591
Operating income (loss)	28,411			(1,136,555		)	—		—		(1,108,144		)
Other income (expense):
Interest expense	(55,065		)	(3		)	—		—		(55,068		)
Gain on derivative financial instruments	15,505			2,841			—		—		18,346
Other income	171			418			—		—		589
Income from equity investments	—			—			20,021		—		20,021
Equity in earnings of subsidiaries	(1,113,278		)	—			—		1,113,278		—
Total other income (expense)	(1,152,667		)	3,256			20,021		1,113,278		(16,112		)
Income (loss) before income taxes	(1,124,256		)	(1,133,299		)	20,021		1,113,278		(1,124,256		)
Income tax expense	—			—			—		—		—
Net income (loss)	$	(1,124,256	)	$	(1,133,299	)	$	20,021	$	1,113,278	$	(1,124,256	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	70,115		$	505,215		$	—		$	—		$	575,330
Costs and expenses:
Oil and natural gas production	14,334			65,209			—			—			79,543
Gathering and transportation	1			59,068			—			—			59,069
Depreciation, depletion and amortization	25,379			227,501			953			—			253,833
Accretion of discount on asset retirement obligations	321			2,407			—			—			2,728
General and administrative	19,375			57,061			(1		)	—			76,435
Other operating items	20,355			6,098			(1,282		)	—			25,171
Total costs and expenses	79,765			417,344			(330		)	—			496,779
Operating income (loss)	(9,650		)	87,871			330			—			78,551
Other income (expense):
Interest expense	(42,326		)	(1,259		)	—			—			(43,585		)
Gain on derivative financial instruments	113,670			17,308			—			—			130,978
Other income	262			293			—			—			555
Income from equity investments	—			—			22,749			—			22,749
Equity in earnings of subsidiaries	127,292			—			—			(127,292		)	—
Total other income (expense)	198,898			16,342			22,749			(127,292		)	110,697
Income (loss) before income taxes	189,248			104,213			23,079			(127,292		)	189,248
Income tax expense	—			—			—			—			—
Net income (loss)	$	189,248		$	104,213		$	23,079		$	(127,292	)	$	189,248

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2012

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	143,678		$	271,099		$	—	$	—	$	414,777
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(29,772		)	(382,592		)	—		—		(412,364		)
Restricted cash	—			88,619			—		—		88,619
Equity method investments	—			(12,997		)	—		—		(12,997		)
Proceeds from disposition of property and equipment	15,390			7,250			—		—		22,640
Distributions from equity method investments	—			—			—		—		—
Deposit on acquisitions	—			—			—		—		—
Net changes in advances (to) from Appalachia JV	—			6,849			—		—		6,849
Advances/investments with affiliates	(49,363		)	49,363			—		—		—
Other	—			—			—		—		—
Net cash used in investing activities	(63,745		)	(243,508		)	—		—		(307,253		)
Financing Activities:
Borrowings under the EXCO Resources Credit Agreement	53,000			—			—		—		53,000
Repayments under the EXCO Resources Credit Agreement	(93,000		)	—			—		—		(93,000		)
Proceeds from issuance of common stock	1,397			—			—		—		1,397
Payment of common stock dividends	(25,740		)	—			—		—		(25,740		)
Deferred financing costs and other	(1,625		)	—			—		—		(1,625		)
Net cash used in financing activities	(65,968		)	—			—		—		(65,968		)
Net increase (decrease) in cash	13,965			27,591			—		—		41,556
Cash at beginning of period	78,664			(46,667		)	—		—		31,997
Cash at end of period	$	92,629		$	(19,076	)	$	—	$	—	$	73,553

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-guarantor subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	61,069		$	293,094		$	1,171		$	—	$	355,334
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(51,201		)	(1,436,396		)	(4,253		)	—		(1,491,850		)
Restricted cash	—			44,378			—			—		44,378
Equity method investments	—			(13,969		)	—			—		(13,969		)
Proceeds from disposition of property and equipment	3,128			425,204			—			—		428,332
Distributions from equity method investments	—			125,000			—			—		125,000
Deposit on acquisitions	—			464,151			—			—		464,151
Net changes in advances (to) from Appalachia JV	—			3,306			—			—		3,306
Advances/investments with affiliates	(113,717		)	110,635			3,082			—		—
Other	—			(5,750		)	—			—		(5,750		)
Net cash used in investing activities	(161,790		)	(283,441		)	(1,171		)	—		(446,402		)
Financing Activities:
Borrowings under the EXCO Resources Credit Agreement	521,000			—			—			—		521,000
Repayments under the EXCO Resources Credit Agreement	(397,500		)	—			—			—		(397,500		)
Proceeds from issuance of common stock	11,776			—			—			—		11,776
Payment of common stock dividends	(25,673		)	—			—			—		(25,673		)
Deferred financing costs and other	(6,346		)	—			—			—		(6,346		)
Net cash provided by financing activities	103,257			—			—			—		103,257
Net increase (decrease) in cash	2,536			9,653			—			—		12,189
Cash at beginning of period	76,763			(32,534		)	—			—		44,229
Cash at end of period	$	79,299		$	(22,881	)	$	—		$	—	$	56,418

6

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

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.

Forward-looking statements

This Quarterly Report on Form 10-Q 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 for oil, natural gas and natural gas liquids;

• 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 our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise any forward-looking statements, except as required by applicable securities laws. 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 on Form 10-Q, including, but not limited to:

• fluctuations in prices of oil, natural gas and natural gas liquids;

• non-cash ceiling test write-downs due to declines in natural gas prices;

• production declines, particularly from our horizontal shale wells;

• imports, exports and inventories of oil and natural gas, including liquefied natural gas;

• future capital requirements and availability of financing;

• 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 risks related to our Marcellus shale play in Appalachia and the Haynesville and Bossier shale plays in East Texas/North Louisiana;

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

• 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 greenhouse gas emissions, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;

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

7

• decisions whether or not to enter into derivative financial instruments;

• potential acts of terrorism;

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

• fluctuations in interest rates; and

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

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned to not place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the cautionary statements in this Quarterly Report on Form 10-Q, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the Securities and Exchange Commission, or the SEC, on February 27, 2012.

Our revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from the EXCO Resources Credit Agreement. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview and history

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore U.S. oil and natural gas properties. Our principal operations are conducted in certain key U.S. oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia. Our midstream joint ventures are treated as a separate business segment.

Our primary strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content. Our shale resource plays and midstream operations are conducted through four joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows.

• East Texas/North Louisiana JV

A joint venture with BG Group covering an undivided 50% interest in a substantial portion of our assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale and conventional shallow producing assets, or the East Texas/North Louisiana JV. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating Company, LP, or EXCO Operating, serving as operator. We report the operating results and financial position of the East Texas/North Louisiana JV using proportional consolidation.

• TGGT

A joint venture with BG Group in which we each own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets. We use the equity method to account for our 50% investment in TGGT.

• Appalachia JV

A joint venture with BG Group covering our shallow producing assets and Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the joint venture's properties. The remaining 0.5% working interest is owned by a jointly owned operating entity, or OPCO, that manages the Appalachia JV operations. Under the terms of the joint development agreement, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $150.0 million, or the Appalachia Carry. As of September 30, 2012, the remaining balance of the Appalachia Carry was approximately $5.2 million. We use the equity method to account for our investment in OPCO and proportionally consolidate our 49.75% interest in the Appalachia JV.

• Appalachia Midstream JV

A joint venture with BG Group in which we each own a 50% interest in a midstream company, or the Appalachia Midstream JV, which will develop infrastructure and provide take-away capacity in the Marcellus shale. We use the equity method to account for our 50% investment in the Appalachia Midstream JV.

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Our acquisition strategy for the past several years has been focused on the shale resources and consisted primarily of undeveloped acreage acquisitions. Our operations in the DeSoto Parish area of the Haynesville shale, or DeSoto Parish, are in the manufacturing phase and we have substantially completed our drilling activities to hold our acreage positions in Shelby, Nacogdoches and San Augustine Counties in East Texas, or the Shelby Area. Our Marcellus shale areas of interest have been identified and we have begun a development program in Northeast Pennsylvania and initiated an appraisal program in Central Pennsylvania. While we expect to continue to evaluate acquisition opportunities in our Haynesville/Bossier and Marcellus shale areas, we have also deployed our business development and technical staff to evaluate opportunities in new areas, along with seeking out joint venture opportunities in both existing and new areas. We are also evaluating certain divestitures to provide financial flexibility.

Our plans for 2012 emphasize cost containment of operating and administrative expenses and reduction of drilling costs in response to a low natural gas price environment. In February 2012, we reduced our expected capital expenditure budget by 33.8% and we continue to evaluate the feasibility and pace of drilling projects. We have reduced our operated drilling rigs in the Haynesville/Bossier shale from 22 during the fourth quarter of 2011 to five in October 2012. In the Marcellus shale, we expect to operate one drilling rig during the remainder of 2012 compared to an original drilling program of five rigs in 2012. Our forecasted capital expenditures for 2012 presently total $470.0 million, of which $384.0 million is allocated to our East Texas/North Louisiana and Appalachia regions. In East Texas and North Louisiana, our capital expenditures for the East Texas/North Louisiana JV are expected to total $286.0 million in 2012. During the first nine months of 2012, we spent $247.2 million in East Texas/North Louisiana, $242.7 million of which was in the area of mutual interest with BG Group, or the East Texas/North Louisiana AMI. In Appalachia, our share of planned capital expenditures for the Appalachia JV in 2012 are expected to total $92.0 million, which excludes $54.6 million of the Appalachia Carry. During the first nine months of 2012, we spent $64.6 million in Appalachia, which reflects the favorable impact from the Appalachia Carry. As of September 30, 2012, the remaining balance of the Appalachia Carry was approximately $5.2 million. We continue to operate one drilling rig in our Permian area.

For 2012, TGGT’s capital expenditure budget totals approximately $132.0 million, of which approximately $107.8 million was spent in the first nine months of 2012 primarily focusing on completing treating facilities in DeSoto Parish and the Shelby Area and completing pipeline infrastructure, particularly in the Shelby Area. TGGT's management believes cash flows from operations and borrowing capacity under its credit agreement will be sufficient to fund its 2012 capital expenditure programs.

We do not expect to make significant capital contributions during the remainder of 2012 to our Appalachia Midstream JV as much of our Northeast Pennsylvania development drilling program utilizes an existing third party gathering system.

In the second quarter of 2012, we began reporting our natural gas liquids production in our Permian division separately from our natural gas production. We have recast prior periods to conform to this presentation.

Like all oil and natural gas exploration and 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 offset the impact of this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions. As a result of our reduced drilling programs in response to low natural gas prices, we expect our production volumes to decline in 2013.

Critical accounting policies

We consider accounting policies related to our estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, revenue recognition and gas imbalances, deferred abandonment on asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 27, 2012.

Our results of operations

A summary of key financial data for the three and nine months ended September 30, 2012 and 2011 related to our results of operations is presented below:

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	Three Months Ended September 30,					Quarter to quarter change			Nine Months Ended September 30,					Period to period change
(dollars in thousands, except per unit prices)	2012			2011					2012			2011
Production:
Oil (Mbbls)	170			182		(12		)	544			553		(9		)
Natural gas liquids (Mbbls)	129			131		(2		)	382			379		3
Natural gas (Mmcf)	45,330			48,178		(2,848		)	140,484			127,395		13,089
Total production (Mmcfe) (1)	47,124			50,056		(2,932		)	146,040			132,987		13,053
Average daily production (Mmcfe)	512			544		(32		)	533			487		46
Revenues before derivative financial instrument activities:
Oil	$	14,768		$	15,596	$	(828	)	$	49,139		$	50,618	$	(1,479	)
Natural gas liquids	4,984			7,851		(2,867		)	16,697			21,958		(5,261		)
Natural gas	121,869			183,827		(61,958		)	328,611			502,754		(174,143		)
Total revenue	$	141,621		$	207,274	$	(65,653	)	$	394,447		$	575,330	$	(180,883	)
Oil and natural gas derivative financial instruments:
Cash settlements (payments) on derivative financial instruments	$	50,725		$	32,938	$	17,787		$	162,685		$	83,090	$	79,595
Non-cash change in fair value of derivative financial instruments	(70,986		)	51,346		(122,332		)	(144,339		)	47,888		(192,227		)
Total derivative financial instrument activities	$	(20,261	)	$	84,284	$	(104,545	)	$	18,346		$	130,978	$	(112,632	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	86.87		$	85.69	$	1.18		$	90.33		$	91.53	$	(1.20	)
Natural gas liquids (per Bbl)	38.64			59.93		(21.29		)	43.71			57.94		(14.23		)
Natural gas (per Mcf)	2.69			3.82		(1.13		)	2.34			3.95		(1.61		)
Natural gas equivalent (per Mcfe)	3.01			4.14		(1.13		)	2.70			4.33		(1.63		)
Costs and expenses:
Oil and natural gas operating costs (2)	$	17,425		$	21,101	$	(3,676	)	$	59,084		$	60,843	$	(1,759	)
Production and ad valorem taxes	6,689			6,653		36			20,671			18,700		1,971
Gathering and transportation	25,847			22,279		3,568			78,183			59,069		19,114
Depletion	67,098			95,949		(28,851		)	236,129			239,956		(3,827		)
Depreciation and amortization	3,491			4,542		(1,051		)	11,379			13,877		(2,498		)
General and administrative (3)	22,052			29,875		(7,823		)	62,194			76,435		(14,241		)
Interest expense	17,935			15,090		2,845			55,068			43,585		11,483
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.37		$	0.42	$	(0.05	)	$	0.40		$	0.46	$	(0.06	)
Production and ad valorem taxes	0.14			0.13		0.01			0.14			0.14		—
Gathering and transportation	0.55			0.45		0.10			0.54			0.44		0.10
Depletion	1.42			1.92		(0.50		)	1.62			1.80		(0.18		)
Depreciation and amortization	0.07			0.09		(0.02		)	0.08			0.10		(0.02		)
General and administrative	0.47			0.60		(0.13		)	0.43			0.57		(0.14		)
Net income (loss)	$	(346,174	)	$	84,945	$	(431,119	)	$	(1,124,256	)	$	189,248	$	(1,313,504	)

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

(2) Share-based compensation expense included in oil and natural gas operating costs was $0.0 million and $0.1 million for the three and nine months ended September 30, 2011, respectively. There was no share-based compensation expense included in oil and natural gas operating costs for the three and nine months ended September 30, 2012.

(3) Share-based compensation expense included in general and administrative expenses was $2.6 million and $2.4 million for the three months ended September 30, 2012 and 2011, respectively, and $8.1 million and $7.4 million for the nine months ended September 30, 2012 and 2011, respectively.

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Following is a discussion of our financial condition and results of operations for the three and nine months ended September 30, 2012 and 2011. The comparability of our results of operations from period to period was impacted by:

• acquisitions in the Marcellus and Haynesville shale during 2011;

• costs associated with a former acquisition proposal and other non-recurring costs;

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

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

• changes in Proved Reserves and production volumes and their impact on depletion;

• the equity method of accounting for our investments, including certain asset impairments in TGGT;

• the impact of our natural gas production volumes from our horizontal drilling activities in the Haynesville/Bossier and Marcellus shales;

• ceiling test write-downs in 2012; and

• changes in the amount of our long-term debt.

General

The availability of a ready market for oil and natural gas and the prices of oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:

• the level of domestic production and economic activity;

• the current domestic oversupply of natural gas;

• the ability to export domestic oil and natural gas;

• the level of domestic and industrial demand for natural gas for utilities and manufacturing operations;

• the available capacity at natural gas storage facilities and quantities of inventories in storage;

• 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 exploration, 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. Some of our natural gas is sold under contracts which provide for sharing in a percentage of proceeds of natural gas liquids extracted by third party plants.

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 pricing and contractual terms. Changes in oil or natural gas prices may significantly affect our

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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. If this occurs, companies purchasing oil or natural gas in these areas may 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 oil or natural gas reserves, we may shut in our oil or natural gas wells for certain 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. Economic conditions, particularly low natural gas prices, may negatively impact the liquidity and creditworthiness of our purchasers and 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, 2012, we reported a net loss of $346.2 million compared to net income of $84.9 million for the three months ended September 30, 2011. For the nine months ended September 30, 2012, we reported a net loss of $1,124.3 million compared to net income of $189.2 million for the nine months ended September 30, 2011.

The net loss for the three and nine months ended September 30, 2012 was primarily the result of non-cash ceiling test write-downs of $318.0 million and $1,022.7 million, respectively, which reflect the significant declines in natural gas prices in 2012. Average natural gas equivalent prices for the three and nine months ended September 30, 2012 averaged $3.01 per Mcfe and $2.70 per Mcfe, respectively, compared with average natural gas equivalent prices for the three and nine months ended September 30, 2011 of $4.14 per Mcfe and $4.33 per Mcfe, respectively.

We use oil and natural gas swap and call option contracts. We do not designate our derivative financial instruments as hedges. As a result, we mark non-cash changes in the fair value of unsettled derivative financial instruments to market at the end of each reporting period and recognize the change in our results of operations. The impacts of realized and unrealized changes in the fair value of derivative financial instruments resulted in a net loss of $20.3 million and gains of $84.3 million for the three months ended September 30, 2012 and 2011, respectively. For the nine months ended September 30, 2012 and 2011, the impacts of realized and unrealized changes in the fair value of derivative financial instruments were gains of $18.3 million and $131.0 million, respectively.

Oil and natural gas production, revenues, and prices

The following table presents our production, revenue and average sales prices by major producing areas for the three and nine months ended September 30, 2012 and 2011:

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	Three Months Ended September 30,
	2012					2011					Quarter to quarter change
(in thousands, except per unit rate)	Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	40,657	$	110,475	$	2.72	44,830	$	171,625	$	3.83	(4,173	)	$	(61,150	)	$	(1.11	)
Appalachia	4,208	12,330		2.93		2,947	12,924		4.39		1,261		(594		)	(1.46		)
Permian and other	2,259	18,816		8.33		2,279	22,725		9.97		(20	)	(3,909		)	(1.64		)
Total	47,124	$	141,621	3.01		50,056	$	207,274	4.14		(2,932	)	$	(65,653	)	(1.13		)
	Nine Months Ended September 30,
	2012					2011					Period to period change
(in thousands, except per unit rate)	Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)	Revenue		$/Mcfe		Production (Mcfe)		Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana	127,580	$	301,798	$	2.37	117,602	$	466,626	$	3.97	9,978		$	(164,828	)	$	(1.60	)
Appalachia	11,597	31,569		2.72		8,593	38,590		4.49		3,004		(7,021		)	(1.77		)
Permian and other	6,863	61,080		8.90		6,792	70,114		10.32		71		(9,034		)	(1.42		)
Total	146,040	$	394,447	2.70		132,987	$	575,330	4.33		13,053		$	(180,883	)	(1.63		)

Production in our East Texas/North Louisiana region for the three months ended September 30, 2012decreased by 4.2 Bcfe from the comparable period in the prior year. This decrease is the result of the reduction to our drilling program in Haynesville during 2012 along with normal decline in producing wells. During the three months ended September 30, 2012, we were operating five horizontal rigs in the East Texas/North Louisiana JV, as compared to 22 rigs during the three months ended September 30, 2011. The decrease in East Texas/North Louisiana JV production was further impacted by normal production declines of 1.1 Bcfe in our Vernon Field and other shallow conventional wells in the region. The increase in Appalachia is a result of our drilling in the Marcellus shale.

For the three months ended September 30, 2012, oil and natural gas revenues were $141.6 million, a 31.7%decrease from the oil and natural gas revenues of $207.3 million for the three months ended September 30, 2011. The decrease in revenues was the result of declines in production, as discussed above, along with decreases in prices for natural gas and natural gas liquids. Our average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased1.4% to $86.87 per Bbl for the three months ended September 30, 2012 from $85.69 per Bbl for the three months ended September 30, 2011. Our average sales price of natural gas liquids per Bbl decreased35.5% to $38.64 per Bbl for the three months ended September 30, 2012 from $59.93 per Bbl for the three months ended September 30, 2011. Our average natural gas sales price, excluding the impact of derivative financial instruments, was $2.69 per Mcf for the three months ended September 30, 2012 compared with $3.82 per Mcf for the three months ended September 30, 2011, a decrease of 29.6%.

Production in our East Texas/North Louisiana region for the nine months ended September 30, 2012increased by 10.0 Bcfe from the comparable period in the prior year. This increase is the result of the development of our East Texas/North Louisiana JV during 2011 and early 2012. The increase in the East Texas/North Louisiana JV production was partially offset by normal production declines of 3.6 Bcfe in our Vernon Field and other shallow conventional wells in the region. The increases in Appalachia and our Permian areas are the result of drilling in those regions. We have reduced drilling in Appalachia and continue our development in the Permian area with one rig.

For the nine months ended September 30, 2012, oil and natural gas revenues were $394.4 million, a 31.4%decrease from the oil and natural gas revenues of $575.3 million for the nine months ended September 30, 2011. The decrease in revenues is primarily a result of significant declines in oil, natural gas and natural gas liquids prices, which were partially offset by increases in production. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, decreased1.3% to $90.33 per Bbl for the nine months ended September 30, 2012 from $91.53 per Bbl for the nine months ended September 30, 2011. The average sales price of natural gas liquids per Bbl decreased24.6% to $43.71 per Bbl for the nine months ended September 30, 2012 from $57.94 per Bbl for the nine months ended September 30, 2011. Our average natural gas sales price, excluding the impact of derivative financial instruments, was $2.34 per Mcf for the nine months ended

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September 30, 2012 compared with $3.95 per Mcf for the nine months ended September 30, 2011, a decrease of 40.8%

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 our nine months ended September 30, 2012 average production levels remain constant for the remainder of the year, a change in the average sales price of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues and cash flows of approximately $4.7 million, a change in the average sales price of $1.00 per Bbl of natural gas liquids would result in an increase or decrease of revenues and cash flows of approximately $0.1 million and a change in the average sales price of $1.00 per Bbl of oil sold would result in an increase or decrease in revenues and cash flow of approximately $0.2 million, without considering the effects of derivative financial instruments.

In addition, our production volumes are impacted by curtailed volumes of natural gas due to operational requirements associated with fracture stimulation and other operations on nearby horizontal wells, seasonal supply and demand conditions from end users and general maintenance and repairs to our wells. While these curtailed volumes are typically for short periods of time, they may have impacts to our revenues, cash flows and results of operations. We currently estimate that approximately 4% to 7% of our Haynesville/Bossier shale production will be curtailed during the remainder of 2012. At the end of the first quarter of 2012, TGGT completed construction of temporary treating facilities which reduced curtailed volumes from the levels experienced in 2011. In the first quarter of 2012, we shut-in 165 conventional wells due to the lower natural gas prices. The impact from these shut-in wells was a reduction of approximately 1.0 Mmcfe per day.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and nine months ended September 30, 2012 were $17.4 million and $59.1 million, respectively, compared with $21.1 million and $60.8 million for the three and nine months ended September 30, 2011, respectively. The decrease for the three and nine months ended September 30, 2012 compared to the same periods in the prior year is primarily due to the implementation of cost saving initiatives throughout our organization.

As shown in the tables below, on a per Mcfe basis, oil and natural gas operating costs for the three and nine months ended September 30, 2012decreased$0.05 per Mcfe and $0.06 per Mcfe, respectively, a decrease of 11.9% and 13.0%, respectively, from the same periods in 2011. The net decrease in oil and natural gas operating costs per Mcfe is primarily due to the combination of increased production in 2012 and implementation of numerous cost savings initiatives as well as increased production for the nine months ended September 30, 2012. Examples of these actions include shutting in marginal producing wells with high-cost water production, decreased compression expenditures and modification of our chemical treating programs. These decreases were offset in part by increases per Mcfe in the Permian region due to higher costs associated with oil production.

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	Three Months Ended September 30,
	2012						2011						Quarter to quarter change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	8,742	$	1,894	$	10,636	$	11,284	$	2,326	$	13,610	$	(2,542	)	$	(432	)	$	(2,974	)
Appalachia	3,518		—		3,518		4,376		—		4,376		(858		)	—			(858		)
Permian and other	3,271		—		3,271		3,094		21		3,115		177			(21		)	156
Total	$	15,531	$	1,894	$	17,425	$	18,754	$	2,347	$	21,101	$	(3,223	)	$	(453	)	$	(3,676	)
	Three Months Ended September 30,
	2012						2011						Quarter to quarter change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.22	$	0.05	$	0.27	$	0.25	$	0.05	$	0.30	$	(0.03	)	$	—		$	(0.03	)
Appalachia	0.84		—		0.84		1.48		—		1.48		(0.64		)	—			(0.64		)
Permian and other	1.45		—		1.45		1.36		0.01		1.37		0.09			(0.01		)	0.08
Operating costs per Mcfe	$	0.33	$	0.04	$	0.37	$	0.37	$	0.05	$	0.42	$	(0.04	)	$	(0.01	)	$	(0.05	)

	Nine Months Ended September 30,
	2012						2011						Period to period change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	30,135	$	7,636	$	37,771	$	33,684	$	7,348	$	41,032	$	(3,549	)	$	288		$	(3,261	)
Appalachia	11,599		—		11,599		10,960		—		10,960		639			—			639
Permian and other	9,416		298		9,714		8,497		354		8,851		919			(56		)	863
Total	$	51,150	$	7,934	$	59,084	$	53,141	$	7,702	$	60,843	$	(1,991	)	$	232		$	(1,759	)
	Nine Months Ended September 30,
	2012						2011						Period to period change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.24	$	0.06	$	0.30	$	0.29	$	0.06	$	0.35	$	(0.05	)	$	—		$	(0.05	)
Appalachia	1.00		—		1.00		1.28		—		1.28		(0.28		)	—			(0.28		)
Permian and other	1.37		0.04		1.41		1.25		0.05		1.30		0.12			(0.01		)	0.11
Operating costs per Mcfe	$	0.35	$	0.05	$	0.40	$	0.40	$	0.06	$	0.46	$	(0.05	)	$	(0.01	)	$	(0.06	)

Midstream operations

We own a 50% equity interest in TGGT and the Appalachia Midstream JV. Our midstream operations earn fees from the gathering, treating and compression of natural gas. Additional operating margins are derived from purchases and resale of natural gas from third parties. Our midstream joint ventures do not own any natural gas processing facilities. We use the equity method of accounting for both of our midstream joint ventures.

TGGT holds most of our East Texas/North Louisiana midstream assets. TGGT’s primary customers are EXCO and BG

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Group. TGGT also owns and operates TGG Pipeline, Ltd., or TGG, and Talco Midstream Assets, Ltd., or Talco. The assets of TGG include treating facilities and gathering pipelines that connect to downstream pipelines. Talco’s assets primarily consist of gathering pipelines that provide well hookups and lateral connections.

TGG operates amine, glycol, and H2S treating facilities, which treat natural gas to meet pipeline specifications for downstream transportation. TGG’s system, which has access to 17 interstate and intrastate pipeline markets, has approximately 128 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe in the East Texas area and 27 miles of pipeline comprised of 36-inch diameter pipe in the North Louisiana area. The Shelby Area’s system has approximately 115 miles of operational pipeline comprised of 4-inch to 36-inch diameter pipe servicing Haynesville/Bossier producers as of September 30, 2012. TGG's major focus in the fourth quarter of 2012 will be its continued reduction of operating expenses through the release of rental units and discontinuation of equipment leases where appropriate. In order to release rental units, TGG will be finalizing its completion of owned amine facilities in the North Louisiana area.

The Talco gathering system in East Texas consists of approximately 585 miles of 4-inch to 12-inch diameter pipe that provides gathering services to a significant number of producers. The Talco gathering system in North Louisiana consists of approximately 285 miles of 2-inch to 16-inch pipe servicing Cotton Valley and Haynesville/Bossier producers. Talco's major focus in the fourth quarter of 2012 and in 2013 will be installing well connects and pipelines for third party Cotton Valley producers.

In the second quarter of 2011, an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana, resulting in an immediate shut-down of the facility. TGGT installed temporary treating units at the damaged facility and began treating volumes late in the first quarter of 2012.

In the first quarter of 2012, TGGT recorded an impairment of approximately $35.3 million of certain assets (approximately $17.7 million net to us) associated with the installation of temporary treating facilities in response to the incident at the TGGT amine treating facility in May 2011. After completion of an independent engineering study, the decision was made to activate the permanent facility affected by the incident since that facility had not sustained as much damage as was initially believed. The impairment primarily resulted from costs incurred related to temporary treating facilities that were not utilized or determined to have a shorter utilization period than originally anticipated. In addition, lower than expected throughput volumes at the facility as a result of reduced drilling contributed to the impairment.

The Appalachia Midstream JV continues to install and operate gathering systems and compression facilities to support our development drilling program in the Appalachia JV.

Gathering and transportation

We report gathering and transportation costs in accordance with Financial Accounting Standards Board, or FASB, Accounting Standards Certification Subtopic 605-45, Revenue Recognition. 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 $25.8 million and $78.2 million, or $0.55 per Mcfe and $0.54 per Mcfe, for the three and nine months ended September 30, 2012, respectively, compared to $22.3 million and $59.1 million, or $0.45 per Mcfe and $0.44 per Mcfe, for the three and nine months ended September 30, 2011, respectively. The increase in total gathering and transportation expense on a per Mcfe rate is a result of increased unused firm transportation volumes.

We have entered into firm transportation agreements with pipeline companies to facilitate sales as we expand our Haynesville volumes and report these firm transportation costs as a component of gathering and transportation expenses. As of September 30, 2012, our firm transportation agreements cover an average of 811 Mmcf per day through 2015, with average annual minimum gathering and transportation expenses of approximately $93.0 million per year. For the years 2016 through 2021, our firm transportation agreements cover an average of 803 Mmcf per day, with average annual minimum gathering and transportation expenses of approximately $89.0 million per year.

Production and ad valorem taxes

For the three months ended September 30, 2012, production and ad valorem taxes were essentially flat over the same period in 2011. For the nine months ended September 30, 2012, production and ad valorem taxes increased by $2.0 million, or

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10.5%, for the same period in 2011. On a percentage of revenue basis, production and ad valorem taxes were 4.7% of gross oil and natural gas sales for the three months ended September 30, 2012 compared with 3.2% during the same period in the prior year and 5.2% of gross oil and natural gas sales for the nine months ended September 30, 2012 compared with 3.3% during the same period in the prior year.

In our East Texas/North Louisiana area, we are presently receiving severance tax holidays on certain Haynesville shale wells which reduce the effective rate of these taxes. Wells that do not have a severance tax holiday are charged a severance tax rate of $0.148 per Mcf.

In February 2012, the Commonwealth of Pennsylvania enacted a comprehensive reform to Pennsylvania’s Oil and Gas Act, or the Act, which requires an impact fee to be paid on all unconventional wells spud. The fee will range from $190,000 to $355,000 per well, based on a price tier calculation to be paid annually up to 15 years. The fee is payable for all wells spud in a single year by April 1st of the following year. The Act contained a retroactive fee to be assessed on all unconventional wells spud prior to December 31, 2011. The retroactive fee of $2.0 million was paid in September 2012, and recorded in “Other operating items” on our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2012. The estimated on-going fee, which is recorded in Production and ad valorem taxes on the Condensed Consolidated Statement of Operations, is computed using the prior year’s trailing 12 month NYMEX natural gas price based on a tiered pricing system and will be paid annually for 15 years. For the three and nine months ended September 30, 2012, we recorded $0.3 million and $1.3 million, respectively, for our estimated 2012 impact fees.

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. Ad valorem tax rates also vary widely. 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, except for holiday exemptions, if any. In our other operating areas, particularly Texas, production taxes are based on a fixed percentage of gross value of products sold. While severance tax holidays are available in Texas as our production increases, our realized severance and ad valorem tax rates may become more sensitive to prices.

Overall, our production and ad valorem tax rates per Mcfe were $0.14 per Mcfe for the three months ended September 30, 2012 compared with $0.13 per Mcfe for the three months ended September 30, 2011 and $0.14 per Mcfe for the nine months ended September 30, 2012 and 2011. The following table presents 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,
	2012						2011
(in thousands, except per unit rate)	Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe		Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	4,476	4.1	%	$	0.11	$	4,342	2.5	%	$	0.10
Appalachia	629		5.1	%	0.15		439		3.4	%	0.15
Permian and other	1,584		8.4	%	0.70		1,872		8.2	%	0.82
Total	$	6,689	4.7	%	0.14		$	6,653	3.2	%	0.13
	Nine Months Ended September 30,
	2012						2011
(in thousands, except per unit rate)	Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe		Production and ad valorem taxes		Taxes % of revenue		Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	13,325	4.4	%	$	0.10	$	12,072	2.6	%	$	0.10
Appalachia	2,325		7.4	%	0.20		1,146		3.0	%	0.13
Permian and other	5,021		8.2	%	0.73		5,482		7.8	%	0.81
Total	$	20,671	5.2	%	0.14		$	18,700	3.3	%	0.14

Depletion, depreciation and amortization

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Our depletion expense for the three and nine months ended September 30, 2012decreased by $28.9 million and $3.8 million, respectively, from the comparable periods in 2011. The decrease is primarily the result of ceiling test write-downs, which have lowered our depletable base. On a per Mcfe basis, our depletion rate for the three and nine months ended September 30, 2012 were $1.42 and $1.62, respectively, compared with $1.92 and $1.80 for the comparable periods in 2011. We expect our per Mcfe depletion rate will continue to decrease as a result of ceiling test write-downs.

Our depreciation and amortization costs for the three and nine months ended September 30, 2012decreased by $1.1 million and $2.5 million, or 23.1% and 18.0%, respectively, from the comparable periods in 2011. The decrease is due to the sale of non oil and natural gas assets.

Accretion of discount on asset retirement obligations for the three and nine months ended September 30, 2012 was $1.0 million and $2.9 million, respectively, compared with $0.9 million and $2.7 million for the three and nine months ended September 30, 2011, respectively. The slight increase is a result of the 2011 acquisitions along with increased drilling programs in both the Haynesville shale and Marcellus shale.

Write-down of oil and natural gas properties

For the three and nine months ended September 30, 2012, we recognized pre-tax ceiling test write-downs of $318.0 million and $1,022.7 million, respectively, due primarily to relatively low natural gas prices. There were no ceiling test write-downs during the comparable periods in 2011.

The ceiling test computation is based on the arithmetic average of reference prices on the first day of the month for the 12 months preceding each balance sheet date. Natural gas prices in 2012 have been lower than 2011, and we expect the trailing 12 month average in 2012 to continue to decline which will result in additional ceiling test write-downs in the fourth quarter 2012 assuming prices do not increase significantly.

General and administrative

The following table presents our general and administrative expenses for the three and nine months ended September 30, 2012 and 2011:

	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands, except per unit rate)	2012			2011			Quarter to quarter change			2012			2011			Period to period change
General and administrative costs:
Gross general and administrative expense	$	37,994		$	48,468		$	(10,474	)	$	115,050		$	127,890		$	(12,840	)
Technical services and service agreement charges	(5,578		)	(8,309		)	2,731			(19,851		)	(21,899		)	2,048
Operator overhead reimbursements	(5,053		)	(4,859		)	(194		)	(15,453		)	(13,745		)	(1,708		)
Capitalized salaries and share-based compensation	(5,311		)	(5,425		)	114			(17,552		)	(15,811		)	(1,741		)
General and administrative expense	$	22,052		$	29,875		$	(7,823	)	$	62,194		$	76,435		$	(14,241	)
General and administrative expense per Mcfe	$	0.47		$	0.60		$	(0.13	)	$	0.43		$	0.57		$	(0.14	)

Our general and administrative costs for the three months ended September 30, 2012 were $22.1 million, or $0.47 per Mcfe, compared to $29.9 million, or $0.60 per Mcfe, for the same period in 2011. Our general and administrative costs for the nine months ended September 30, 2012 were $62.2 million, or $0.43 per Mcfe, compared to $76.4 million, or $0.57 per Mcfe, for the same period in 2011.

Significant components of the net decrease in general and administrative expense for the three and nine months ended September 30, 2012 compared to the respective 2011 periods were a result of:

• decreased personnel costs of $5.7 million and $8.4 million for the three and nine months ended September 30, 2012, respectively, primarily related to a reduction in contract labor costs and lower estimated cash bonus payments in 2012;

• a decrease of $3.3 million and $1.5 million for the three and nine months ended September 30, 2012, respectively,

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related to a retention program implemented in the third quarter of 2011. During the third quarter of 2011, we recognized $4.5 million of general and administrative expenses, representing 25% of the total retention program payments. Upon implementation of the retention program, we began ratably accruing the remaining retention payments. During the three and nine months ended September 30, 2012, the retention expense was $1.2 million and $3.0 million, respectively.

• decreased travel costs of $1.0 million and $1.9 million for the three and nine months ended September 30, 2012, respectively, as compared to travel costs incurred in the prior year related to the former acquisition proposal;

• decreased office related expenses of $0.3 million and $0.8 million, decreased employee development costs of $0.7 million and $1.2 million, and decreased information technology costs of $1.1 million and $1.3 million, all for the three and nine months ended September 30, 2012, respectively, primarily related to our emphasis on cost reductions;

• increased overhead recoveries of $1.7 million for the nine months ended September 30, 2012, respectively, arising from additional wells drilled in 2012 and 2011; and

• increased capitalized salaries and share based compensation of $1.7 million for the nine months ended September 30, 2012, due to 2011 stock option and restricted stock grants.

The above decreases were partially offset by:

• increased legal expenses of $0.8 million for the nine months ended September 30, 2012;

• increased share based compensation expense of $0.5 and $2.0 million for the three and nine months ended September 30, 2012, respectively; and

• decreased technical service recoveries of $2.7 million and $2.0 million for the three and nine months ended September 30, 2012, respectively, arising from decreased employee costs in 2012.

Operating items

Our other operating expenses for the three and nine months ended September 30, 2012 were $1.0 million and $9.3 million, respectively, compared with $21.0 million and $25.2 million for the three and nine months ended September 30, 2011, respectively. The amount for the nine months ended September 30, 2012 was primarily related to the first quarter $2.0 million retroactive Pennsylvania impact fee discussed in Production and ad valorem taxes, a second quarter charge of $6.7 million related to resolution of title defect adjustments from a prior period divestiture and a $1.0 million third quarter charge related primarily to equipment sales and inventory write-downs. We elected to report the retroactive portion of the Pennsylvania impact fee as a component of other operating items as the retroactive amount would disproportionately impact comparative periods in future quarters. The amount for the nine months ended September 30, 2011 was primarily related to costs associated with various lawsuits, the impairment of certain assets and the former acquisition proposal that terminated in July 2011.

Interest expense

Our interest expense for the three and nine months ended September 30, 2012increased$2.8 million and $11.5 million, respectively, from the comparable 2011 periods. The increase for the three and nine months ended September 30, 2012 from the prior year same periods was primarily due to the increase in interest expense related to the EXCO Resources Credit Agreement, including the acceleration of deferred finance costs associated with the lowering of our borrowing base in April 2012, and decreases of capitalized interest related to the decline in our unproved oil and natural gas properties. The year to date variance is offset by a $1.4 million decrease in other interest expense related to a $1.2 million payment made in 2011 in connection with the formation of the TGGT credit facility.

The following table presents our interest expense for the three and nine months ended September 30, 2012 and 2011:

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	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2012			2011			Quarter to quarter change			2012			2011			Period to period change
Interest expense:
2018 Notes	$	14,351		$	14,330		$	21		$	43,037		$	42,975		$	62
EXCO Resources Credit Agreement	8,121			5,799			2,322			23,116			16,705			6,411
Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement	915			1,837			(922		)	5,860			4,131			1,729
Amortization of deferred financing costs on 2018 Notes	467			467			—			1,401			1,401			—
Capitalized interest	(5,967		)	(7,407		)	1,440			(18,492		)	(23,155		)	4,663
Other	48			64			(16		)	146			1,528			(1,382		)
Total interest expense	$	17,935		$	15,090		$	2,845		$	55,068		$	43,585		$	11,483

Derivative financial instruments

We enter into derivative financial instruments to manage our exposure to commodity price and interest rate fluctuations, protect our returns on investments, and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments.

In July 2012, the Commodity Futures Trading Commission approved the final rule that, among other things, exempts end users from the clearing requirements for swaps under the Dodd-Frank Wall Street Reform and Consumer Protection Act. EXCO qualifies as an end user under this final rule. As a result, the swaps we enter into with our derivative counterparties are not subject to clearing requirements that would generally require us to post collateral to secure our derivative obligations.

The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments. Our derivative activity is reported as a component of Other income or expense in our Condensed Consolidated Statements of Operations.

	Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)	2012			2011		Quarter to quarter change			2012			2011		Period to period change
Derivative financial instrument activities:
Cash settlements on derivative financial instruments	$	50,725		$	32,938	$	17,787		$	162,685		$	83,090	$	79,595
Non-cash change in fair value of derivative financial instruments	(70,986		)	51,346		(122,332		)	(144,339		)	47,888		(192,227		)
Total derivative financial instrument activities	$	(20,261	)	$	84,284	$	(104,545	)	$	18,346		$	130,978	$	(112,632	)

The following table presents our natural gas prices, before and after the impact of the cash settlement of our derivative financial instruments.

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	Three Months Ended September 30,							Nine Months Ended September 30,
Average realized pricing:	2012		2011		Quarter to quarter change			2012		2011		Period to period change
Oil per Bbl	$	86.87	$	85.69	$	1.18		$	90.33	$	91.53	$	(1.20	)
Natural gas liquids per Bbl	38.64		59.93		(21.29		)	43.71		57.94		(14.23		)
Natural gas per Mcf	2.69		3.82		(1.13		)	2.34		3.95		(1.61		)
Natural gas equivalent per Mcfe	3.01		4.14		(1.13		)	2.70		4.33		(1.63		)
Cash settlements on derivative financial instruments, per Mcfe	$	1.08	$	0.66	$	0.42		$	1.11	$	0.62	$	0.49
Net price per Mcfe, including derivative financial instruments	$	4.09	$	4.80	$	(0.71	)	$	3.81	$	4.95	$	(1.14	)

Our total cash settlements for the three months ended September 30, 2012 increased revenue by $50.7 million, or $1.08 per Mcfe, compared to $32.9 million, or $0.66 per Mcfe, for the same period in 2011. Our total cash settlements for the nine months ended September 30, 2012 increased revenue by $162.7 million, or $1.11 per Mcfe, compared to $83.1 million, or $0.62 per Mcfe, for the same period in 2011. The significant fluctuations between settlements of receipts on our derivative financial instruments demonstrate volatility in prices.

Our non-cash mark-to-market changes in the value of our oil and natural gas derivative financial instruments for the three and nine months ended September 30, 2012 resulted in losses of $71.0 million and $144.3 million, respectively, compared to gains of $51.3 million and $47.9 million for the same periods in the prior year, respectively. The significant fluctuations were also attributable to high volatility in oil and natural gas prices between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

While the percentage of expected production covered by derivative financial instruments in 2013 is less than the percentage covered in 2012, we expect to continue our comprehensive derivative financial instrument program as part of our overall strategy.

Income taxes

Our effective income tax rate for the three and nine months ended September 30, 2012 and 2011 was zero, primarily due to current operating losses arising from ceiling test write-downs, which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our estimated accumulated valuation allowance as of September 30, 2012 is approximately $814.8 million and can be used against future deferred tax benefits. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits become more likely than not. The effective income tax rates, excluding the impact of the valuation allowances, would have been 39.4% and 39.1% for the three and nine months ended September 30, 2012, respectively, and 40.0% for both the three and nine months ended September 30, 2011, respectively.

Our liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and liquidity are internally generated cash flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets, joint ventures and capital markets, when capital market conditions are favorable. Since we began to emphasize shale resource plays, we have invested significant development expenditures which exceeded our cash flows from operations during 2011. As a result of the current low natural gas price environment, our revised 2012 capital budget is designed to limit capital expenditures to approximate our expected cash flows from operations in 2012. In addition, we are evaluating potential transactions which may enhance our liquidity, including the possible sale of part or all of our interest in TGGT and other assets. Other factors which could impact our liquidity, capital resources and capital commitments in 2012 and future years include the following:

• the results of our ongoing drilling programs;

• our ability to reduce and maintain lower operating, general and administrative expenses and capital expenditure programs in response to continued low natural gas prices;

• reduced oil and natural gas revenues resulting from, among other things, low natural gas prices and lower production from reductions to our drilling and development activities;

• implementation of the Pennsylvania impact fee on non-conventional wells in 2012;

• decreases in the percentage of our production covered by derivative financial instruments, coupled with expiration of

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higher priced derivative financial instruments;

• potential acquisitions and/or sales of oil and natural gas properties or other assets;

• reductions to our borrowing base; and

• our ability to maintain compliance with debt covenants as a result of low natural gas prices.

While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement, will be sufficient to conduct our operations through 2013, there are certain risks arising from the declines in natural gas prices that began in 2011 and could impact our ability to meet debt covenants in future periods. In particular, our ratio of consolidated funded indebtedness to consolidated EBITDAX, as defined in the EXCO Resources Credit Agreement, is computed using a trailing 12-month computation of EBITDAX. As a result, our ability to maintain compliance with this covenant is negatively impacted when oil and/or natural gas prices and production decline over an extended period of time.

In addition to the covenants in the EXCO Resources Credit Agreement, the indenture governing our 2018 Notes contains a debt incurrence test on secured borrowings based on (i) the greater of $1.2 billion, subject to certain permanent reductions, or (ii) 75% of adjusted consolidated net tangible assets, or ACNTA, as defined in the indenture. A significant component of the ACNTA valuation is based on the PV-10 value of our Proved Reserves, computed using SEC pricing as of the beginning of each year. On January 1, 2012, the ACTNA limitation was $2.1 billion. We expect our January 1, 2013 ACNTA limitation to be reduced to the $1.2 billion limitation due to the significant decreases in 2012 natural gas prices used for SEC pricing. While ACNTA limits our ability to incur secured indebtedness, we are not prevented from incurring unsecured financing under the indenture.

In response to the declines in natural gas prices, we have reduced our drilling plans, which will likely reduce our production volumes during the remainder of 2012 and into 2013. During 2012, we sold our corporate aircraft, reduced contract and full-time personnel by approximately 34.1% and 14.3%, respectively, and implemented cost saving initiatives in our field operations. In addition, the volumes of natural gas currently covered by derivative financial instruments declines significantly in 2013 as compared to 2012 and 2011. The combination of our reduced borrowing base, lower production volumes and reduced percentages of volumes covered by derivative financial instruments may require us to seek alternative financing arrangements, further reduce costs or sell assets.

Our current capital budget for 2012 is $470.0 million and reflects continued focus on the development of the Marcellus shale, the Haynesville/Bossier shale plays and the Permian area. In Appalachia, our drilling expenditures for the first nine months of 2012 reflect a benefit of $49.4 million from the Appalachia Carry. We expect the remaining balance of $5.2 million of the Appalachia Carry to be fully utilized during the fourth quarter of 2012.

The following table presents capital expenditures for the first nine months of 2012 and our expected capital expenditures for the remainder of 2012.

	Nine Months Ended September 30,		October - December Forecast		Full Year Forecast
(in thousands)	2012		2012		2012
Capital expenditures:
Development capital	$	326,664	$	78,336	$	405,000
Gas gathering and water pipelines	1,005		1,995		3,000
Lease acquisitions and seismic	10,005		1,995		12,000
Corporate and other	37,722		12,278		50,000
Total	$	375,396	$	94,604	$	470,000

Operationally, we have reduced our company-wide operated rig count from 23 at December 31, 2011 to seven in October 2012 in response to continued low natural gas prices. We currently expect to end 2012 with seven to nine drilling rigs. The rig reductions have been accomplished by a combination of rig contract expirations, assignments of contracts to other operators and the early release and termination of rig contracts and placing two contracted rigs on stand-by. Costs incurred for early termination of rig contracts for the nine months ended September 30, 2012 were approximately $12.4 million.

We believe our current capital expenditure budget for 2012 will meet our operational objectives while maintaining sufficient liquidity. The following table presents our liquidity and and financial position as of September 30, 2012 and pro forma October 25, 2012:

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(in thousands)	September 30, 2012		October 25, 2012
Cash (1)	$	140,859	$	147,816
Drawings under the EXCO Resources Credit Agreement	1,107,500		1,107,500
2018 Notes (2)	750,000		750,000
Total debt	1,857,500		1,857,500
Net debt	$	1,716,641	$	1,709,684
Borrowing base (3)	$	1,400,000	$	1,300,000
Total of unused borrowing base (4)	$	285,393	$	185,393
Unused borrowing base plus cash (1) (4)	$	426,252	$	333,209

(1)    Includes restricted cash of $67.3 million at September 30, 2012 and $77.0 million at October 25, 2012.

(2)    Excludes unamortized bond premium of $8.8 million at September 30, 2012 and $8.7 million at October 25, 2012.

(3) On October 30, 2012, our bank group approved a borrowing base redetermination of $1.3 billion. The amounts shown on this table reflect our October 25, 2012 cash balances and liquidity assuming the $1.3 billion borrowing base was in effect.

(4) Net of $7.1 million in letters of credit as of September 30, 2012 and October 25, 2012.

Events affecting liquidity

Although weaknesses in natural gas prices continue, we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities and available borrowing capacity under the EXCO Resources Credit Agreement will be adequate to execute our corporate strategies and to meet debt service obligations. We expect the natural gas markets to continue to experience an extended period of low prices due to excess supply. Accordingly, we are carefully monitoring our capital budget and may implement further drilling rig reductions as required, or sell assets to provide additional liquidity.

Historical sources and uses of funds

Our primary sources of cash in the first nine months of 2012 were cash flows from operations and borrowings under the EXCO Resources Credit Agreement.

Net increases (decreases) in cash are summarized as follows:

	Nine Months Ended September 30,
(amounts in thousands)	2012			2011
Net cash provided by operating activities	$	414,777		$	355,334
Net cash used in investing activities	(307,253		)	(446,402		)
Net cash flows provided by (used in) financing activities	(65,968		)	103,257
Net increase in cash	$	41,556		$	12,189

In response to the significant declines in natural gas prices that began in 2011, we reduced our drilling programs, particularly in our Haynesville shale operations and implemented company-wide cost reduction efforts. Our cash flows provided by operating activities of $414.8 million for the nine months ended September 30, 2012 exceeded year-to-date capital expenditures of $409.6 million by $5.2 million. In addition, we have reduced our long-term debt by $40.0 million in 2012.

Cash flows from operating activities

The primary factors impacting our cash flows from operations generally include: (i) levels of production from our oil and natural gas properties, (ii) prices we receive from 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 of our general and administrative activities and (v) interest expense and other financing related costs. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes. The prolonged decline in natural gas prices over the last two years has had a significant negative impact on our cash flows from operating activities, with the average realized price per Mcfe, including net derivative settlement proceeds, declining from $6.86 per Mcfe for the nine months ended September 30, 2010 to $3.81 per Mcfe for the nine months ended September 30, 2012, or 44.5%.

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Net cash provided by operating activities for the nine months ended September 30, 2012 was $414.8 million compared with $355.3 million for the nine months ended September 30, 2011. The 16.7%increase in the current nine-month period is primarily attributable to the higher settlement proceeds on our derivatives and favorable working capital conversions, offset by lower average prices received. As of October 25, 2012, our cash and cash equivalent balance was $70.8 million and our restricted cash account, which is used for Haynesville/Bossier shale development operations, was $77.0 million.

Investing activities

Our investing activities consist primarily of drilling and development expenditures, capital contributions to our joint ventures, and acquisitions. Our acquisitions have been focused primarily on undeveloped shale acreage in our core areas and have been funded primarily with borrowings under the EXCO Resources Credit Agreement. Future acquisitions are dependent on oil and natural gas prices, availability of producing properties and attractive acreage and availability of borrowing capacity under the EXCO Resources Credit Agreement or from other capital sources.

For the nine months ended September 30, 2012, our cash flows used in investing activities were $307.3 million, compared with $446.4 million of cash flows used in investing activities for the nine months ended September 30, 2011, which was favorably impacted by a $125.0 million return of capital distribution from TGGT and receipt of $337.3 million from BG Group for its 50% share of acquisitions in our Appalachia and East Texas/North Louisiana areas.

Credit agreement and long-term debt

As of October 25, 2012, we had total debt outstanding of approximately $1.9 billion, which consisted of borrowings under the EXCO Resources Credit Agreement of $1.1 billion and $750.0 million under the 2018 Notes. Terms and conditions of each of the debt obligations are discussed below. Our ability to borrow from sources other than the EXCO Resources Credit Agreement is subject to certain restrictions imposed by our lenders and the indenture governing the 2018 Notes. These agreements contain limitations and restrictions on incurring additional indebtedness and pledging our assets.

EXCO Resources Credit Agreement

At September 30, 2012, the EXCO Resources Credit Agreement had a borrowing base of $1.4 billion and outstanding indebtedness of $1.1 billion.

On April 27, 2012, following the completion of our semi-annual redetermination of our borrowing base in April 2012, we entered into the Sixth Amendment to the EXCO Resources Credit Agreement with the lenders in the bank syndicate. The Sixth Amendment provided for the following changes to the EXCO Resources Credit Agreement:

• reduced our borrowing base from $1.6 billion to $1.4 billion;

• increased the maximum ratio of consolidated funded debt to consolidated EBITDAX (as defined in the agreement) to 4.5 to 1.0 from 4.0 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2012;

• increased the interest rate by 25 bps such that rates now range from LIBOR plus 175 bps to LIBOR plus 275 bps or from ABR plus 75 bps to ABR plus 175 bps depending on borrowing base usage; and

• provided for asset sale procedures for sales of oil and natural gas properties or other material assets, including our interest in TGGT, whereby the proceeds from asset sales (over a minimum threshold) will be used to pay down the outstanding debt balance under the EXCO Resources Credit Agreement and will also reduce the borrowing base. The borrowing base reduction will be equal to the borrowing base value assigned to the assets sold (if any) plus cash proceeds in excess of the borrowing base value aggregating up to $200.0 million.

On October 30, 2012, our banking group approved the Seventh Amendment to the EXCO Resources Credit Agreement, which established our borrowing base at $1.3 billion and, among other things, removed the mandatory asset sale procedures contained in the Sixth Amendment. There were no changes to the interest grid or covenants.

The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries which are jointly held with BG Group. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group. The EXCO Resources Credit Agreement matures on April 1, 2016 and has regularly scheduled semi-annual borrowing base redeterminations each April and October, with EXCO and the lenders having the right to request interim unscheduled redeterminations in certain circumstances.

Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the Engineered Value, as defined in the EXCO Resources Credit Agreement, of our oil and natural gas properties evaluated by the lenders for purposes of establishing our borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of the forecasted production from total Proved Reserves (as

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defined in the agreement) during the first two years of the forthcoming five year period, 90% of the forecasted production from total Proved Reserves for any month during the third year of the forthcoming five year period and 85% of the forecasted production from total Proved Reserves during the fourth and fifth year of the forthcoming five year period.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common stock. Pursuant to the amendment, we may declare and pay cash dividends on our 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) we have at least 10% of our borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes.

Based on a one month LIBOR of 0.2% on October 25, 2012, we would incur an interest rate of 2.7% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

As of September 30, 2012, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, as amended, which requires that we:

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

• not permit our ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2012.

2018 Notes

As of September 30, 2012 and October 25, 2012, we had outstanding $750.0 million aggregate principal amount of 7.5% senior unsecured notes maturing on September 15, 2018. The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group. Our equity investments with BG Group, other than OPCO, are designated as unrestricted subsidiaries under the indenture governing the 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2012 was $8.8 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $702.8 million on September 30, 2012.

Interest is payable on the on the 2018 Notes semi-annually in arrears on March 15th and September 15th of each year.

The indenture governing the 2018 Notes contains covenants which may limit our ability and the ability of our restricted subsidiaries to:

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

• pay dividends on our capital stock (over $50.0 million per annum) or redeem, repurchase or retire our capital stock or subordinated debt;

• make certain 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.

The foregoing description is not complete and is qualified in its entirety by the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes.

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. Recent financial reform legislation has addressed derivative financial instruments, including the possibility of requiring the posting of cash collateral for certain derivative parties. The definitions and specific requirements of this legislation are yet to be defined and we cannot

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presently quantify the impact to us, if any.

Oil and natural gas derivatives

Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas derivative contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.

Our objective in entering into oil and natural gas derivative contracts is to mitigate the impact of price fluctuations and achieve a more predictable cash flow associated with our operations. 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, 2012, we had derivative financial instruments in place for the volumes and prices shown below:

(in thousands, except prices)	NYMEX gas volume - Mmbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Bbls	Weighted average contract price per Bbl
Swaps:
Q4 2012	20,240	$	5.27	138	$	98.05
2013	32,850	4.46		365	99.96
2014	27,375	4.25		—	—
2015	23,725	4.29		—	—
Calls:
Q4 2012	—	$	—	—	$	—
2013	20,075	4.29		—	—
2014	20,075	4.29		365	100.00
2015	20,075	4.29		365	100.00

The swap contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. The call option contracts give the counterparty an option to cause us to enter into derivative contracts at future dates. These options are exercisable monthly on the settlement date for each monthly contract. If the counterparty elects to exercise their option, the notional volume of natural gas will increase by 55,000 Mmbtu per day at the average price of $4.29 per Mmbtu.

Since October 1, 2012, we have entered into natural gas swap agreements covering 90,000 Mmbtus per day for 2013 at an average price of $3.98 per Mmbtu, 60,000 Mmbtus per day for 2014 at an average price of $4.26 per Mmbtu and 12,500 Mmbtus per day for 2015 at an average price of $4.44 per Mmbtu.

Off-balance sheet arrangements

As of September 30, 2012, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

The following table presents our contractual obligations and commercial commitments as of September 30, 2012:

	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
2018 Notes (1)	$	—	$	—	$	—	$	750,000	$	750,000
EXCO Resources Credit Agreement (2)	—		—		1,107,500		—		1,107,500
Firm transportation services and other fixed commitments (3)	93,121		184,974		179,364		302,003		759,462
Other fixed commitments (4)	20,532		14,342		8,146		225		43,245
Drilling contracts	15,213		2,713		—		—		17,926
Operating leases and other	16,434		12,895		2,265		—		31,594
Total contractual obligations (5)	$	145,300	$	214,924	$	1,297,275	$	1,052,228	$	2,709,727

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(1) The 2018 Notes are due on September 15, 2018. The annual interest obligation is $56.3 million.

(2) The EXCO Resources Credit Agreement, as amended, matures on April 1, 2016. The interest is payable at LIBOR plus 175 bps to LIBOR plus 275 bps, or from ABR plus 75 bps to ABR plus 175 bps, depending on borrowing base usage.

(3) 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 fees as if the quantities were delivered.

(4) Other fixed commitments are primarily related to completion service contracts.

(5) Excludes commitments of our equity method investees, TGGT and OPCO, as neither EXCO nor any of its subsidiaries are guarantors of these commitments. TGGT’s commitments as of September 30, 2012, which consist primarily of compression equipment and office leases, totaled $7.9 million. OPCO’s commitments as of September 30, 2012, which consist primarily of firm transportation contracts, drilling contracts and completion services, totaled $67.5 million.

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 fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our financing activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas 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.

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.

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, 2012.

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(in thousands, except prices)	Volume Mmbtus/Bbls	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2012
Natural gas:
Swaps:
Remainder of 2012	20,240	$	5.27	$	39,178
2013	32,850	4.46		19,843
2014	27,375	4.25		1,828
2015	23,725	4.29		(1,794		)
Calls:
Remainder of 2012	—	—		—
2013	20,075	4.29		(4,406		)
2014	20,075	4.29		(9,391		)
2015	20,075	4.29		(13,281		)
Total natural gas	164,415			$	31,977
Oil:
Swaps:
Remainder of 2012	138	$	98.05	$	721
2013	365	99.96		2,238
2014	—	—		—
2015	—	—		—
Calls:
Remainder of 2012	—	—		—
2013	—	—		—
2014	365	100.00		(2,985		)
2015	365	100.00		(3,053		)
Total oil	1,233			$	(3,079	)
Total oil and natural gas derivatives				$	28,898

At September 30, 2012, the average forward NYMEX oil prices per Bbl for the remainder of 2012 and calendar years 2013, 2014 and 2015 were $92.72, $93.70, $91.49 and $89.12, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2012 and for calendar years 2013, 2014 and 2015 were $3.32, $3.84, $4.18 and $4.37 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 (expense) on our Condensed Consolidated Statements of Operations. For example, using the oil swaps in place as of September 30, 2012, for the remainder of 2012, if the settlement price exceeds the actual weighted average strike price of $98.05 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $98.05 per Bbl, multiplied by the hedged volume of 138 Mbbls. Conversely, if the settlement price is less than $98.05 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $98.05 per Bbl, multiplied by the hedged volume of 138 Mbbls. For example, for a hedged volume of 138 Mbbls, if the settlement price is $99.05 per Bbl then other income would decrease by $0.1 million. Conversely, if the settlement price is $97.05 per Bbl, other income would increase by $0.1 million.

Interest rate risk

At September 30, 2012, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement and interest earned on our short-term investments. The interest rate per annum on the 2018 Notes is fixed at 7.5%. Interest is payable on borrowings under the EXCO Resources 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, 2012, we had approximately $1.1 billion in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% change in interest rates (100 bps) based on the variable borrowings as of

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September 30, 2012 would result in an increase or decrease in our interest expense of $11.1 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO’s 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. This evaluation included consideration of various processes and procedures 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.

Based upon this evaluation, our principal executive officer and principal financial officer concluded that as a result of a material weakness described below, our disclosure controls and procedures were not effective as of September 30, 2012. Due to this material weakness in preparing our consolidated financial statements for the quarter ended September 30, 2012, we performed additional procedures to ensure that these condensed consolidated financial statements were fairly presented in all material respects in accordance with U.S. generally accepted accounting principles.

Material weakness in internal control over financial reporting. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of EXCO's annual or interim financial statements will not be prevented or detected on a timely basis. During the preparation of our condensed consolidated financial statements for the quarter ended September 30, 2012, we identified that our processes and procedures for the computation of the fair value of our oil and natural gas derivative financial instruments were not effective. This control deficiency would have resulted in a material error in our condensed consolidated financial statements for the quarter ended September 30, 2012 that would have overstated the net asset carrying value of our derivative financial instruments and understated the unrealized loss on derivative financial instruments recognized in our condensed consolidated statements of operations for these periods. Accordingly, management has concluded this deficiency in internal control over financial reporting constituted a material weakness. The material weakness did not affect the reported results of operations or disclosures in any prior interim or annual period.

Management's remediation initiatives. As a result of the error, we have implemented a more comprehensive review of the futures prices that are used to compute the fair value of our derivative financial instruments, and have used this more detailed process to complete the preparation of our condensed consolidated financial statements for the quarter ended September 30, 2012.

Changes in control over financial reporting. There were no changes in EXCO's internal control over financial reporting that occurred during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we are periodically a party to various litigation matters. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our results of operations or financial condition.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer repurchases of ordinary shares

The following table details our repurchase of common shares for the three months ended September 30, 2012:

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Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (1)
July 1, 2012 - July 31, 2012	—	$	—	—	$ 192.5 million
August 1, 2012 - August 31, 2012	—	$	—	—	$ 192.5 million
September 1, 2012 - September 30, 2012	—	$	—	—	$ 192.5 million
Total	—	$	—	—

(1) On July 19, 2010, we announced a $200.0 million share repurchase program.

Item 6. Exhibits

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

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SIGNATURES

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

			EXCO RESOURCES, INC.
			(Registrant)
Date:	October 30, 2012	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

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INDEX TO EXHIBITS

Exhibit Number	Description of Exhibits
2.1	Asset Purchase Agreement, dated December 15, 2010, among EXCO Holding (PA), Inc., Chief Oil & Gas LLC, Chief Exploration & Development LLC and Radler 2000 Limited Partnership, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
3.1	Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), 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 (File No. 001-32743), 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-l 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), 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 Current Report on Form 8-K (File No. 001-32743), 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 Current Report on Form 8-K (File No. 001-32743), 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 Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
3.8	Statement of Designation of Series A-l Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), 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 Current Report on Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
3.10	Statement of Designation of Series A Junior Participating Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 12, 2011 and filed on January 13, 2011 and incorporated by reference herein.
4.1	Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
4.2	First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 7.500% Senior Notes due 2018, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
4.3	Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-l (File No. 333-129935), filed on January 27, 2006 and incorporated by reference herein.

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4.4	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-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.
10.1	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.*
10.2	Form of Incentive Stock Option Agreement for 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 November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.3	Form of Nonqualified Stock Option Agreement for 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 November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.4	Form of Restricted Stock Award Agreement for 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 August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*
10.5	Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*
10.6	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.*
10.7	Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated by reference herein.*
10.8	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 (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.9	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 (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.10	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.*
10.11	Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*
10.12	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.
10.13	Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
10.14	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.

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10.15	First Amendment to Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated January 31, 2011, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
10.16	Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.17	Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
10.18	Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.19	Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.20	Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.21	Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.22	Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.23	Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.24	Guaranty, dated June 1, 2010, by EXCO Resources, Inc., in favor of: (i) BG Production Company (PA), LLC, BG Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.25	Credit Agreement, dated as of April 30, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger, Wells Fargo Securities, LLC, as Co-Lead Arranger, Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.

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10.26	First Amendment to Credit Agreement, dated as of July 16, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.
10.27	Second Amendment to Credit Agreement, dated as of September 15, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, and Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
10.28	Third Amendment to Credit Agreement, dated as of April 1, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 1, 2011 and filed on April 4, 2011 and incorporated by reference herein.
10.29	Fourth Amendment to Credit Agreement, dated as of November 8, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2011 and filed on November 9, 2011 and incorporated by reference herein.
10.30	Fifth Amendment to Credit Agreement, dated as of November 8, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2011 and filed on November 9, 2011 and incorporated by reference herein.
10.31	Sixth Amendment to Credit Agreement, dated as of April 27, 2012, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 27, 2012 and filed on April 27, 2012, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q, filed on May 2, 2012 and incorporated by reference herein.
10.32	Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.
10.33	Credit Agreement, dated January 31, 2011, by and among TGGT Holdings, LLC, its subsidiaries, as borrowers (or guarantor as to one TGGT subsidiary), JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities Inc., as sole bookrunner and co-lead arranger, BNP Paribas, Citibank, N.A., The Royal Bank of Scotland PLC and Wells Fargo Securities, LLC, as co-lead arrangers, and the lenders named therein, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.
10.34	First Amendment to Credit Agreement, dated January 25, 2012, by and among TGGT Holdings, LLC, TGG Pipeline, Ltd. And Talco Midstream Assets, Ltd., as Borrowers, TGGT GP Holdings, LLC and certain subsidiaries of Borrowers, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, J.P. Morgan Securities LLC, as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Securities, LLC, Bank of America, N.A., BMO Harris Financing, Inc., Royal Bank of Canada, Morgan Stanley Senior Funding, Inc., UBS Loan Finance LLC and The Royal Bank of Scotland plc, as Co-Lead Arrangers, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 25, 2012 and filed on January 31, 2012 and incorporated by reference herein.
10.35	EXCO Resources, Inc. Retention Bonus Plan, dated August 4, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*
31.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.

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31.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
32.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Taxonomy Extension Schema Document.
101.CAL**	XBRL Taxonomy Calculation Linkbase Document.
101.DEF**	XBRL Taxonomy Definition Linkbase Document.
101.LAB**	XBRL Taxonomy Label Linkbase Document.
101.PRE**	XBRL Taxonomy Presentation Linkbase Document.

*

These exhibits are management contracts.

**

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

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