Use these links to rapidly review the documentTABLE OF CONTENTS ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA





UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-K

|(Mark One)                                                       |                                                                                         
|---------------------------------------------------------------- | ----------------------------------------------------------------------------------------
|ý                                                                | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934    
|For the Fiscal Year Ended December 31, 2007                     
|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 0-9204

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EXCO RESOURCES, INC.(Exact name of Registrant as specified in its charter)

|Texas(State or other jurisdiction of
incorporation or organization)                        |  | 74-1492779(I.R.S. Employer Identification No.)                  
|------------------------------------------------------------------------------------------ |  | ----------------------------------------------------------------
|12377 Merit Drive, Suite 1700, LB 82
Dallas, Texas(Address of principal executive offices) |  | 75251(Zip Code)                                                 
|Registrant's telephone number, including area code:(214) 368-2084                         
|Securities registered pursuant to Section 12(b) of the Act:                               
|Title of each classCommon Stock, $0.001 par value                                          |  | Name of each exchange on which registeredNew York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None(Title of class)

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Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ý    No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o    No ý

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 ý    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. 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 definition of "accelerated filer," "large accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ý

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 ý

As of February 15, 2008, the registrant had 104,641,636 outstanding shares of common stock, par value $.001 per share, which is its only class of common
stock. As of the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of our common stock held by non-affiliates was
$1,269,540,000.

For
purposes of this calculation only, affiliates include all shares held by all officers, directors and 10% or greater shareholders.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's proxy statement to be furnished to shareholders in connection with its 2008 Annual Meeting of Shareholders are incorporated by
reference in Part III, Items 10-14 of this Annual Report on Form 10-K.



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TABLE OF CONTENTS



|         |  |                                                                                                                  |  | Page
|-------- |  | ---------------------------------------------------------------------------------------------------------------- |  | ----
|PART I   |  |                                                                                                                 
|Item 1.  |  | Business                                                                                                         |  | 1   
|Item 1A. |  | Risk Factors                                                                                                     |  | 30  
|Item 1B. |  | Unresolved Staff Comments                                                                                        |  | 45  
|Item 2.  |  | Properties                                                                                                       |  | 45  
|Item 3.  |  | Legal Proceedings                                                                                                |  | 46  
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                                              |  | 46  
|PART II  |  |                                                                                                                 
|Item 5.  |  | Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 47  
|Item 6.  |  | Selected Financial Data                                                                                          |  | 47  
|Item 7.  |  | Management's Discussion and Analysis of Financial Condition and Results of Operations                            |  | 51  
|Item 7A. |  | Quantitative and Qualitative Disclosures About Market Risk                                                       |  | 79  
|Item 8.  |  | Financial Statements and Supplementary Data                                                                      |  | 81  
|Item 9.  |  | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure                             |  | 141 
|Item 9A. |  | Controls and Procedures                                                                                          |  | 141 
|Item 9B. |  | Other Information                                                                                                |  | 142 
|PART III |  |                                                                                                                 
|Item 10. |  | Directors, Executive Officers and Corporate Governance                                                           |  | 142 
|Item 11. |  | Executive Compensation                                                                                           |  | 142 
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters                   |  | 142 
|Item 13. |  | Certain Relationships and Related Transactions and Director Independence                                         |  | 142 
|Item 14. |  | Principal Accounting Fees and Services                                                                           |  | 142 
|PART IV  |  |                                                                                                                 
|Item 15. |  | Exhibits and Financial Statement Schedules                                                                       |  | 142 

i

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EXCO RESOURCES, INC.    PART I

ITEM 1.    BUSINESS

General

Unless the context requires otherwise, references in this Annual Report on Form 10-K to "EXCO," "EXCO Resources,"
"Company," "we," "us," and "our" are to EXCO Resources, Inc., its consolidated subsidiaries and EXCO Holdings Inc., or EXCO Holdings, our former parent company that merged with us on
February 14, 2006.

The period that began on January 1, 2005 and ended on October 2, 2005 is referred to in this Annual Report on Form 10-K as
Predecessor. The Predecessor period represents the accounting period up to October 3, 2005, when all of the outstanding equity securities of EXCO Holdings were purchased in a private
transaction, or the Equity Buyout. The period that began on October 3, 2005 and ended on December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 are
referred to as Successor.

We have provided definitions of terms commonly used in the oil and natural gas industry in the "Glossary of selected oil and natural gas terms" beginning on
page 27.

EXCO
Resources, a Texas corporation incorporated in October 1955, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North
American oil and natural gas properties. Our operations are focused in key North American oil and natural gas areas including East Texas/North Louisiana, Appalachia, Mid-Continent and
Permian. As of December 31, 2007, our Proved Reserves were approximately 1.9 Tcfe, of which 93.3% were natural gas and 70.8% were Proved Developed Reserves. As of December 31, 2007, the
related PV-10 of our Proved Reserves was approximately $3.9 billion, and the Standardized Measure of our Proved Reserves was $3.1 billion (see "Summary of
geographic areas of operation" for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the twelve months ended December 31, 2007, we produced 121.3 Bcfe of
oil and natural gas. Based on our December 2007 average daily production of 377 Mmcfe/d, this translates to a reserve life of approximately 13.6 years.

Our business strategy

We plan to achieve reserve, production, and cash flow growth by executing our strategy as highlighted below:







1

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Our strengths

We have a number of strengths that we believe will help us successfully execute our strategy.



2

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Significant transactions during 2007

Private placement of preferred stock.On March 30, 2007, we completed a private placement, or
Private Placement, of an aggregate of $390.0 million of 7.0% Cumulative Convertible Perpetual Preferred Stock, or 7.0% Preferred Stock, and $1.61 billion of Hybrid Preferred Stock, or
Hybrid Preferred Stock, to accredited investors pursuant to the terms and conditions of a Preferred Stock Purchase Agreement dated March 28, 2007. The purchase price for each share was $10,000
(which equaled the liquidation preference per share on March 30, 2007). The issuance and sale of the shares in the Private Placement
was exempt from registration under the Securities Act of 1933, or Securities Act, pursuant to Section 4(2) thereof and Regulation D promulgated thereunder.

The
net proceeds of the Private Placement were used to fund the purchase price of approximately $1.5 billion for the Vernon Acquisition on March 30, 2007 and to repay
certain outstanding indebtedness.

The
7.0% Preferred Stock is convertible into shares of our common stock at an initial conversion price of $19.00 per share, subject to anti-dilution adjustments, which
equates to each share of 7.0% Preferred Stock being initially convertible into approximately 526.3 shares of our common stock, subject to adjustment for fractional shares. The Hybrid Preferred Stock
was not initially convertible into shares of our common stock. Under applicable New York Stock Exchange, or NYSE, rules, shareholder approval is required to issue common stock, or securities
convertible into or exercisable for common stock, if (i) such common stock has, or will have upon issuance, 20.0% or more of the voting power outstanding before the issuance, (ii) the
number of shares of common stock to be issued is, or will be upon issuance, equal to 20.0% or more of the number of shares of common stock outstanding before the issuance, (iii) such common
stock, or securities convertible into or exercisable for common stock, will be issued to a director, officer or substantial security holder of the Company and such securities exceed either a threshold
of one percent or, if issued to a substantial security holder who is not a director or officer at a price that is not less than the book and market value of the common stock, five percent of the
number of shares of common stock or the voting power outstanding before the issuance or (iv) such issuance will result in a change of control of the Company.

Absent
NYSE rules, we likely would have issued 200,000 shares of 7.0% Preferred Stock to fund the Vernon Acquisition and to repay certain outstanding indebtedness. As a result of the
limited time period to fund the Vernon Acquisition and the time required to organize a special meeting of shareholders, we were unable to hold a special meeting of our shareholders to approve the
issuance of 200,000 shares of 7.0% Preferred Stock prior to the Vernon Acquisition. Therefore, in the interim, we issued 39,008 shares of 7.0% Preferred Stock and 160,992 shares of Hybrid Preferred
Stock.

3

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We
agreed with the preferred stock investors to seek the shareholder approval required by the NYSE, or NYSE Shareholder Approval, to transform the terms of the Hybrid Preferred Stock
into the same terms as the 7.0% Preferred Stock. On August 30, 2007, NYSE Shareholder Approval was obtained and the designations, preferences, limitations and relative voting rights of the
Series A-1 Hybrid Preferred Stock and Series A-2 Hybrid Preferred Stock became identical to the designations, preferences, limitations and relative voting rights
of the Series A-1 7.0% Preferred Stock and the Series A-2 7.0% Preferred Stock, respectively, including the right to receive dividends at an annual rate of 7.0%
and the right to convert into shares of our common stock at an initial conversion price of $19.00 per share, subject to anti-dilution adjustments.



The following summarizes the principal terms of the 7.0% Preferred Stock and the Hybrid Preferred Stock. This discussion is not complete and is qualified in its
entirety by, and should be read in conjunction with, the Statements of Designation establishing each series of the 7.0% Preferred Stock and the Hybrid Preferred Stock, which are filed as exhibits to
our Current Report on Form 8-K dated March 28, 2007 and filed with the Securities and Exchange Commission, or the SEC, on April 2, 2007 and are incorporated by
reference herein.



The
Series A-1 7.0% Preferred Stock has an initial liquidation preference equal to $10,000 per share and is convertible into common stock at a price of $19.00 per
share, as may be adjusted in accordance with the terms of the Series A-1 7.0% Preferred Stock. We may force the conversion of the Series A-1 7.0% Preferred Stock
at any time if the common stock trades for 20 days within a period of 30 consecutive days at a price (i) above 175% of the then effective conversion price ($33.25 per share at the
current conversion price of $19.00 per share) at any time during the 24 months after issuance, (ii) above 150% of the then effective conversion price ($28.50 per share at the current
conversion price of $19.00 per share) thereafter through the 48th month after issuance and (iii) above 125% of the then effective conversion price ($23.75 per share at the
current conversion price of $19.00 per share) at any time thereafter. Cash dividends will accrue at the rate of 7.0% per annum prior to March 30, 2013 and at the rate of 9.0% per annum
thereafter. In lieu of paying cash dividends, we may, under certain circumstances prior to March 30, 2013, pay dividends at a rate of 9.0% per annum by adding the dividends to the liquidation
preference of the shares of Series A-1 7.0% Preferred Stock. Upon the occurrence of a change of control, holders of the Series A-1 7.0% Preferred Stock may
require us to repurchase their shares for cash at the liquidation preference plus accumulated dividends. Holders of the Series A-1 7.0% Preferred Stock have the right to vote with
the holders of common stock, the holders of other series of 7.0% Preferred Stock and the holders of Hybrid Preferred Stock, together as a single class, on all matters submitted to our shareholders
(except the election of directors) on an as-converted basis. Holders of Series A-1 7.0% Preferred Stock, Series B 7.0% Preferred Stock, Series C 7.0%
Preferred Stock and Series A-1 Hybrid Preferred Stock have the right to separately elect up to four directors, subject to the rights of the holders of Series B 7.0% Preferred
Stock and Series C 7.0% Preferred Stock to vote as separate classes to each elect one of such preferred directors. In addition, upon the occurrence of specified defaults in the Statements of
Designation for the 7.0% Preferred Stock and the Hybrid Preferred Stock, the holders of the 7.0% Preferred Stock and Hybrid Preferred Stock, voting together as a class, have the right to elect four
additional directors, or Default Directors, until such default is cured.



The
Series B 7.0% Preferred Stock has substantially the same rights as the Series A-1 7.0% Preferred Stock, except that the holders of Series B 7.0%
Preferred Stock have the right to designate one of the preferred directors and do not have registration rights under the 7.0% Registration Rights Agreement. The Series B 7.0% Preferred Stock is
convertible into Series A-1 7.0% Preferred Stock at any time at the election of the holder and will automatically convert into Series A-1 7.0% Preferred

4

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Stock
when such holder ceases to own an aggregate of 10,000 shares of Series B 7.0% Preferred Stock and/or Hybrid Preferred Stock.



The
Series C 7.0% Preferred Stock has substantially the same rights as the Series A-1 7.0% Preferred Stock, except that the holders of Series C 7.0%
Preferred Stock have the right to designate one of the preferred directors and do not have any registration rights under the 7.0% Registration Rights Agreement. The Series C 7.0% Preferred
Stock is convertible into Series A-1 7.0% Preferred Stock at any time at the election of the holder and will automatically convert into Series A-1 7.0% Preferred
Stock when such holder ceases to own an aggregate of 10,000 shares of Series C 7.0% Preferred Stock and/or Hybrid Preferred Stock.



Since
NYSE Shareholder Approval was obtained on August 30, 2007, the designations, preferences, limitations and relative voting rights of the Series A-1 Hybrid
Preferred Stock became identical to the designations, preferences, limitations and relative voting rights of the Series A-1 7.0% Preferred Stock, including the right to dividends
and the right to convert into our common stock.



In connection with the Private Placement, we entered into the 7.0% Registration Rights Agreement with the preferred stock investors. The 7.0% Registration Rights
Agreement contemplates the registration of the resale of the shares of common stock underlying the 7.0% Preferred Stock and the Hybrid Preferred Stock. The 7.0% Registration Rights Agreement contains
customary terms and conditions for a transaction of this type. We agreed to file with the SEC, not later than September 26, 2007, a registration statement to register the offer and sale of the
common shares issuable upon conversion of the 7.0% Preferred Stock and the Hybrid Preferred Stock and to use our best efforts to have the registration statement declared effective by March 24,
2008. On September 5, 2007, we filed an automatically effective registration statement on Form S-3 with the SEC to register for resale the shares of common stock issuable
upon conversion of the Series A-1 Hybrid Preferred Stock and the Series A-1 7.0% Preferred Stock. If any shares of 7.0% Preferred Stock or Hybrid Preferred are
outstanding on March 30, 2011, we agreed to file a registration statement with the SEC by June 28, 2011 registering such shares for resale and to use our best efforts to have such
registration statement declared effective by September 26, 2011. If we are unable to meet the deadlines described above, if a registration statement ceases to remain effective or if we restrict
sales under a registration statement under certain "blackout provisions" for longer than the contractually permitted period, we must pay liquidated damages at a rate of 0.5% per annum of the
liquidation preference applicable to the 7.0% Preferred Stock and the Hybrid Preferred Stock for the first 90 days and thereafter for each subsequent 90-day period at an additional
rate of 0.25% up to a maximum of 2.0% per annum during any default period. We also agreed to indemnify holders against certain liabilities under the Securities Act in respect of any such resale
registration.



In connection with the Private Placement, we entered into a registration rights agreement, or Hybrid Registration Rights Agreement, with the Hybrid Preferred
Stock investors. The Hybrid Registration Rights Agreement contemplates the registration of the resale of the shares of Series A-1 Hybrid Preferred Stock. If NYSE Shareholder
Approval had not been obtained by September 26, 2007, we would have been required to file a registration statement with the SEC by December 24, 2007, covering the resale prior to
such shareholder approval of shares of Hybrid Preferred Stock and to use our best efforts to have the registration statement declared effective by March 24, 2008. The Hybrid Registration Rights
Agreement and the obligation of the parties thereunder terminated on August 30, 2007 because NYSE Shareholder Approval was obtained.

5

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Vernon Acquisition.On March 30, 2007, EXCO Partners Operating Partnership, a wholly-owned
unrestricted subsidiary of EXCO, or EPOP, completed the purchase of substantially all of the oil and natural gas properties and related assets, including derivative financial instruments, covering a
significant portion of estimated production for 2007, 2008 and 2009 from entities affiliated with Anadarko in the Vernon and Ansley fields located in Jackson Parish, Louisiana for approximately
$1.5 billion in cash, net of purchase price adjustments. The Vernon Acquisition was funded by a $1.75 billion capital contribution from EXCO to EPOP. The capital contribution consisted
of $1.67 billion in cash and application of an $80.0 million deposit paid by EXCO to Anadarko in December 2006.

Amended and restated credit agreement of EPOP.Concurrent with the Vernon Acquisition, EPOP entered
into an Amended and Restated Credit Agreement, or the EPOP Credit Agreement, among EPOP, as borrower, certain subsidiaries of EPOP, as guarantors, and certain lenders. The initial interest rate was
London Inter Bank Offered Rate, or LIBOR, plus 150 basis points with a maximum rate of LIBOR plus 175 basis points. The material changes reflected in the EPOP Credit Agreement included an increase in
the borrowing base from $750.0 million to $1.3 billion, principally to reflect the assets acquired in the Vernon Acquisition. EPOP used a portion of the increased borrowing capacity and
the remaining cash from EXCO's capital contribution to repay $668.7 million of an existing EPOP term loan, or the Senior Term Credit Facility, which included principal of $650.0 million,
accrued interest of $5.7 million and a prepayment premium of $13.0 million. Upon consummation of the Vernon Acquisition and repayment of the Senior Term Credit Facility, approximately
$1.1 billion was outstanding under the EPOP Credit Agreement.

Southern Gas Acquisition.On May 2, 2007, we completed the purchase of oil and natural gas
properties and related assets, including derivative financial instruments, covering a significant portion of estimated production for 2007, 2008 and 2009 from entities affiliated with Anadarko in
multiple fields primarily located in Oklahoma, Texas and Louisiana for approximately $761.1 million in cash, including acquisition related expenses, net of preliminary purchase price
adjustments. The Southern Gas Acquisition was funded with cash on hand of $145.2 million, including $133.0 million from like-kind exchange escrow accounts from prior sales,
borrowings under the EXCO Resources credit agreement of $572.9 million and the application of a $43.0 million deposit paid by EXCO to Anadarko in February 2007.

On
May 2, 2007, in connection with the Southern Gas Acquisition, EXCO entered into the Second Amended and Restated Credit Agreement, or the EXCO Resources Credit Agreement, among
EXCO, as borrower, certain subsidiaries of EXCO, as guarantors, and a group of lenders. As a result of the Southern Gas Acquisition, EXCO and the lenders agreed to increase the borrowing base from
$750.0 million to $1.0 billion.

Other 2007 acquisitions.On October 9, 2007, we completed the acquisition of an additional 45%
interest in approximately 28,000 acres of leasehold interests and 135 producing wells in our Canyon Sand field in West Texas for $155.0 million, after post-closing purchase price
adjustments.

In
October 2007, we completed the acquisition of more than 300 producing wells and associated undeveloped sites within our core central Pennsylvania operating area for approximately
$16.2 million.

Summary of 2007 acquisition activity.During 2007, we completed the following acquisitions of oil and
natural gas properties and undeveloped acreage. A summary of these acquisitions and the values

6

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allocated
to oil and natural gas properties and gathering facilities, net of contractual adjustments, is presented on the following table.

|(in thousands)                                                     |                                 | Vernon Acquisition |           | Southern Gas Acquisition |   | Other acquisitions |         | Consolidated total |        
|------------------------------------------------------------------ | ------------------------------- | ------------------ | --------- | ------------------------ | - | ------------------ | ------- | ------------------ | -------
|Purchase price calculations:                                       |                                 |                    |           |                          |   |                    |         |                    |        
|Purchase price                                                     |                                 | $                  | 1,520,183 |                          | $ | 759,100            |         | $                  | 180,160
|Acquisition related expenses                                       |                                 |                    | 1,755     |                          |   | 2,040              |         |                    |       
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        
|Total purchase price                                               |                                 | $                  | 1,521,938 |                          | $ | 761,140            |         | $                  | 180,160
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        
|Allocation of purchase price:                                      |                                 |                    |           |                          |   |                    |         |                    |        
|Proved oil and natural gas properties                              |                                 | $                  | 1,417,823 |                          | $ | 577,852            |         | $                  | 159,502
|Unproved oil and natural gas properties                            |                                 |                    | 58,192    |                          |   | 4,743              |         |                    | 20,658 
|Gulf coast sale                                                    |                                 |                    |          |                          |   | 235,477            |         |                    |       
|Gas gathering and related facilities                               |                                 |                    | 119,409   |                          |   |                   |         |                    |       
|Fair value (liability) of assumed derivative financial instruments |                                 |                    | (60,015   | )                        |   | (42,204            | )       |                    |       
|Asset retirement obligations                                       |                                 |                    | (10,726   | )                        |   | (12,567            | )       |                    |       
|Other liabilities, net                                             |                                 |                    | (2,745    | )                        |   | (2,161             | )       |                    |       
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        
|                                                                   | Total purchase price allocation |                    | $         | 1,521,938                |   | $                  | 761,140 |                    | $      
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        

Gulf Coast Sale.On May 8, 2007, we completed the sale of a portion of the oil and natural gas
properties and related assets in multiple fields primarily located in South Texas and South Louisiana acquired in the Southern Gas Acquisition to an entity affiliated with Crimson
Exploration Inc., or Crimson, for an aggregate sale price of $235.5 million in cash, net of preliminary purchase price adjustments, and 750,000 shares of unregistered restricted Crimson
common stock. In connection with the closing of the Gulf Coast Sale, the borrowing base on the EXCO Resources Credit Agreement was reduced from $1.0 billion to $900.0 million.

On
August 15, 2007, we sold the 750,000 shares of unregistered restricted common stock of Crimson for an aggregate sales price of approximately $5.2 million. We recorded a
gain of $0.7 million on the sale, which is included in other income for the year ended December 31, 2007.

Other 2007 sales of oil and natural gas properties.On January 5, 2007, we completed the sale
of oil and natural gas properties and undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, or the Wattenberg Field, for approximately $130.9 million, net of contractual
adjustments. The transaction included substantially all of the assets EXCO held in the area. Proceeds from the sale were deposited with a third party intermediary pending closing of the Southern Gas
Acquisition to facilitate a like-kind exchange for federal income tax purposes.

On
July 13, 2007, we completed the sale of substantially all of our interest in the Cement Field, located in Caddo and Grady Counties, Oklahoma in our Mid-Continent
area for approximately $99.7 million, after contractual purchase price adjustments. Proceeds from this sale were deposited with a third party intermediary and used to purchase assets in West
Texas in October 2007.

In
November 2007, we sold certain assets across our portfolio for approximately $20.4 million, subject to post-closing adjustments. Through this divestiture, we exited
Nebraska, Colorado, and certain non-operated properties in Texas and the Gulf Coast area of Louisiana.

No
gain or loss was recognized from these sales as we use the full cost method of accounting.

Pro forma results of operations.The following table reflects the unaudited pro forma results of
operations as though the acquisitions of TXOK, Power Gas Marketing & Transmission, Inc., or PGMT,

7

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Winchester,
the Private Placement, the Vernon Acquisition, the Southern Gas Acquisition and the Gulf Coast Sale had occurred on January 1, 2006.

(in thousands, except per share data)

Year ended December 31, 2006

Year ended December 31, 2007Revenues and other income

$
1,430,863

$
1,063,492Net income


335,129


101,697Preferred stock dividends


(140,000
)

(140,000
)Net income (loss) available to common shareholders

$
195,129

$
(38,303
)Basic earnings (loss) per share

$
2.02

$
(0.37
)Diluted earnings (loss) per share

$
1.65

$
(0.37
)


Significant subsequent events

Withdrawal of master limited partnership

On January 10, 2008, we announced the withdrawal of our registration statement related to our proposed master limited partnership. As such, approximately
$3.5 to $4.5 million in registration costs, of which $3.4 million was deferred in 2007, will be expensed in the first quarter of 2008.

Financial Risk Management Instruments

In January 2008, we entered into financial risk management instruments to mitigate our exposure to fluctuations in interest rates on $700.0 million in
principal through February 14, 2010 at LIBOR rates ranging from 2.45% to 2.8%.

Derivative Financial Instruments

Subsequent to December 31, 2007, we entered into additional derivative financial instruments covering 28,021 Mmbtu of natural gas and
731 Bbls of oil at weighted average prices of $8.79 per Mmbtu and $91.18 per Bbl, respectively.

Appalachian acquisition

On February 20, 2008, EXCO acquired shallow natural gas properties from EOG Resources, Inc. located primarily in EXCO's central Pennsylvania
operating area. The properties include approximately 2,500 producing wells, 2,000 shallow undrilled locations and 16 Mmcfe/d of net production. The purchase price was $395.0 million. After
reduction for preliminary closing adjustments of $7.4 million, the net purchase price paid on February 20, 2008 was $387.6 million and was financed with the EXCO Resources Credit
Agreement.



The following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2007:

Areas

Total proved reserves (Bcfe) (1)

PV-10
(in millions) (1)(2)

Average December daily net production (Mmcfe/d)

Reserve life (years) (3)East Texas/North Louisiana

974.3

$
1,987.2

243.0

11.0Appalachia

418.5


674.0

44.0

26.1Mid-Continent

315.4


831.0

62.0

13.9Permian

143.9


424.8

26.0

15.2Rockies

13.0


28.9

2.0

17.8Total

1,865.1

$
3,945.9

377.0

13.6


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|
|

|Areas                      |       | Identified drilling locations(4) |        | Identified exploitation projects(5) |     | Total gross acreage |           | Total net acreage(6)
|-------------------------- | ----- | -------------------------------- | ------ | ----------------------------------- | --- | ------------------- | --------- | --------------------
|East Texas/North Louisiana |       | 2,466                            |        | 543                                 |     | 328,541             |           | 278,480             
|Appalachia                 |       | 6,154                            |        | 121                                 |     | 863,189             |           | 815,073             
|Mid-Continent              |       | 548                              |        | 179                                 |     | 378,632             |           | 221,769             
|Permian                    |       | 684                              |        | 44                                  |     | 71,525              |           | 50,351              
|Rockies                    |       | 150                              |        | 7                                   |     | 147,998             |           | 132,456             
|                           |       |                                  |        |                                     |     |                     |           |                     
|                           | Total |                                  | 10,002 |                                     | 894 |                     | 1,789,885 |                     
|                           |       |                                  |        |                                     |     |                     |           |                     

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(in millions)PV-10

$
3,945.9Future income taxes


(1,857.5
)Discount of future income taxes at 10% per annum


1,030.5Standardized Measure

$
3,118.9


9

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Our development and exploitation project areas

East Texas/North Louisiana

The East Texas/North Louisiana area is a part of the Cotton Valley Sand trend, which covers parts of the East Texas Basin and the Northern Louisiana Salt Basin.
We are targeting tight sand reservoirs along the Cotton Valley Sand trend at depths of 6,500 to 15,000 feet. Operations in the area are generally characterized by long-lived reserves, high
drilling success rates and wells with relatively high initial production rates. Due to the tight nature of the reservoirs, development programs in the area are mostly focused on infill development
drilling. Many areas have been down spaced to 80 acres per well, with some areas having economically established 40 acre spacing.

Vernon Field

The Vernon Field, located in Jackson Parish, Louisiana, is our largest producing field, accounting for approximately one-third of our production. The
field and gathering system were acquired from Anadarko on March 30, 2007. At December 31, 2007, we had Proved Reserves of 467.5 Bcfe and 365 gross producing wells. Most of the wells in
the field produce from the Lower Cotton Valley and Bossier formations at approximately 12,000 to 15,000 feet. We gather and treat our own gas and have access to numerous transmission lines. In 2008 we
plan to drill 24 wells.

East Texas/North Louisiana Cotton Valley Area

Within our Cotton Valley Area, we are active in Harrison, Panola, Smith, Rusk, Upshur and Gregg Counties in Texas, primarily across six fieldsWaskom,
Overton, Oak Hill, Minden, Glenwood and White Oak. We are also active in Caddo Parish and DeSoto Parish in Louisiana, primarily across four fieldsHolly, Kingston, Caspiana and Longwood.
At December 31, 2007, we had Proved Reserves of 506.8 Bcfe and 1,206 gross producing wells. We are focused on developing the Lower Cotton Valley (Taylor) and Upper Cotton Valley sands at depths
of 10,400 to 11,000 feet, the Pettet Lime at depths of 7,000 to 8,500 feet and Travis Peak Sands at depths of 7,800 to 10,000 feet. Our natural gas is gathered through our own gathering lines in these
fields. In 2008 we plan to drill 115 wells.

Appalachia

The Appalachian Basin includes portions of the states of Kentucky, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee, and covers an area of over 185,000
square miles. It is the most mature oil and natural gas producing region in the United States, first establishing oil production in 1859. The Appalachian Basin is strategically located near high
energy demand areas with limited supply. As a result, the natural gas produced from the area typically commands a higher wellhead price relative to other North American areas.

10

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Although the Appalachian Basin has sedimentary formations indicating the potential for deposits of oil and natural gas reserves up to depths of 30,000 feet or more, most production in
this area has been derived from relatively shallow, low porosity and permeability sand and shale formations at depths of 1,000 to 6,000 feet. Operations in the area are generally characterized by long
reserve lives, high drilling success rates and a large number of low productivity wells in these shallow formations. In the Appalachian Basin, there are more than 200,000 producing wells and 3,100
operators, with most being relatively small, private enterprises. Our operations in the area primarily include development drilling on our existing acreage, as well as the acquisition of properties
with established production and growth opportunities. We believe that the number of wells and operators presents a significant consolidation opportunity.

Northwestern Pennsylvania Area

The Northwestern Pennsylvania Area stretches across eight counties in northwestern Pennsylvania. At December 31, 2007, we had Proved Reserves of 25.6 Bcfe
and 602 gross producing wells. Drilling, completion and production activities target the Silurian Medina Sandstone formation at depths of 4,500 to 5,100 feet. We currently plan to drill 29 wells in
2008.

Central Pennsylvania Area

The Central Pennsylvania Area encompasses a band across 13 counties in central Pennsylvania. At December 31, 2007, we had Proved Reserves of 188.9 Bcfe and
2,220 gross producing wells. Drilling, completion and production activities target the multiple, laterally stratified reservoirs of the Upper Devonian Venango, Bradford and Elk sandstone groups at
depths ranging from 1,800 to 4,600 feet. We currently plan to drill 132 wells in 2008.

Eastern Ohio Area

The Eastern Ohio Area includes some 25 counties in eastern Ohio. At December 31, 2007, we had Proved Reserves of 72.7 Bcfe and 1,657 gross producing wells.
Drilling, completion and production activities target the Silurian Clinton Sandstone found at depths of 3,500 to 5,600 feet and the Knox series at depths approaching 7,500 feet. We currently plan to
drill 31 wells in 2008.

Northern West Virginia Area

The Northern West Virginia Area includes 17 counties located in northern West Virginia. At December 31, 2007, we had Proved Reserves of 76.3 Bcfe and 1,388
gross producing wells. Drilling, completion and production activities target the multiple, laterally stratified reservoirs of the Mississippian and Devonian formations found at depths of 2,500 to
4,500 feet. We currently plan to drill 19 wells in 2008.

Southern West Virginia Area

The Southern West Virginia Area includes 12 counties in southern West Virginia. At December 31, 2007, we had Proved Reserves of 48.9 Bcfe and 786 gross
producing wells. Drilling, completion and production activities target the multiple, laterally stratified reservoirs of the Mississippian and Devonian formations found at depths of 1,500 to 5,500
feet. We currently plan to drill 6 wells in 2008.

Marcellus Shale Play

In Appalachia, we hold in excess of 800,000 net leasehold acres. Our land staff is focused on acquiring additional leasehold in our traditional shallow producing
areas as well as in the Marcellus shale play fairway. Included in our extensive acreage position, we have approximately 350,000 net acres in the Marcellus shale, much of which is held by shallow
production. More than 190,000 net acres are

11

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in
the core area of the overpressured Marcellus play. Efforts continue to evaluate and develop plans relating to exploitation of the Marcellus shale play, and we have begun staffing in preparation for
exploitation of our Marcellus shale position. Successful testing of the Marcellus shale has been conducted on four wells located in the shallower, normal to under-pressured areas of the basin where
Marcellus production is being commingled with other, more traditional horizons to improve overall well economics. Testing of stand-alone horizontal wellbore completions in the
over-pressured shale is planned for 2008.

Mid-Continent

The Mid-Continent area includes parts of Oklahoma, southwestern Kansas and the Texas Panhandle. The major properties in the Mid-Continent
area are located in the Anadarko Shelf and Anadarko Basin of Oklahoma. The Mid-Continent area is characterized by stratigraphic plays with multiple, stacked pay zones and more complex
geology than in our other operating areas. Similar to our other operating areas, the Mid-Continent area contains a number of fields with long production histories. We also recognize the
potential for additional attractive acquisition opportunities, as this area contains a number of smaller operators seeking liquidity opportunities and some larger companies seeking to divest
non-core assets.

Mocane-Laverne Field

The Mocane-Laverne Field is primarily located in Beaver, Harper and Ellis Counties of Oklahoma. At December 31, 2007, we had estimated Proved Reserves of
92.0 Bcfe and we had 695 gross producing wells. Primary drilling targets include the Morrow, Chester and Cherokee formations. Current producing wells have an average total depth of 7,161 feet. We
currently plan to drill 37 wells during 2008.

Golden Trend Area

The Golden Trend Area is primarily located in Grady, Garvin and McClain Counties of Oklahoma. At December 31, 2007, we had estimated Proved Reserves of
157.1 Bcfe and we had 569 gross producing wells. Primary drilling targets are Sycamore, Hunton, Viola, Woodford, Simpson and Pennsylvanian formations. Current producing wells have an average total
depth of 11,190 feet. We currently plan to drill 17 wells during 2008.

Permian

The Permian Basin is located in West Texas and the adjoining area of southeastern New Mexico. Though the Permian Basin is better known as a mature oil focused
basin exploited with waterflood and other enhanced oil recovery techniques, our activities are focused on conventional natural gas properties. With the use of 3-D seismic, we are targeting
prolific natural gas reservoirs with potential for multi-pay horizons. The properties are characterized by long reserve lives and low operating costs.

Sugg Ranch Field

The Sugg Ranch Field is located primarily in Irion County, Texas. We acquired an additional 45% interest in 135 producing wells and took over as operator in
October 2007. This brings our total working interest to 97%. At December 31, 2007, we had Proved Reserves of 101.0 Bcfe and 160 gross producing wells. Production is primarily from the Canyon
Sand from depths of 6,700 to 7,300 feet. We currently plan to drill 147 wells during 2008.

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Rockies

The Rockies Area is located in Wyoming, Montana and Colorado. The region is mature and has been oil focused, with more recent emphasis on natural gas and
coal-bed methane. The region can be complex geologically. Drill depths range from less than 1,000 feet to greater than 25,000
feet. Opportunities exist to acquire 3D seismic on existing fields to identify by-passed pay zones.

Rockies Area

The Rockies Area holdings consist of approximately 132,000 net acres of leasehold in Wyoming, primarily in the Wind River, Bighorn and Powder River Basins. At
December 31, 2007, we had Proved Reserves of 13.0 Bcfe and 66 gross producing wells. We are targeting prolific natural gas reserves in the range of 2,000 to 14,000 feet with potential for
multiple pays in each well. We currently plan to drill 9 wells in 2008.

Our oil and natural gas reserves

The following tables summarize historical information regarding Proved Reserves at December 31, 2005, 2006 and 2007. The historical information was
prepared in accordance with the rules and regulations of the SEC.

At December 31,2005

2006

2007Oil (Mmbbls)Developed


5.5


11.3


15.2Undeveloped


1.3


4.9


5.7Total


6.8


16.2


20.9Natural Gas (Bcf)Developed


321.7


665.3


1,228.8Undeveloped


79.5


461.3


510.9Total


401.2


1,126.6


1,739.7Equivalent reserves (Bcfe)Developed


354.7


733.1


1,320.0Undeveloped


87.3


490.7


545.1Total


442.0


1,223.8


1,865.1Pre-tax present value, discounted at 10% (PV-10)
(in millions)(1)Developed

$
1,046.7

$
1,353.7

$
3,369.2Undeveloped


201.9


252.3


576.7Total

$
1,248.6

$
1,606.0

$
3,945.9Standardized Measure (in millions)

$
823.3

$
1,311.8

$
3,118.9


---

13

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Date

Natural gas (per Mmbtu)

Oil
(per Bbl)December 31, 2005

$
10.08

$
61.03December 31, 2006


5.64


60.82December 31, 2007


6.80


95.92


We
believe that PV-10 before income taxes, while not a financial measure in accordance with generally accepted accounting principles, is an important financial measure used
by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics, which can differ
significantly, among comparable companies. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with SFAS No. 69. The
following table provides a reconciliation of our PV-10 to our Standardized Measure:

At December 31,(in millions)2005

2006

2007PV-10

$
1,248.6

$
1,606.0

$
3,945.9Future income taxes


(1,097.6
)

(721.2
)

(1,857.5
)Discount of future income taxes at 10% per annum


672.3


427.0


1,030.5Standardized Measure

$
823.3

$
1,311.8

$
3,118.9


The
total reserve estimates presented as of December 31, 2005, 2006 and 2007 have been prepared by our internal engineers. These reserve estimates are reviewed and approved by
senior engineering staff with final approval by the Vice President and Chief Operating Officer. During each of the years ended 2005, 2006 and 2007, we retained Lee Keeling to prepare an estimate of
our Proved Reserves and future net cash flows attributable to our interests. The estimate of our PV-10 and Standardized Measure is based upon our estimate of future abandonment costs and
the report on our Proved Reserves as prepared by Lee Keeling. Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm's
extensive visits, collection of any and all required geologic, geophysical, engineering and economic data, and such firm's complete external preparation of all required estimates and are
forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses, capital
expenditures, production and ad valorem taxes and availability of funds. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and
natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that
the reserves will ultimately be realized. Our actual results could differ materially. See "Note 21. Supplemental information relating to oil and natural gas producing
activitiescontinuing operations (unaudited)" of the notes to our consolidated financial statements for additional information regarding our oil and natural gas reserves and our
Standardized Measure.

The
Proved Reserve estimate prepared by Lee Keeling for the years ended 2005, 2006 and 2007 included a detailed review of all of our properties.

Lee
Keeling also examined our estimates with respect to reserve categorization, using the definitions for Proved Reserves set forth in SEC Regulation S-X
Rule 4-10(a) and SEC staff interpretations and guidance. In preparing an estimate of the reserves of future net cash flow attributable to our interest, Lee Keeling did not
independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation
and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of

14

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the
examination something came to the attention of Lee Keeling which brought into question the validity or sufficiency of any such information or data, Lee Keeling did not rely on such information or
data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. Lee Keeling determined that our estimates of reserves conform to
the guidelines of the SEC, including the criteria of "reasonable certainty," as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating
conditions, consistent with the definition in Rule 4-10(a)(2) of SEC Regulation S-X. Lee Keeling issued an unqualified audit opinion on our Proved Reserves at
December 31, 2007, based upon their evaluation. Their opinion concluded that our estimates of Proved Reserves were, in the aggregate, reasonable.

Our production, prices and expenses

The following table summarizes revenues (before cash settlements of derivative financial instruments), net production of oil and natural gas sold, average sales
price per unit of oil and natural gas and costs and expenses associated with the production of oil and natural gas. This table includes information for acquisitions from the date of closing and
excludes information with respect to the sale of our Canadian subsidiary in February 2005.

|                    |                                                   | Predecessor |   | Successor
|------------------- | ------------------------------------------------- | ----------- | - | ---------
|
|Sales:              |                                                   |             |   |          
|Oil:                |                                                   |             |   |          
|                    | Revenue(1)                                        |             | $ | 19,528   
|                    | Production sold (Mbbl)                            |             |   | 375      
|                    | Average sales price per Bbl(1)                    |             | $ | 52.07    
|Natural gas:        |                                                   |             |   |          
|                    | Revenue(1)                                        |             | $ | 113,293  
|                    | Production sold (Mmcf)                            |             |   | 15,490   
|                    | Average sales price per Mcf(1)                    |             | $ | 7.31     
|Costs and expenses: |                                                   |             |   |          
|                    | Average production cost per Mcfe                  |             | $ | 1.25     
|                    | General and administrative expense per Mcfe(2)    |             | $ | 5.04     
|                    | Depreciation, depletion and amortization per Mcfe |             | $ | 1.39     

---

Our interest in productive wells

The following table quantifies as of the dates indicated information regarding productive wells (wells that are currently producing oil or natural gas or are
capable of production), including temporarily shut-in wells. The number of total gross oil and natural gas wells excludes any multiple

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completions.
Gross wells refers to the total number of physical wells that we hold any working interest in, regardless of our percentage interest. A net well is not a physical well, but is a concept
that reflects the actual total working interests we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells.

At December 31, 2007Gross wells(1)

Net wellsAreasOil

Gas

Total

Oil

Gas

TotalEast Texas/North Louisiana

51

1,527

1,578

45.8

1,143.4

1,189.2Appalachia

408

6,335

6,743

403.4

5,731.5

6,134.9Mid-Continent

318

1,320

1,638

178.2

758.5

936.7Permian

153

134

287

127.7

101.0

228.7Rockies

44

22

66

34.8

18.8

53.6Total

974

9,338

10,312

789.9

7,753.2

8,543.1


---

As
of December 31, 2007, we were the operator of 9,273 gross (8,268.3 net) wells, which represented approximately 95% of our Proved Reserves as of December 31, 2007.

Our drilling activities

We intend to concentrate our drilling activity on lower risk, development-type properties. The number and types of wells we drill will vary depending
on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests in each well, the estimated recoverable reserves attributable to each well
and accessibility to the well site.

The
following tables summarize our approximate gross and net interests in the wells we drilled during the periods indicated and refers to the number of wells completed at any time during
the period, regardless of when drilling was initiated. These tables exclude information with respect to Canada as a result of the sale of our Canadian subsidiary in February 2005.

Development wellsGross

NetProductive

Dry

Total

Productive

Dry

TotalYear ended December 31, 2005

104

2

106

101.1

1.5

102.6Year ended December 31, 2006

366

5

371

298.2

2.3

300.5Year ended December 31, 2007

487

7

494

394.7

4.6

399.3


|
|

Exploratory wellsGross

NetProductive

Dry

Total

Productive

Dry

TotalYear ended December 31, 2005

4

1

5

2.7

0.2

2.9Year ended December 31, 2006

1

1

2

0.3

0.3

0.6Year ended December 31, 2007

8

4

12

2.5

3.4

5.9


At
December 31, 2007, we had 23 gross (20.6 net) wells being drilled and 42 gross (35.6 net) wells being completed.

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Our developed and undeveloped acreage

Developed acreage are those acres spaced or assignable to producing wells. Undeveloped acreage are those acres that do not currently have completed wells capable
of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The definitions of gross acres and net acres conform to how we determine gross
wells and net wells. The following table sets forth our developed and undeveloped acreage at December 31, 2007:

At December 31, 2007Developed acreage

Undeveloped acreageAreasGross

Net

Gross

NetEast Texas/North Louisiana

171,883

137,636

156,658

140,844Appalachia

420,256

394,381

442,933

420,692Mid-Continent

348,308

202,502

30,324

19,267Permian

38,717

23,707

32,808

26,644Rockies

13,886

10,340

134,112

122,116Total

993,050

768,566

796,835

729,563


The
primary terms of our oil and natural gas leases expire at various dates, generally ranging from one to five years. Most of our undeveloped acreage is "held by production," which
means that these leases are active as long as we produce oil or natural gas from the acreage. Upon ceasing production, these leases will expire. We have 100,454, 74,083 and 73,042 net acres with
leases expiring in 2008, 2009 and 2010, respectively.

The
undeveloped "held by production" acreage in many cases represents potential additional drilling opportunities through down spacing and drilling of proved undeveloped and unproved
locations in the same formation(s) already producing in a given oil or natural gas field without the necessity of purchasing additional leases or producing properties.

Sales of producing properties and undeveloped acreage

We periodically review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of properties with higher
operating costs and properties that are not within our core geographic operating areas. We also seek to opportunistically divest properties in areas in which acquisitions and investment economics no
longer meet our objectives, most notably evidenced by the sale of our Canadian subsidiary for $443.4 million, the sale of our Wattenberg Field operations in Colorado for $130.9 million
in January 2007 and the sale of our Cement Field interest for $99.7 million on July 13, 2007. During the years ended December 31, 2005, 2006 and 2007, we received proceeds of
$45.3 million, $5.2 million and $490.3 million, respectively, from the sale of properties in the United States.

Midstream operations

In connection with the Winchester acquisition, we acquired a 53-mile intrastate pipeline, or the TGG Pipeline, composed of 23 miles of
12-inch diameter and 30 miles of 16-inch diameter pipelines. The TGG Pipeline connects to several processing plants owned by others and interconnects 12 interstate
pipeline markets. During 2007, we added 9 miles to this pipeline network, which now totals 62 miles. During December 2007, average throughput volume on the TGG Pipeline was 118 Mmcf/d with a total
capacity of 175 Mmcf/d. Of the natural gas transported by the TGG Pipeline, approximately 20% represents production from our assets and approximately 80% represents production from third parties. We
are presently expanding our TGG Pipeline in East Texas, adding 57 miles of 8-inch, 12-inch and 20-inch diameter pipe segments at a cost of approximately
$37.6 million.

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This
expansion, which we expect to be fully operational in the second half of 2008, will allow 100 Mmcf/d of additional third party throughput.

In
support to the above mentioned TGG Pipeline, we own and operate Talco Midstream Assets, a network of natural gas gathering systems comprised of approximately 550 miles of pipeline in
our East Texas/North Louisiana area of operation, which gathers and transports natural gas to the TGG Pipeline and larger gathering systems and intrastate, interstate and local distribution pipelines
owned by third parties. Of the 145 Mmcf/d of natural gas gathered and transported by this system, approximately 76% represents production from our assets and approximately 24% represents production
from the assets of third parties. We transport natural gas from unaffiliated producers on our gathering and pipeline assets under fixed fee arrangements pursuant to which our gathering and
transportation fee income represents an agreed rate per unit of throughput. The revenues we earn from these arrangements are directly related to the volume of natural gas that flows through our
systems and are not directly dependent on commodity prices.

In
connection with the Vernon Acquisition, we acquired a gathering system comprised of 167 miles of pipeline ranging in size from 3 inches to 16 inches in diameter. Since the
acquisition, we have added 1 mile of 4-inch diameter pipeline. The pipeline connects to several processing plants and interconnects to five interstate pipeline markets. During December
2007, average throughput volume on the pipeline was 192 Mmcf/d with a total capacity of 420 Mmcf/d. Of all the natural gas transported by the gathering system, approximately 97% represents production
from our assets and approximately 3% represents production from the assets of third parties.

Our principal customers

For the twelve months ended December 31, 2007, sales to a regulated natural gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, and an
independent oil and natural gas company, Anadarko and its affiliates, accounted for 20.0% and 12.1%, respectively, of total oil and natural gas revenues. For the twelve months ended
December 31, 2006 and 2005 sales to one industrial customer, Alcan Rolled ProductsRavenswood, LLC, accounted for 4.9% and 10.1%, respectively, of total oil and natural gas
revenues. We believe that the loss of any one customer would not have a material adverse effect on our results of operations or financial condition.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring
properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a
result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will
permit.

We
are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs,
equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages
may again occur or how they would affect our development and exploitation program.

Competition
is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete
satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. We regularly evaluate acquisition opportunities and
submit bids as part of our growth strategy.

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Applicable laws and regulations

General

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and
regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry
increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others
in our industry with similar types, quantities and locations of production.

The
following is a summary of the more significant existing environmental, safety and other laws and regulations to which our business operations are subject and with which compliance
may have a material adverse effect on our capital expenditures, earnings or competitive position.

Production Regulation

Our production operations are subject to a number of regulations at federal, state and local levels. These regulations require, among other things, permits for
the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:



State
laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or
integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties
and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or
flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the
number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil and natural gas within its
jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

FERC Matters

The availability, terms and cost of downstream transportation significantly affect sales of natural gas, oil and NGLs. With regard to natural gas, the interstate
transportation and sale for resale is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily
by the Federal Energy Regulatory Commission, or FERC. Since 1985, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas
transportation more accessible to gas

19

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buyers
and sellers on an open-access, non-discriminatory basis. Federal and state regulations govern the rates and terms for access to intrastate natural gas pipeline
transportation, while states alone regulate natural gas gathering activities. With regard to oil and NGLs, the rates and terms and conditions of service for interstate transportation is regulated by
FERC. Tariffs for such transportation must be just and reasonable and not unduly discriminatory. Oil and NGL transportation that is not federally regulated is left to state regulation.

Wholesale
prices for natural gas, oil and NGLs are not currently regulated and are determined by the market. We cannot predict, however, whether new legislation to regulate the price of
energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the
operations of the underlying properties.

Under
the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of
non-interstate pipelines and other natural gas market participants. The Commodity Futures Trading Commission, or the CFTC, also holds authority to monitor certain segments of the physical
and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical sales of natural gas, oil and NGLs, our gathering of any of these energy commodities, and any
related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold
substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal
penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and
taxing authorities.

Federal, state or Indian oil and natural gas leases

In the event we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions,
including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations
and other appropriate permits issued by the Bureau of Land Management, or BLM, or Minerals Management Service or other appropriate federal or state agencies.

Other regulatory matters relating to our pipeline and gathering system assets

The pipelines we use to gather and transport our oil and natural gas are subject to regulation by the Department of Transportation, or DOT, under the Hazardous
Liquids Pipeline Safety Act of 1979, as amended, or the HLPSA, with respect to oil, and the Natural Gas Pipeline Safety Act of 1968, as amended, or the NGPSA, with respect to natural gas. The HLPSA
and NGPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas and hazardous liquids pipeline facilities, including pipelines transporting crude
oil. Where applicable, the HLPSA and NGPSA also require us and other pipeline operators to comply with regulations issued pursuant to these acts that are designed to permit access to and allow copying
of records and to make certain reports available and provide information as required by the Secretary of Transportation.

The
Pipeline Safety Act of 1992, as reauthorized and amended, mandates significant changes and new requirements in the way that the energy industry ensures the safety and integrity of
its pipelines. The law applies to natural gas and hazardous liquids pipelines, including some natural gas gathering pipelines. Central to the law are the requirements it places on each pipeline
operator to prepare and implement an "integrity management program." The Pipeline Safety Act of 1992 mandated a number of other requirements, including increased penalties for violations of safety
standards and qualification

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programs
for employees who perform sensitive tasks. The DOT has established a number of rules carrying out the provisions of this act. The Pipeline and Hazardous Materials Safety Administration of
DOT, or the PHMSA, has established a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We
could incur significant expenses as a result of these laws and regulations.

U.S. federal taxation

The federal government may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand
or our results of operations.

U.S. environmental regulations

The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various
federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic
activities are subject to federal environmental laws and regulations, as they are amended from time to time, including, but not limited to:



Our
domestic activities are also controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation,
storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for
non-compliance with environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking
certain of our activities, limit or prohibit other activities because of protected areas or species, can impose certain substantial liabilities for the clean-up of pollution, impose
certain reporting requirements, regulate remedial plugging operations to prevent future contamination and can require substantial expenditures for compliance. We cannot predict what effect future
regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Under
CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters of the United States, adjoining shorelines and
wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing or remediating a release; (2) administrative, civil or criminal fines or penalties;
or (3) OPA specified damages, such as loss of use, and natural resource damages. The extent of our liability could be extensive depending upon the circumstances of the release. Liability can be
joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and
Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines. State laws governing discharges to water also
provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters.

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CERCLA,
as amended, and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability for costs of investigation and remediation and for
natural resource damages, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a "hazardous substance" into the environment. In practice,
under circumstances where harm is divisible, clean-up costs are usually allocated among the various responsible persons. These classes of persons, or so-called potentially
responsible parties, or PRPs, include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who
disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public
health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted, even under circumstances where
such operations were performed by third parties not under our control, and/or from conditions at third party disposal facilities where wastes from operations were sent. Although CERCLA currently
exempts petroleum (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot assure you that this
exemption will be preserved in any future amendments of the act. Such amendments could have a material impact on our costs or operations. Additionally, our operations may involve the use or handling
of other materials that may be classified as hazardous substances under CERCLA and similar state statutes. We may also be the owner or operator of sites on which hazardous substances have been
released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA. We also do not know of any prior owners or operators of our properties that are named
as PRPs related to their ownership or operation of such properties. Certain states have comparable statutes. In the event hazardous substance contamination is discovered at a site on which we are or
have been an owner or operator, we could be liable for costs of investigation and remediation and natural resource damages.

RCRA
and comparable state and local programs impose requirements on the management, treatment, storage and disposal of both hazardous and nonhazardous solid wastes. Although we believe
we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties
we own or lease or the locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such
parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generate hazardous and nonhazardous solid waste in our
routine operations. While RCRA currently exempts drilling fluids, produced waters, and certain other wastes associated with the exploration, development and production of crude oil or natural gas from
being regulated as hazardous wastes, from time to time, proposals have been made that would reclassify these oil and natural gas wastes as "hazardous wastes" under RCRA, which would make these solid
wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. Adoption of these proposals could have a material impact on our operating
costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact on our operations.

Our
operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The CAA and andogous state laws require new and modified
sources of air pollutants to obtain permits prior to commencing construction. Smaller sources may qualify for exemption from permit requirement of existing authorizations through issuance of permits
by rule or general permits. Major sources of air pollutants are subject to more stringent, federally imposed
requirements including additional operating permits. Federal and state laws designed to control hazardous (i.e., toxic) air pollutants might require installation of additional controls.
Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified
deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forgo construction, modification or operation of certain air emission sources.

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Oil and natural gas exploration and production, and possibly other activities, have been conducted at a majority of our properties by previous owners and operators. Materials from these
operations remain on some of the properties and in certain instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have
acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or
currently owned or operated properties will be material, but we cannot guarantee that result.

If
in the course of our routine oil and natural gas operations surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for
waste handling, remediation and third party actions for damages. Moreover, we are only able to directly control the operations of the wells that we operate. Notwithstanding our lack of control over
wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be attributable to us and may impose legal liabilities upon us.

There
are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act, or CZMA, was passed in 1972 to
preserve and, where possible, restore the natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and
coastal development. States, such as Texas, also have coastal management programs, which provide for, among other things, the coordination among local and state authorities to protect coastal
resources through regulating land use, water, and coastal development. Coastal management programs also may provide for the review of state and federal agency rules and agency actions for consistency
with the goals and policies of the state coastal management plan. In the event our activities trigger these programs, this review of agency rules and actions may impact other agency permitting and
review activities, resulting in possible delays or restrictions of our activities and adding an additional layer of review to certain activities undertaken by us.

We
do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program complying with current
environmental laws and regulations. As these laws and regulations are frequently changed and are subject to interpretation, our assessment regarding the cost of compliance or the extent of liability
risks may change in the future.

We
are also unable to assure you that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with
environmental laws and regulations in the future. For instance, in response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the
Earth's atmosphere, the current session of the U.S. Congress is considering climate change-related legislation to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate
Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United
States between 2012 and 2050. The Lieberman-Warner bill proposes a "cap and trade" scheme of regulation of greenhouse gas emissionsa ban on emissions above a defined reducing annual cap.
Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. Debate and a
possible vote on this bill by the full Senate are anticipated to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of
greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Depending on the particular program, we could
be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels (e.g.,
oil or natural gas) we produce. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 inMassachusetts, et al. v. EPA, the EPA
may regulate carbon dioxide and

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other
greenhouse gas emissions from mobile sources such as cars and trucks, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated
that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been
finalized. The Court's holding inMassachusettsthat greenhouse gases including carbon dioxide fall under the federal Clean Air Act's definition of "air
pollutant" may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain CAA programs. New federal or state laws requiring adoption of
a stringent greenhouse gas control program or imposing restrictions on emissions of carbon dioxide in areas of the United States in which we conduct business could adversely affect our cost of doing
business and demand for the oil and gas we produce.

If
substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result
in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not
available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured
against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and
results of operations.

OSHA and other regulations

We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication
standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about
hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Anti-terrorism security measures.

Our operations and the operations of the natural gas and oil industry in general may be subject to laws and regulations regarding the security of industrial
facilities, including natural gas and oil facilities. The Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security, or DHS, to issue regulations
establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security
risk." The DHS issued an interim final rule, known as the Chemical Facility Anti-Terrorism Standards interim rule, in April 2007 regarding risk-based performance standards to
be attained pursuant to the act and on November 20, 2007 further issued an Appendix A to the interim rule that established the chemicals of interest and their respective threshold
quantities that may trigger compliance with these interim rules. Facilities possessing greater than threshold levels of these chemicals of interest were required to prepare and submit to the DHS in
January 2008 initial screening surveys that the agency would use to determine whether the facilities presented a high level of security risk. Covered facilities that are determined by DHS to pose a
high level of security risk will be notified by DHS and will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory
requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. We have not yet determined the extent to which our
facilities are subject to coverage under the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

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Title to our properties

When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we
usually conduct little or no investigation of
title other than a preliminary review of local mineral records. We do conduct title investigations and, in most cases, obtain a title opinion of local counsel before we begin drilling operations. We
believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are
adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

Our
properties are generally burdened by:



We
believe that none of these burdens either materially detract from the value of our properties or materially interfere with property used in the operation of our business.
Substantially all of our properties are pledged as collateral under our credit agreements.

Our employees

As of December 31, 2007, we employed 689 persons of which 406 were involved in field operations and 283 were engaged in technical, office or administrative
activities. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we
consider our relations with our employees to be good. We also utilize the services of independent consultants on a contract basis.

Forward-looking statements

This Annual Report on Form 10-K contains forward-looking statements, as defined in Section 27A of the Securities Act and
Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements relate to, among other things, the following:



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

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

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cause
our actual results or financial condition to materially differ from our expectations in this Annual Report on Form 10-K, including, but not limited to:



We
believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict,
or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, you should keep in mind the risk
factors and other cautionary statements in this Annual Report on Form 10-K. The risk factors noted in this Annual Report on Form 10-K and other factors noted
throughout this Annual Report on Form 10-K provide examples of risks, uncertainties and events that may cause our actual results to differ materially

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from
those contained in any forward-looking statement. Please see "Item 1A. Risk factors" for a discussion of certain risks of our business and an investment in our common stock.

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

Glossary of selected oil and natural gas terms

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.

Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf.One billion cubic feet of natural gas.

Bcfe.One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Btu.British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5
degrees Fahrenheit.

Commercial Well; Commercially Productive Well.An oil and natural gas well which produces oil and natural gas in sufficient
quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Completion.The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole,
the reporting of abandonment to the appropriate agency.

Developed Acreage.The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well.A well drilled within the proved area of an oil or natural gas reservoir, or which extends a proved
reservoir, to the depth of a stratigraphic horizon known to be productive.

Downspacing Wells.Additional wells drilled between known producing wells to better exploit the reservoir.

Dry Hole; Dry Well.A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.

Exploitation.The continuing development of a known producing formation in a previously discovered field. To maximize the
ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.

Exploratory Well.A well drilled to find and produce oil or natural gas in an unproved area or to find a new reservoir in a
field previously found to be productive of oil or natural gas in another reservoir.

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Farmout.An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on
that location.

Formation.A succession of sedimentary beds that were deposited under the same general geologic conditions.

Full Cost Pool.The full cost pool consists of all costs associated with property acquisition, exploration, and development
activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are
included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross Acres or Gross Wells.The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal Wells.Wells which are drilled at angles greater than 70 degrees from vertical.

Infill drilling.Drilling of a well between known producing wells to better exploit the reservoir.

Mbbl.One thousand stock tank barrels.

Mcf.One thousand cubic feet of natural gas.

Mcfe.One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Mmbbl.One million stock tank barrels.

Mmbtu.One million British thermal units.

Mmcf.One million cubic feet of natural gas.

Mmcf/d.One million cubic feet of natural gas per day.

Mmcfe.One million cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Mmcfe/d.One million cubic feet equivalent per day calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Mmmbtu.One billion British thermal units.

NYMEX.New York Mercantile Exchange.

NGLs.The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under
various levels of higher pressure and lower temperature.

Overriding royalty interest.An interest in an oil and/or natural gas property entitling the owner to a share of oil and
natural gas production free of costs of production.

Present value of estimated future net revenues or PV-10.The present value of estimated future net revenues is an
estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future
capital costs, abandonment costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present
value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates

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have
been made using constant oil, natural gas and NGL prices and operating costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of
estimated future net revenues before income taxes, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas
producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.

Productive Well.A productive well is a well that is not a dry well.

Proved Developed Reserves.Reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production
response that increased recovery will be achieved.

Proved Reserves.The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs
are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves
which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful
testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates
of Proved Reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves;
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil
shales, coal, gilsonite and other such sources.

Proved Undeveloped Reserves.Reserves that are expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain
of production when drilled. Proved Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing
productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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Recompletion.An operation within an existing well bore to make the well produce oil and/or gas from a different, separately
producible zone other than the zone from which the well had been producing.

Reserve Life.The estimated productive life, in years, of a proved reservoir based upon the economic limit of such reservoir
producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this Annual Report on Form 10-K, reserve life is calculated by dividing the
Proved Reserves (on a Mmcfe basis) at the end of the period by production volumes for the previous 12 months.

Reservoir.A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas
that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Royalty interest.An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas
production free of costs of production.

Standardized Measure of discounted future net cash flows or the Standardized Measure.Under the Standardized Measure, future
cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end Proved Reserves. Future
cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes are computed by
applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10%
annual discount rate to arrive at the Standardized Measure.

Stock tank barrel.42 U.S. gallons liquid volume.

Tcf.One trillion cubic feet of natural gas.

Tcfe.One trillion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.

Undeveloped Acreage.Lease acreage on which wells have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and natural gas regardless of whether such acreage contains Proved Reserves.

3-D seismic.Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic
typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Working interest.The operating interest that gives the owner the right to drill, produce and conduct activities on the
property and a share of production.

Workovers.Operations on a producing well to restore or increase production.

Available information

We make our filings with the SEC available, free of charge, on our website atwww.excoresources.comas soon as
reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.

ITEM 1A.    RISK FACTORS

The risk factors noted in this section and other factors noted throughout this Annual Report on Form 10-K, including those risks identified in
"Item 7. Management's discussion and analysis of

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financial
condition and results of operations," describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking
statement.

If
one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this Annual Report on
Form 10-K.

Risks relating to our business

Fluctuations in oil and natural gas prices, which have been volatile at times, may adversely affect our revenues as well as our ability to maintain or
increase our borrowing capacity, repay current or future indebtedness and obtain additional capital on attractive terms.

Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. We are
particularly dependent on prices for natural gas. As of December 31, 2007, 93.3% of our Proved Reserves were natural gas. Historically, oil and natural gas prices have been volatile and are
subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Factors that affect the prices we receive for
our oil and natural gas include:



In
the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. During 2007, the NYMEX price for natural gas has fluctuated from a
high of $8.64 per Mmbtu to a low of $5.38 per Mmbtu, while the NYMEX West Texas Intermediate crude oil price ranged from a high of $98.18 per barrel to a low of $50.48 per barrel. For the five years
ended December 31, 2007, the NYMEX Henry Hub natural gas price ranged from a high of $15.38 per Mmbtu to a low of $4.20 per Mmbtu, while the NYMEX West Texas Intermediate crude oil price ranged
from a high of $98.18 per barrel to a low of $25.24 per barrel. On December 31, 2007, the spot market price for natural gas at Henry Hub was $6.80 per Mmbtu, a 21% increase from
December 31, 2006. In 2007, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $71.17 per Bbl and $6.54 per Mcf compared with 2006
prices of $62.27 per Bbl and $6.77, respectively.

Our
revenues, cash flow and profitability and our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on
attractive terms depend substantially upon oil and natural gas prices.

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Changes in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price our
actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we use to price our oil and natural gas sales sometimes reflect a discount to the relevant benchmark prices, such as
NYMEX. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Increases
in the differential between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our
results of operations and financial condition.

Our use of derivative financial instruments may cause us to forego additional future profits or result in our making cash payments.

To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into derivative financial instrument
arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected
future oil and natural gas production over a fixed period of time. Our derivative financial instruments are subject to mark-to-market accounting treatment. The change in the
fair market value of these instruments is reported in our statement of operations each quarter, which typically result in significant variability in our net income. Derivative financial instruments
expose us to the risk of financial loss and may limit our ability to benefit from increases in oil and natural gas prices in some circumstances, including the following:



Our
use of derivative financial instruments could have the effect of reducing our revenues and the value of our common stock. During the year ended December 31, 2006, we received
cash settlements from our derivative financial instrument contracts totaling $29.4 million. During the year ended December 31, 2007, we received cash settlements from our derivative
financial instrument contracts totaling $108.4 million. For the year ended December 31, 2007, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase
in cash settlement payments (or a decrease in settlements received) of approximately $109.3 million. As of December 31, 2007, the net unrealized losses on our derivative financial
instrument contracts was $81.6 million. The ultimate settlement amount of these unrealized derivative financial instrument contracts is dependent on future commodity prices. In connection with
the TXOK, Winchester, Vernon and Southern Gas acquisitions, we assumed additional derivative financial instruments covering a significant portion of estimated future production. We may incur
significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place. See "Item 7.
Management's discussion and analysis of financial condition and results of operationsLiquidity, capital resources and capital commitmentsDerivative financial instruments."

We will face risks associated with our recent acquisitions relating to difficulties in integrating operations, potential disruptions of operations, and
related negative impact on earnings.

The TXOK, Winchester, Vernon and Southern Gas acquisitions represented a significant increase in our reserves and production. These acquisitions are the largest
acquisitions that we have completed to date.

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These
acquisitions present significant integration challenges for us. In addition to the other general acquisition risks described elsewhere in this section, the magnitude of these
acquisitions could strain our managerial, financial, accounting, technical, operational and administrative resources, disrupt our ongoing business, distract management, divert resources and make it
difficult to maintain our current business standards as well as our internal controls and procedures. We may not be successful in overcoming these risks or any other problems encountered in connection
with these acquisitions, all of which could negatively impact our results of operations and our ability to generate cash needed to service our debt and fund our capital program and other working
capital requirements.

We incurred a substantial amount of indebtedness to fund our 2006 and 2007 acquisitions, which may adversely affect our cash flow and our ability to
operate our business, remain in compliance with debt covenants and make payments on our debt.

In connection with our 2006 and 2007 acquisitions, we have increased our consolidated indebtedness from $461.8 million at December 31, 2005 to
$2.1 billion at December 31, 2007. To service this indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control,
and any failure to meet our debt obligations could harm our business, financial condition and results of operations. If our cash flow and capital resources are insufficient to fund our debt
obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on commercially reasonable terms, or
at all. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt under our credit facilities, which could cause us to default on our obligations and
could impair our liquidity.

We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.

Our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder
our ability to acquire additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale.
If we are unable to conduct successful development activities or acquire properties containing Proved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our
production will generally decline. In addition, if our reserves and production decline, then the amount we are able to borrow under our credit agreements will also decline. We may be unable to locate
additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.

We may not identify all risks associated with the acquisition of oil and natural gas properties, and any indemnifications we receive from sellers may be
insufficient to protect us from such risks, which may result in unexpected liabilities and costs to us.

Generally, it is not feasible for us to review in detail every individual property involved in an acquisition. Our business strategy focuses on acquisitions of
producing oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental
hazards, potential tax and Employee Retirement Security Act, or ERISA, liabilities, and other liabilities and other similar factors. Ordinarily, our review efforts are focused on the higher-valued
properties. For example, in the TXOK, Winchester, Vernon and Southern Gas acquisitions we did not review title or production data for, or physically inspect, every well we acquired. Even a detailed
review of properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant
remedial expenditures, are not necessarily observable even when we inspect

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a
well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.

Even
if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these
problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity. The indemnifications we received in the
TXOK, Winchester, Vernon and Southern Gas acquisitions are subject to floors, caps and time limitations and do not cover all these types of risks.

We may be unable to obtain additional financing to implement our growth strategy.

The growth of our business will require substantial capital on a continuing basis. Due to the amount of debt we have incurred, it may be difficult for us in the
foreseeable future to obtain additional debt financing on an unsecured basis or to obtain additional secured financing other than purchase money indebtedness. If we are unable to obtain additional
capital on satisfactory terms and conditions, we may lose opportunities to acquire oil and natural gas properties and businesses and, therefore, unable to implement our growth strategy.

We may not be successful in managing our growth, which could adversely affect our operations and net revenues.

The pursuit of additional acquisitions is a key part of our strategy. We face challenges in growing our managerial, financial, accounting, technical, operational
and administrative resources to keep up with the pace of the growth of our business and our significant corporate transactions such as the TXOK, Winchester, Vernon and Southern Gas acquisitions. For
example, our rapid growth and significant transactions over the past two years have strained, and could continue to strain, our financial, tax and accounting staff. The size and scope of our business
from an operational, personnel, financial reporting and accounting perspective have substantially increased due to the TXOK, Winchester, Vernon and Southern Gas acquisitions. Our growth could disrupt
our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards as well as internal controls and procedures. Failure to manage our growth
successfully could adversely affect our operations and net revenues through increased operating costs and revenues that do not meet our expectations, as well as adversely affect our ability to satisfy
our disclosure and other obligations. We may also be unable to successfully integrate acquired oil and natural gas properties into our operations or achieve desired profitability.

If we are unable to successfully prevent or address material weaknesses in our internal control over financial reporting, or any other control
deficiencies, our ability to report our financial results on a timely and accurate basis and to comply with disclosure and other requirements may be adversely affected.

As of December 31, 2007, we are required to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Prior to December 31, 2007, we were
not required to make an assessment of the effectiveness of our internal control over financial reporting for that purpose. However, in connection with the 2004 and the 2005 audits of the financial
statements of EXCO Resources, we reported a material weakness in Item 9A of our Annual Report on Form 10-K. In addition, prior to the quarter ended September 30, 2006,
our management concluded that our disclosure controls and procedures were not effective due to a material weakness relating to accounting for income taxes. Although we remediated this material
weakness, we may identify additional material weaknesses or other deficiencies in our internal control over financial reporting in the future.

A
material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material
misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis.

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We will continue to monitor the effectiveness of these and other processes, procedures and controls and will make any further changes management determines appropriate, including to
effect compliance with Section 404 of the Sarbanes-Oxley Act of 2002.

Any
material weaknesses or other deficiencies in our internal control over financial reporting may affect our ability to comply with SEC reporting requirements and the NYSE listing
standards or cause our financial statements to contain material misstatements, which could negatively affect the market price and trading liquidity of our common stock, cause investors to lose
confidence in our reported financial information, as well as subject us to civil or criminal investigations and penalties.

There are inherent limitations in all internal control systems over financial reporting, and misstatements due to error or fraud may occur and not be
detected.

While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002
and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances. Our management, including our Chief
Executive Officer, Chief Financial Officer and Chief Accounting Officer, does not expect that our internal controls and disclosure controls will prevent all error and all fraud. A control system, no
matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect
the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making
can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by
management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or
increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements
due to error or fraud may occur and not be detected.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

Our ability to market our oil and natural gas production will depend upon the availability and capacity of natural gas gathering systems, pipelines and other
transportation facilities. We are primarily dependent upon third parties to transport our products. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or
unavailable due to repairs, outages caused by accidents or other events, or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements.
We experienced production curtailments in the Appalachian Basin during 2005, 2006 and 2007 resulting from capacity restraints and short term shutdowns of certain pipelines for maintenance purposes.
Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply
and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our
ability to produce and market oil and natural gas, the value of our common stock and our ability to pay dividends on our company stock.

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There are risks associated with our drilling activity that could impact the results of our operations.

Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur
significant expenditures to identify and acquire properties and to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively prior to drilling a well that oil
or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of
equipment. We have experienced some delays in contracting for drilling rigs and increasing costs to drill wells. All of these risks could adversely affect our results of operations and financial
condition.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, development, and exploitation
activities.

Our future success will depend on the success of our acquisition, development, and exploitation activities. Our decisions to purchase, develop or otherwise
exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical
and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Our estimates regarding the increase in our reserves and
production resulting from the Winchester, TXOK, Vernon and Southern Gas acquisitions may prove to be incorrect, which could significantly reduce our ability to generate cash needed to service our debt
and fund our capital program and other working capital requirements.

We cannot control the development of the properties we own but do not operate, which may adversely affect our production, revenues and results of
operations.

As of December 31, 2007, third parties operate wells that represent approximately 5% of our Proved Reserves. As a result, the success and timing of our
drilling and development activities on those properties depend upon a number of factors outside of our control, including:



If
drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal
production declines, which may adversely affect our production, revenues and results of operations.

Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported
reserves and our financial condition.

Numerous uncertainties are inherent in estimating quantities of proved oil and natural gas reserves, including many factors beyond our control. This Annual Report
on Form 10-K contains estimates of our proved oil and natural gas reserves and the PV-10 and Standardized Measure of our proved oil and natural gas reserves. These
estimates are based upon reports of our own engineers and our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC as to constant oil
and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated
Proved Reserves. The process of estimating oil and

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natural
gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates
are inherently imprecise evaluations of reserve quantities and future net revenue. Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves may vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value
of reserves, the amount of PV-10 and Standardized Measure described in this Annual Report on Form 10-K, and our financial condition. In addition, our reserves or
PV-10 and Standardized Measure may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas
prices and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes of our reserves. Similarly, a decline in market prices for oil or natural gas
may adversely affect our PV-10 and Standardized Measure. Any of these negative effects on our reserves or PV-10 and Standardized Measure may decrease the value of our common
stock.

We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.

Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:



We
have in the past experienced some of these events during our drilling operations. These events may result in substantial losses to us from:



As
is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these potential losses or liabilities.
Furthermore, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. Due to cost considerations, from time to time we have declined to obtain coverage
for certain drilling activities and have therefore been restricted from conducting these types of drilling activities during the period we were uninsured. We do not carry business interruption
insurance. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our results of operations and
cash flow.

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We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting
our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in
compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur
substantial costs in order to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if
new laws and regulations become applicable to our operations.

Our
business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the
exploration for, production and sale of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business,
financial condition and results of operations. Please see "BusinessApplicable laws and regulations" for a description of the laws and regulations that affect us.

Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.

Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing
the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur
material costs, including
clean-up costs, fines and civil and criminal sanctions and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws
and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in
compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future
environmental laws and regulations which may be more stringent.

Our business substantially depends on Douglas H. Miller, our Chief Executive Officer.

We are substantially dependent upon the skills of Mr. Douglas H. Miller. Mr. Miller has extensive experience in acquiring, financing and
restructuring oil and natural gas companies. We do not have an employment agreement with Mr. Miller or maintain key man insurance. The loss of the services of Mr. Miller could hinder our
ability to successfully implement our business strategy.

We may have write-downs of our asset values, which could negatively affect our results of operations and net worth.

We follow the full cost method of accounting for our oil and natural gas properties. Depending upon oil and natural gas prices in the future, and at the end of
each quarterly and annual period when we are required to test the carrying value of our assets using full cost accounting rules, we may be required to write-down the value of our oil and
natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. We have in the
past experienced ceiling test write-downs with respect to our oil and natural gas properties. Future non-cash ceiling test write-downs could negatively affect our results of operations and
net worth.

We
also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting units exceeds the fair value of those
reporting units, an impairment charge will occur, which could negatively impact our net worth.

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We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas.

Our ability to collect the proceeds from the sale of oil and natural gas from our customers depends on the payment ability of our customer base, which includes
several significant customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. In addition, in recent years, a number of energy
marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our oil and natural gas production.
This reduction in potential customers has reduced market liquidity and, in some cases, has made it difficult for us to identify creditworthy customers. We also sell a portion of our natural gas
directly to end users. We may experience a material loss as a result of the failure of our customers to pay us for prior purchases of our oil or natural gas.

We may experience a decline in revenues if we lose one of our significant customers.

For the twelve months ended December 31, 2007, sales to a regulated natural gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, and an
independent oil and natural gas company, Anadarko and its affiliates, accounted for 20.0% and 12.1%, respectively, of total oil and natural gas revenues. For the twelve months ended
December 31, 2006 and 2005 sales to one industrial customer, Alcan Rolled ProductsRavenswood, LLC, accounted for 4.9% and 10.1%, respectively, of total oil and natural gas
revenues. In 2007, our top four customers accounted for approximately 43.5% of our total oil and natural gas revenues. To the extent any significant customer reduces the volume of its natural gas
purchases from us, we could experience interruption in sales of, or a lower price for, our oil and natural gas.

Competition in our industry is intense and we may be unable to compete in acquiring properties, contracting for drilling equipment and hiring
experienced personnel.

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring
properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a
result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will
permit. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation
activities and has caused significant price increases. We may experience difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these
services and related material and equipment. We are unable to predict how such shortages and price increases will affect our development and exploitation program. Competition has also been strong in
hiring experienced personnel, particularly in petroleum engineering, geoscience, accounting and financial reporting, tax and land professions. In addition, competition is strong for
attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We are often outbid by competitors in our attempts to acquire properties
or companies. All of these challenges could make it more difficult to execute our growth strategy and increase our costs.

The success of our natural gas gathering and transportation business depends upon our ability to continually obtain new sources of natural gas supply,
and any decrease in supplies of natural gas could reduce our transportation revenues.

Our gathering and transportation pipelines are connected to natural gas reserves and wells, for which the production will naturally decline over time, which means
that our cash flows associated with

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these
wells will also decline over time. To maintain or increase throughput levels on our pipelines, we must continually obtain new natural gas supplies. We may not be able to obtain additional third
party contracts for natural gas supplies. The primary factors affecting our ability to connect new supplies of gas and attract new customers to our gathering and transportation pipelines include:
(i) the level of successful drilling activity near our gathering systems and (ii) our ability to compete for the commitment of such additional volumes to our systems.

Fluctuations
in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally
decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations other than our own drilling, the amount of reserves underlying
the wells or the rate at which production from a well will decline. In addition, we have no control over third party producers or their production decisions, which are affected by, among other things,
prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.

We
face strong competition in acquiring new natural gas supplies. Competitors to our pipeline operations include major interstate and intrastate pipelines, and other natural gas
gatherers. Competition for natural gas supplies is primarily based on the location of pipeline facilities, pricing arrangements, reputation, efficiency, flexibility and reliability. Many of our
competitors have greater financial resources than we do.

If
we are unable to maintain or increase the throughput on our gathering and transportation pipelines because of decreased drilling activity in the areas in which we operate or because
of an inability to connect new supplies of gas and attract new customers to our gathering and transportation pipelines, then our business and financial results could be materially adversely affected.

If third-party pipelines and other facilities interconnected to our gathering and transportation pipelines become unavailable to transport or process
natural gas, our revenues and cash flow could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options from our transportation and gathering pipelines for the benefit of our
customers. All of the natural gas transported by our pipelines must be processed by processing plants before delivery into a pipeline for natural gas. We own only one processing plant that treats
certain natural gas products. If the processing plants to which we deliver natural gas were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of
testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers would be unable to deliver natural gas to end markets. Either of such events
could materially and adversely affect our business, results of operations and financial condition.

We do not own all of the land on which our transportation and gathering pipelines and gathering system are located, which could disrupt our operations.

We do not own all of the land on which our transportation and gathering pipelines have been constructed, and we are therefore subject to the possibility of
increased costs to retain necessary land use. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our
loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and
financial condition.

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Risks relating to our indebtedness

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance
with debt covenants and make payments on our debt.

As of December 31, 2007, we had approximately $2.1 billion of indebtedness, including $1.6 billion of indebtedness which is subject to
variable interest rates. Our total interest expense on an annual basis is approximately $131.1 million and would change by approximately $16.4 million for every 1% change in interest
rates.

Our
level of debt could have important consequences, including the following:



Our
ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We
will be unable to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our earnings will be sufficient to allow us to pay the principal and
interest on our debt and meet our other obligations. If we do not have enough money to service our debt, we may be required but unable to refinance all or part of our existing debt, sell assets,
borrow more money or raise equity on terms acceptable to us, if at all. Further, failing to comply with the financial and other restrictive covenants in our credit agreements and the Indenture
governing our senior notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

Together with our subsidiaries, we may incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration
of oil and natural gas producing properties. The restrictions in our debt agreements on our incurrence of additional indebtedness are subject to a number of qualifications and exceptions, and under
certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute
indebtedness. To the extent new

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indebtedness
is added to our current indebtedness levels, the risks described above could substantially increase.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and
any failure to meet our debt obligations could harm our business, financial condition and results of operations.

Our ability to make payments on and to refinance our indebtedness, including our senior notes and loans under our credit agreements, and to fund planned capital
expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and
other factors that are beyond our control, including the prices that we receive for oil and natural gas.

Our
business may not generate sufficient cash flow from operations and future borrowings may not be available to us in an amount sufficient to enable us to pay our indebtedness,
including our senior notes and loans under our credit agreements, or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be
forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on commercially reasonable terms, or at all. In addition,
any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur
additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, which could cause us to default
on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and
engage in other business activities that may be in our best interests.

Our credit agreements contain a number of significant covenants that, among other things, restrict our ability to:



Also,
our credit agreements require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and
financial condition tests may be affected by events beyond our control, and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and
financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise
conduct necessary corporate

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activities.
We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit agreements and
the Indenture governing our senior notes.

A
breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit arrangements. A
default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit arrangements. The accelerated debt would become immediately due and payable. If that
should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

Risks relating to our common stock

Our stock price may fluctuate significantly.

Our common stock began trading on the NYSE on February 9, 2006. An active trading market may not be sustained. The market price of our common stock could
fluctuate significantly as a result of:



Many
of these factors are beyond our control and we cannot predict their potential effects on the price of our common stock. In addition, the stock markets in general can experience
considerable price and volume fluctuations.

Future sales of our common stock may cause our stock price to decline.

As of December 31, 2007, we had 104,578,941 shares of common stock outstanding. All shares are freely tradable by persons other than our affiliates. Sales
of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of
these shares could impair our ability to raise capital through the sale of additional common or preferred stock.

The equity trading markets may be volatile, which could result in losses for our shareholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market
price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.

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Our articles of incorporation permit us to issue preferred stock that may restrict a takeover attempt that you may favor.

Our articles of incorporation permit our board to issue up to 10,000,000 shares of preferred stock and to establish, by resolution, one or more series of
preferred stock and the powers, designations, preferences and participating, optional or other special rights of each series of preferred stock. The preferred stock may be issued on terms that are
unfavorable to the holders of our common stock, including the grant of superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our
liquidation and the designation of conversion rights that entitle holders of our preferred stock to convert their shares into our common stock on terms that are dilutive to holders of our common
stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult. In 2007, we issued 200,000 shares of preferred stock for proceeds of
$2.0 billion to institutional accredited investors in a private placement under the Securities Act of 1933. See "Item 1. Business. Significant transactions during
2007Private placement of preferred stock."

We have not paid dividends on our common stock in the past, and any return on investment has historically been limited to the value of our common stock.

We have never paid cash dividends on our common stock. The payment of dividends will depend on our earnings, capital requirements, financial condition, prospects
and other factors our board of directors may deem relevant. If we do not pay dividends, our common stock may be less valuable because a return on your investment will only occur if our stock price
appreciates. In addition, our credit agreements and the Indenture governing our senior notes restrict our ability to pay dividends.

Risks relating to our preferred stock

The holders of 7.0% Preferred Stock and Hybrid Preferred Stock have rights that could adversely affect an investment in our common stock.

On March 30, 2007, we completed the Private Placement of an aggregate of $390.0 million of 7.0% Preferred Stock and $1.61 billion of Hybrid
Preferred Stock to accredited investors pursuant to the terms and conditions of a Preferred Stock Purchase Agreement dated March 28, 2007. The purchase price for each share was $10,000 (which
equaled the liquidation preference per share on March 30, 2007). The designations, preferences, limitations and relative voting rights of the Hybrid Preferred Stock are identical to the
designations, preferences, limitations and relative voting rights of the 7.0% Preferred Stock, including the right to dividends and the right to convert into shares of our common stock. The 7.0%
Preferred Stock and the Hybrid Preferred Stock are convertible into shares of our common stock at an initial conversion price of $19.00 per share, subject to adjustment.

The
initial $19.00 per share conversion price of the 7.0% Preferred Stock and the Hybrid Preferred Stock equates to each share of 7.0% Preferred Stock and Hybrid Preferred Stock being
initially convertible into approximately 526.3 shares of our common stock, subject to adjustment for fractional shares. The Statement of Designation for each series of the 7.0% Preferred Stock and the
Hybrid Preferred Stock contain weighted average anti-dilution provisions that provide for an adjustment to the conversion price of the 7.0% Preferred Stock and the Hybrid Preferred Stock
upon (i) the issuance of stock, convertible securities or options at a price below the then-current conversion price, (ii) the issuance of options to holders of common stock
at less than the current market price, (iii) a dividend or distribution to holders of common stock in excess of $0.06 per share in any quarter or (iv) an equity tender offer or share
repurchase by us at a price in excess of the current market price. The exact number of shares of common stock into which the 7.0% Preferred Stock and the Hybrid Preferred Stock may ultimately be
converted may vary over time as a result of the effects of these anti-dilutive adjustments to the conversion price. Assuming no adjustment to the $19.00 conversion price, the 7.0%

44

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Preferred
Stock and the Hybrid Preferred Stock are convertible into a total of 105,263,115 shares of our common stock.

The
holders of 7.0% Preferred Stock and Hybrid Preferred Stock also have the right to receive cash dividends at the rate of 7.0% per annum prior to March 30, 2013 and at the rate
of 9.0% per annum thereafter. In lieu of paying cash dividends, we may, under certain circumstances prior to March 30, 2013, pay such dividend at a rate of 9.0% per annum by adding the dividend
to the liquidation preference of the shares of 7.0% Preferred Stock and Hybrid Preferred Stock. Upon the occurrence of a change of control, holders of 7.0% Preferred Stock and Hybrid Preferred Stock
may require us to repurchase their shares for cash at the liquidation preference plus accumulated dividends. These anti-dilution, dividend and liquidation provisions could substantially
dilute our common shareholders' interest and may otherwise adversely affect an investment in our common stock.

The holders of 7.0% Preferred Stock and Hybrid Preferred Stock could restrict our ability to enter into various corporate transactions that may be
beneficial to our business strategy.

Without the prior consent of the holders of our 7.0% Preferred Stock and Hybrid Preferred Stock, we are generally prohibited from, among other things, the
following:



These
restrictions may limit our ability to engage in activities which could expand our business, including obtaining future financing, making needed capital expenditures, or taking
advantage of business opportunities such as strategic acquisitions and dispositions.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.    PROPERTIES

Corporate offices

We lease office space in Dallas, Texas, Akron, Ohio, Tulsa, Oklahoma, Shreveport, Louisiana and The Woodlands, Texas. We also have small offices for technical and
field operations in Texas,

45

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Oklahoma,
Louisiana, Colorado, Ohio and West Virginia. The table below summarizes our material corporate leases.

Location

Approximate square footage

Approximate monthly payment

ExpirationDallas, Texas

75,000

$
103,000

June 30, 2013Akron, Ohio

30,700


48,100

December 15, 2012Tulsa, Oklahoma

22,700


24,500

May 31, 2011Shreveport, Louisiana

15,300


12,100

September 30, 2008The Woodlands, Texas

13,800


28,700

June 30, 2012


Other

We have described our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling activity in "Item 1. Business"
of this Annual Report on Form 10-K.

ITEM 3.    LEGAL PROCEEDINGS

On October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styled PRC Holdings, LLC, et
al. v. North Coast Energy, Inc.and was filed in the Circuit Court of Roane County, West Virginia. This action has
been removed to the United States District Court for the Southern District of West Virginia. The action has been brought by certain landowners and lessors in West Virginia for themselves and on behalf
of other similarly situated landowners and lessors in West Virginia. The lawsuit alleges that North Coast Energy, Inc. has not been paying royalties to the plaintiffs in the manner required
under the applicable leases, has provided misleading documentation to the plaintiffs regarding the royalties due, and has breached various other contractual, statutory and fiduciary duties to the
plaintiffs with regard to the payment of royalties. In a case styledThe Estate of Garrison Tawney v. Columbia Natural Resources, LLCannounced
in June 2006, the West Virginia Supreme Court held that language such as "at the wellhead" and similar language contained in leases when used in describing how to calculate royalties due lessors was
ambiguous and, therefore, should be construed strictly against the lessee. Accordingly, in the absence of express language in a lease that is intended to allocate between a lessor and lessee
post-production costs such as the costs
of marketing the product and transporting it to the point of sale, no post-production costs may be deducted from the lessor's royalty payment due from the lessee. The claims alleged by the
plaintiffs in the lawsuit filed against us are similar to the claims alleged in theTawneycase. Plaintiffs are seeking common law and statutory
compensatory and punitive damages, interest and costs and other remedies. The Company is vigorously defending the existing lawsuit. The action is in a very preliminary stage. The preliminary status of
the lawsuit leaves the ultimate outcome of this litigation uncertain. The Company believes that it has substantial defenses to this lawsuit and that the adverse affects from this litigation, if any,
are reflected in our financial statements and we do not expect the ultimate outcome of the lawsuit to have a material effect on our financial position, results of operations or cash flows.

In
the ordinary course of business, we are periodically a party to lawsuits and claims. 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 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

For a description of matters related to the resignation of Vincent J. Cebula as the Series B Preferred Stock Director and his simultaneous election as a
general Preferred Stock Director by the holders of our Preferred Stock and the election of B. James Ford to our board of directors as the

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Series B
Preferred Stock Director by the holders of our Preferred Stock, please see our Current Report on Form 8-K dated December 1, 2007 and filed with the SEC on
December 5, 2007 and incorporated herein by reference.

PART II

ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market information for our common stock

Prior to February 14, 2006, we were 100% owned by EXCO Holdings. Effective February 9, 2006, our common stock began trading on a "when issued" basis
on the NYSE under the symbol "XCO".

The
following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the NYSE:

Common StockHigh

LowYear ended December 31, 2007:First Quarter

$
18.35

$
15.07Second Quarter


19.70


15.89Third Quarter


18.27


14.69Fourth Quarter


17.48


13.61Year ended December 31, 2006:First Quarter

$
13.70

$
11.81Second Quarter


13.03


9.55Third Quarter


15.00


10.05Fourth Quarter


18.20


12.15


Our shareholders

According to our transfer agent, Continental Stock Transfer & Trust Company, there were approximately 146 holders of record of our common stock on
December 31, 2007 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders).

Our dividend policy

We have not paid any cash dividends on our common stock. In addition, our credit agreements currently prohibit us from paying dividends on our common stock and
the Indenture governing our senior notes contains restrictions on our payment of dividends. Even if our credit agreement permitted us to pay cash dividends, we can make those payments only from our
surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying
those dividends we would be able to pay our liabilities as they become due.

ITEM 6.    SELECTED FINANCIAL DATA

The following table presents our selected historical financial and operating data. You should read this financial data in conjunction with "Item 7.
Management's discussion and analysis of financial condition and results of operations," our consolidated financial statements, the notes to our consolidated financial statements and the other
financial information, included in this Annual Report on Form 10-K. This information does not replace the consolidated financial statements. We have

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completed
numerous acquisitions and dispositions since 2003 that materially impact the comparability of this data between periods.

The
selected financial data for the 209 day period from January 1, 2003 to July 28, 2003 is referred to as public predecessor and represents accounting periods when
EXCO was a publicly traded company on the Nasdaq. On July 29, 2003, EXCO completed a going private transaction which resulted in a change of accounting basis. The selected financial data for
the 156 day period from July 29, 2003 to December 31, 2003, the twelve months ended December 31, 2004 and the 275 day period from January 1, 2005 to
October 2, 2005 is referred to as predecessor and represents the period of time when EXCO was privately held. The period from the Equity Buyout on October 3, 2005, which resulted in an
additional change in accounting basis, through December 31, 2007 is referred to as successor.

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Selected consolidated financial and operating data

|                                                                                |                                                          | Public Predecessor |        | Predecessor |   | Successor |        
|------------------------------------------------------------------------------- | -------------------------------------------------------- | ------------------ | ------ | ----------- | - | --------- | -------
|
|Statement of operations data(1):                                                |                                                          |                    |        |             |   |           |        
|Revenues and other income:                                                      |                                                          |                    |        |             |   |           |        
|                                                                                | Oil and natural gas                                      |                    | $      | 22,403      |   | $         | 21,767 
|                                                                                | Derivative financial instruments(2)                      |                    |        |            |   |           | (10,800
|                                                                                | Other income                                             |                    |        | (1,129      | ) |           | (141   
|                                                                                |                                                          |                    |        |             |   |           |        
|                                                                                | Total revenues and other income                          |                    |        | 21,274      |   |           | 10,826 
|                                                                                |                                                          |                    |        |             |   |           |        
|Costs and expenses:                                                             |                                                          |                    |        |             |   |           |        
|                                                                                | Oil and natural gas production                           |                    |        | 11,380      |   |           | 7,331  
|                                                                                | Depreciation, depletion and amortization                 |                    |        | 5,125       |   |           | 5,413  
|                                                                                | Accretion of discount on asset retirement obligations(3) |                    |        | 320         |   |           | 205    
|                                                                                | General and administrative(4)                            |                    |        | 11,347      |   |           | 3,874  
|                                                                                | Interest expense                                         |                    |        | 1,058       |   |           | 1,921  
|                                                                                |                                                          |                    |        |             |   |           |        
|                                                                                | Total costs and expenses                                 |                    |        | 29,230      |   |           | 18,744 
|                                                                                | Equity in income of TXOK Acquisition, Inc.               |                    |        |            |   |           |       
|                                                                                |                                                          |                    |        |             |   |           |        
|Income (loss) before income taxes                                               |                                                          |                    | (7,956 | )           |   | (7,918    | )      
|Income tax expense (benefit)                                                    |                                                          |                    | (181   | )           |   | (7,764    | )      
|                                                                                |                                                          |                    |        |             |   |           |        
|Income (loss) before discontinued operations and change in accounting principle |                                                          |                    | (7,775 | )           |   | (154      | )      
|                                                                                |                                                          |                    |        |             |   |           |        
|Discontinued operations:                                                        |                                                          |                    |        |             |   |           |        
|                                                                                | Income (loss) from discontinued operations               |                    |        | 13,534      |   |           | 6,217  
|                                                                                | Gain on disposition of Addison Energy Inc.               |                    |        |            |   |           |       
|                                                                                | Income tax expense                                       |                    |        | 4,982       |   |           | 1,917  
|                                                                                |                                                          |                    |        |             |   |           |        
|Income from discontinued operations                                             |                                                          |                    | 8,552  |             |   | 4,300     |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Income (loss) before change in accounting principle                             |                                                          |                    | 777    |             |   | 4,146     |        
|Cumulative effect of change in accounting principle, net of income tax          |                                                          |                    | 255    |             |   |          |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Net income (loss)                                                               |                                                          |                    | 1,032  |             |   | 4,146     |        
|Dividends on preferred stock                                                    |                                                          |                    | (2,620 | )           |   |          |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Net income (loss) available to common shareholders                              |                                                          | $                  | (1,588 | )           | $ | 4,146     |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Basic income (loss) per share from continuing operations                        |                                                          | $                  | (1.25  | )           | $ |          |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Basic income (loss) per sharetotal                                             |                                                          | $                  | (0.19  | )           | $ | 0.04      |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Diluted income (loss) per share from continuing operations                      |                                                          | $                  | (1.25  | )           | $ |          |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Diluted income (loss) per sharetotal                                           |                                                          | $                  | (0.19  | )           | $ | 0.04      |        
|                                                                                |                                                          |                    |        |             |   |           |        
|Weighted average common and common equivalent shares outstanding:               |                                                          |                    |        |             |   |           |        
|                                                                                | Basic                                                    |                    |        | 8,084       |   |           | 115,947
|                                                                                | Diluted                                                  |                    |        | 8,084       |   |           | 115,947

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Selected consolidated financial and operating data (continued)

|                                |                                            | Public
Predecessor |   | Predecessor |   | Successor |         
|------------------------------- | ------------------------------------------ | ------------------ | - | ----------- | - | --------- | --------
|
|Statement of cash flow data:(2) |                                            |                    |   |             |   |           |         
|Net cash provided by (used in): |                                            |                    |   |             |   |           |         
|                                | Operating activities                       |                    | $ | 20,418      |   | $         | 21,495  
|                                | Investing activities                       |                    |   | (23,520     | ) |           | (237,623
|                                | Financing activities                       |                    |   | 9,982       |   |           | 214,284 
|Balance sheet data:(2)          |                                            |                    |   |             |   |           |         
|                                | Current assets                             |                    |   | n/a         |   | $         | 31,641  
|                                | Total assets                               |                    |   | n/a         |   |           | 505,056 
|                                | Current liabilities                        |                    |   | n/a         |   |           | 45,188  
|                                | Long-term debt, less current maturities    |                    |   | n/a         |   |           |        
|                                | Shareholders' equity                       |                    |   | n/a         |   |           | 183,895 
|                                | Total liabilities and shareholders' equity |                    |   | n/a         |   |           | 505,056 

---

50

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our
financial statements and the related notes to those statements included elsewhere in this Annual Report on Form10-K. In addition to historical financial information, the following
discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those
anticipated in these forward-looking statements as a result of many factors including those discussed under "risk factors" and elsewhere in this Annual Report on
Form 10-K.

Overview and history

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas
properties and, until February 10, 2005, in Canada. We expect to continue to grow by leveraging our management team's experience, exploiting our multi-year inventory of development
drilling locations and exploitation projects, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive derivative
financial instrument program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on
investments, and manage our capital structure. In 2006 and 2007, we closed acquisitions of producing properties, undeveloped acreage, undeveloped properties and oil and natural gas gathering and
transportation facilities totaling $2.1 billion and $2.5 billion, respectively. In 2007, we drilled 506 wells and completed 495 gross (397.2 net) wells with a 98% drilling success rate.
Our 2007 development, exploitation and other oil and natural gas property capital spending activities totaled $487.2 million. In addition, our midstream and corporate capital expenditures
totaled $48.3 million. Our acquisitions in 2007 were funded, in part, by a $2.0 billion private placement of preferred stock. We also amended our credit agreements in 2007 to reflect the
increased borrowing capacity resulting from our acquisitions. Our 2008 capital budget, approved by our Board of Directors, totals $625.2 million. We expect to drill and complete over 600 gross
(approximately 526 net) wells in 2008, along with other activities.

Oil
and natural gas prices have historically been volatile. During 2007, the NYMEX price for natural gas has fluctuated from a high of $8.64 per Mmbtu to a low of $5.38 per Mmbtu. On
December 31, 2007, the spot market price for natural gas at Henry Hub was $6.80 per Mmbtu, a 21% increase from December 31, 2006. The price of oil has shown similar volatility. In 2007,
our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $71.17 per Bbl and $6.54 per Mcf compared with 2006 prices of $62.27 per Bbl and $6.77
per Mcf, respectively. The volatile commodity price environment from 2005 through 2007, which was accentuated in 2005 by historical high prices for natural gas after the hurricanes in the third
quarter of 2005, caused an increase in demand for drilling rigs, field supplies and related oil field service costs. EXCO, as well as other producers of oil and natural gas, experienced some
difficulty in timely scheduling drilling and related services during this period. However, we have not encountered any significant operational problems or operational delays as a result of these
scheduling difficulties. We cannot predict the impact that the continuing volatility in oil and natural gas prices could cause to our operating revenues, results of operations, or capital budgets nor
can we predict the impact on the pricing for drilling rigs and related oil field services. Management continuously monitors its operations and capital budget and employs the use of derivative
financial instruments to lessen the impact of fluctuating prices for oil and natural gas.

Like
all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time.
We attempt to overcome this natural decline by drilling to identify and develop additional reserves and by acquisitions.

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Our
future growth will depend upon our ability to continue to identify and add oil and natural gas reserves in excess of production at a reasonable cost. We will maintain our focus on
the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

We
also face the challenge of financing future acquisitions. Following completion of our initial public offering, or IPO, in February 2006, we amended our revolving credit agreement with
our banking syndicate. As a result of our 2006 and 2007 acquisitions our credit agreements have been further amended. We also completed a $2.0 billion private placement of preferred stock in
March 2007 and used the proceeds to fund acquisitions and reduce debt in our credit agreements. On February 20, 2008, the EXCO Resources Credit Agreement had a borrowing base of
$1.2 billion, $920.5 million of which was drawn, and the EPOP Credit Agreement had a borrowing base of $1.3 billion, $1.1 billion of which was drawn. We believe we will
have adequate unused borrowing capacity under our credit agreements and available cash flow from operations to fund capital development and working capital needs for the next 12 months. Funding
for future acquisitions may require additional sources of financing, which may not be available.

Critical accounting policies

In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified
the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve the most
complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our Proved Reserves, accounting for business combinations, accounting for
derivatives, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.

We
prepared our consolidated financial statements for inclusion in this report in accordance with GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and
requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is
a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.

Estimates of Proved Reserves

The Proved Reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve
estimate is a function of:



Because
these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural
gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

You
should not assume that the present value of future net cash flows represents the current market value of our estimated Proved Reserves. In accordance with SEC requirements, we based
the estimated discounted future net cash flows from Proved Reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices
and costs as

52

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of
the date of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates.

Proved
Reserves quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net
income. A decline in the estimate of Proved Reserves may result from lower market prices, and a decline may make it uneconomical to drill or produce from higher cost fields. In addition, a
decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.

Proved
Reserves are defined as the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Reservoirs
are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes
(i) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (ii) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves
which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful
testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates
of Proved Reserves do not include the following: (i) oil that may become available from known reservoirs but is classified separately as indicated additional reserves;
(ii) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (iii) crude oil
and natural gas, that may occur in undrilled prospects; and (iv) crude oil and natural gas that may be recovered from oil shales, coal, gilsonite and other such sources.

Business combinations

We follow SFAS No. 141 "Accounting for Business Combinations", or SFAS No. 141, to record our acquisitions of oil and natural gas properties or
entities which we acquire. SFAS No. 141 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being
recognized as goodwill. Application of SFAS No. 141 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require
the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.

Accounting for derivatives

We use derivative financial instruments to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition
activities. Our objective in entering into these derivative financial instruments is to manage price fluctuations and achieve a more predictable cash flow to fund our development, acquisition
activities and support debt incurred with our acquisitions. These derivative financial instruments are not held for trading purposes. We do not

53

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designate
our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative's fair value as a component of current earnings.

Share-based payments

We account for share-based payments to employees using the methodology prescribed in SFAS No. 123(R) and related interpretations. At December 31,
2007, our employees and directors held options under EXCO's 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 12,402,773 shares of EXCO common stock at prices ranging
from $7.50 per share to $18.44 per share. The options expire ten years from the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the
options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of grant. We use the Black-Scholes model to calculate the fair value of issued options. The
gross fair value of the granted options using the Black-Scholes model range from $2.29 per share to $6.53 per share. SFAS No. 123(R) requires share-based compensation be recorded with cost
classifications consistent with cash compensation. EXCO uses the full cost method to account for its oil and natural gas properties. As a result, part of our share-based payments are capitalized.
Total share-based compensation for 2007 was $15.0 million, of which $2.4 million was capitalized as part of our oil and natural gas properties. In 2006, a total of $7.9 million of
share-based compensation was incurred, of which $1.4 million was capitalized.

Accounting for oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives; the full cost method or the
successful efforts method.

We
use the full cost method of accounting, which involves capitalizing all costs associated with the acquisition, exploration, exploitation and development of oil and natural gas
properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs are not subject to
depletion. We review our unproved oil and natural gas property costs on an ongoing basis, and we expect these costs to be evaluated in one to seven years and transferred to the depletable portion of
the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus costs of acquired proved
and unproved leaseholds.

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

At
the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future
net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). Until February 10, 2005, this ceiling
test calculation was done separately for the United States and for our Canadian subsidiary full cost pools. When computing our ceiling test, we evaluate the limitation at the end of each reporting
period date. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation for price changes that occur after the balance
sheet to assess impairment as permitted by Staff Accounting Bulletin Topic 12Oil and Gas Producing Activities. In addition, in July 2007 we sought and received an exemption from the SEC
to exclude the proved oil and natural gas properties of the Winchester acquisition, and those acquired in the Vernon Acquisition and the Southern Gas Acquisition from our ceiling test for a period of
12 months from the closing date of each acquisition,

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provided
that we could demonstrate beyond a reasonable doubt that the fair value of the oil and natural gas reserves exceeded their unamortized carrying costs. The exemption related to Winchester
expired September 30, 2007 and therefore the proved oil and natural gas properties of Winchester were included in our December 31, 2007 ceiling test calculation. The exemption for the
Vernon Acquisition will expire on March 30, 2008 and the exemption for the Southern Gas Acquisition will expire on May 2, 2008.

The
quarterly calculation of the ceiling test is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in
projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing 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.

Goodwill

As a result of the Equity Buyout on October 3, 2005, which required the application of the purchase method of accounting pursuant to SFAS No. 141,
goodwill of $220.0 million was recognized. Additional goodwill of $250.1 million was recognized from our 2006 acquisitions. As of December 31, 2007, our consolidated goodwill
totals $470.1 million. Our strategy is to concentrate on accumulating assets in East Texas, North Louisiana, the Mid-Continent region and Appalachia. We believe the strategic value
paid for the assets substantiates the goodwill we have incurred.

None
of the goodwill is currently deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, "Goodwill and Intangible Assets," or SFAS No. 142,
goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair
market value of the business
operations with which goodwill is associated, are subject to various assumptions and judgments. Actual future results of these assumptions could differ as a result of economic changes which are not
within our control. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations.

Asset retirement obligations

We follow SFAS No. 143 to account for legal obligations associated with the retirement of long-lived assets. SFAS No. 143 requires these
obligations be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related
long-lived asset and allocated to expense over the useful life of the asset. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the
industry. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.

Accounting for income taxes

Income taxes are accounted for using the liability method of accounting in accordance with SFAS No. 109, "Accounting for Income Taxes," or SFAS
No. 109. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. Deferred taxes are recorded to reflect the tax
benefits and consequences of future years' differences between the tax basis of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax
assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

55

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In
July 2006, the Financial Accounting Standards Board, or FASB, issued Financial Interpretation No. 48, "Accounting for Uncertainty in Income Taxes," or FIN 48.
FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with Statement of Financial Accounting Standards, or SFAS,
No. 109, "Accounting for Income Taxes." FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertainties relating to tax positions
that a company has taken or expects to take on a tax return. We adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on our consolidated
financial position or results of operations.

Recent accounting pronouncements

The FASB issued FASB Staff Position EITF 00-19-2 "Accounting for Registration Payment Arrangements," or FSP
00-19-2, on December 21, 2006. FSP 00-19-2 requires contingent obligations to make future payments under a registration payment arrangement to be
recognized separately in accordance with SFAS No. 5, "Accounting for Contingencies," or SFAS No. 5. SFAS No. 5 requires that an estimated loss from a loss contingency be accrued
if the loss is probable and can reasonably be estimated. Our 7.0% Preferred Stock and Hybrid Preferred Stock contain requirements for EXCO, in certain circumstances, to register shares on behalf of
the preferred stockholders. On September 5, 2007, we filed an automatically effective registration statement on Form S-3 with the SEC to register for resale the shares of
common stock issuable upon conversion of the Series A-1 7.0% Preferred Stock and the Series A-1 Hybrid Preferred Stock. If such registration deadlines are not
met, or a prior registration statement ceases to remain effective, we may be obligated to pay liquidated damages. We adopted FSP 00-19-2 upon issuance of the 7.0% Preferred
Stock and the Hybrid Preferred Stock. We do not believe any of the contingencies associated with the registration rights of the preferred stockholders are probable as of December 31, 2007 and
therefore they are not valued separately at December 31, 2007.

In
September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements," or SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in
GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years for
financial assets and liabilities. In February 2008, the FASB issued a one year deferral for non-financial assets and liabilities. We adopted SFAS No. 157 for financial instruments
on January 1, 2008. We will adopt SFAS No. 157 for non-financial assets and liabilities on January 1, 2009. The adoption of SFAS No. 157 is not expected to have
a significant effect on our financial statements.

In
February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial LiabilitiesIncluding an Amendment of FASB Statement
No. 115," or SFAS No. 159. SFAS No. 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established
by SFAS No. 159 permits us to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected
are to be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and as
such, was adopted by us on January 1, 2008. The adoption of SFAS No. 159 is not expected to have a significant effect on our financial statements.

In
December 2007, the FASB issued SFAS No. 141(R), "Business Combinations," or SFAS No. 141(R). SFAS No. 141(R) replaces SFAS No. 141. SFAS No. 141(R)
broadens the scope of business combinations to include bargain purchases and combinations of related companies, provides guidance on measuring goodwill and requires acquisition costs to be separate
from the value of assets and liabilities purchased. SFAS No. 141(R) is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be
adopted by us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 141(R) on our financial statements.

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In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements," or SFAS No. 160. SFAS No. 160 amends Accounting
Research Bulletin 51, or ARB 51. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements separate from the
parent's equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. It also amends certain of ARB
No. 51's consolidation procedures for consistency with the requirements of SFAS No. 141(R). SFAS No. 160 also includes expanded disclosure requirements regarding the interests of
the parent and its noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be adopted by
us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 160 on our financial statements.

Our results of operations

Due to the application of purchase accounting for the Equity Buyout in October 2005, our results of operations contain predecessor and successor periods. Because
the application of purchase accounting can inhibit meaningful comparison of historical results before and after such transactions, we analyzed the impact of the Equity Buyout on our statements of
operations. We believe that our results of operations for 2005, 2006 and 2007 are comparable on an annual basis except as it relates to depreciation, depletion and amortization expenses resulting from
a change in basis of the underlying properties in 2005. As a result we believe that the non-GAAP measure for 2005, discussed below, provides a more meaningful basis for comparing our
results of operations. A summary of key financial

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data
for 2005, 2006 and 2007 related to our results of operations for the years then ended is presented below.

|                                                                                   |                                                                   | Predecessor                                      |          | Successor |          |        |         | Successor |          | Year to year change |         
|---------------------------------------------------------------------------------- | ----------------------------------------------------------------- | ------------------------------------------------ | -------- | --------- | -------- | ------ | ------- | --------- | -------- | ------------------- | --------
|
|Production:                                                                        |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Oil (Mbbls)                                                       |                                                  |          | 375       |          |        | 116     |           |          | 491                 |         
|                                                                                   | Natural gas (Mmcf)(a)                                             |                                                  |          | 15,490    |          |        | 5,112   |           |          | 20,602              |         
|                                                                                   | Total production (Mmcfe)                                          |                                                  |          | 17,740    |          |        | 5,808   |           |          | 23,548              |         
|Oil and natural gas revenues before derivative financial instrument activities:    |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Oil revenues                                                      |                                                  | $        | 19,528    |          | $      | 6,666   |           | $        | 26,194              |         
|                                                                                   | Natural gas sales(a)                                              |                                                  |          | 113,293   |          |        | 63,395  |           |          | 176,688             |         
|                                                                                   |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Total oil and gas sales                                           |                                                  | $        | 132,821   |          | $      | 70,061  |           | $        | 202,882             |         
|                                                                                   |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|Derivative financial instruments:                                                  |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Cash settlements on derivative financial instruments              |                                                  | $        | (62,842   | )        | $      | (22,210 | )         | $        | (85,052             | )       
|                                                                                   | Non-cash change in fair value of derivative financial instruments |                                                  |          | (114,411  | )        |        | 21,954  |           |          | (92,457             | )       
|                                                                                   |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   |                                                                   | Total derivative financial instrument activities |          | $         | (177,253 | )      | $       | (256      | )        | $                   | (177,509
|                                                                                   |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|Average sales price (before cash settlements of derivative financial instruments): |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Oil (Bbl)                                                         |                                                  | $        | 52.07     |          | $      | 57.47   |           | $        | 53.35               |         
|                                                                                   | Natural gas (per Mcf)                                             |                                                  |          | 7.31      |          |        | 12.40   |           |          | 8.58                |         
|                                                                                   | Natural gas equivalent (per Mcfe)                                 |                                                  |          | 7.49      |          |        | 12.06   |           |          | 8.62                |         
|Oil and natural gas production costs:                                              |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Oil and natural gas operating costs                               |                                                  | $        | 14,581    |          | $      | 5,485   |           | $        | 20,066              |         
|                                                                                   | Production and ad valorem taxes                                   |                                                  |          | 7,576     |          |        | 3,464   |           |          | 11,040              |         
|                                                                                   | Depreciation, depletion and amortization                          |                                                  |          | 24,687    |          |        | 14,071  |           |          | 38,758              |         
|                                                                                   | General and administrative(c)                                     |                                                  |          | 89,442    |          |        | 6,375   |           |          | 95,817              |         
|                                                                                   | Interest expense                                                  |                                                  |          | 26,675    |          |        | 19,414  |           |          | 46,089              |         
|Expenses (per Mcfe):                                                               |                                                                   |                                                  |          |           |          |        |         |           |          |                     |         
|                                                                                   | Oil and natural gas operating costs                               |                                                  | $        | 0.82      |          | $      | 0.94    |           | $        | 0.85                |         
|                                                                                   | Production and ad valorem taxes                                   |                                                  |          | 0.43      |          |        | 0.60    |           |          | 0.47                |         
|                                                                                   | Depreciation, depletion and amortization                          |                                                  |          | 1.39      |          |        | 2.42    |           |          | 1.65                |         
|                                                                                   | General and administrative                                        |                                                  |          | 5.04      |          |        | 1.10    |           |          | 4.07                |         
|Net income (loss)(d)                                                               |                                                                   | $                                                | (137,216 | )         | $        | 16,350 |         | $         | (120,866 | )                   | $       
|Preferred stock dividends                                                          |                                                                   |                                                  |         |           |          |       |         |           |         |                     |         
|Income (loss) available to common shareholders                                     |                                                                   | $                                                | (137,216 | )         | $        | 16,350 |         | $         | (120,866 | )                   | $       

---

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The following is a discussion of our financial condition and results of operations for the years ended December 31, 2005, 2006 and 2007.
Information presented for the year ended December 31, 2005 represents the non-GAAP combined total for the 275 day period from January 1, 2005 to October 2, 2005
(predecessor) and the 90 day period from October 3, 2005 to December 31, 2005 (successor).

The
comparability of our results of operations from 2005, 2006 and 2007 is impacted by:



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:



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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 the oil and natural gas from any producing well in which we have or may acquire an interest.

Marketing arrangements and backlog

We produce oil and natural gas. We do not refine or process the oil we produce. We sell the majority of the oil we produce under short-term contracts
using market sensitive pricing. The majority of our oil 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 natural gas 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 prices received for natural gas sold on the spot market varies daily, reflecting changing
market conditions. We also gather and transport natural gas for other producers in fields which we operate for which we are compensated.

For
the twelve months ended December 31, 2007, sales to a regulated natural gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, and an independent oil and
natural gas company, Anadarko and its affiliates, accounted for 20.0% and 12.1%, respectively, of total oil and natural gas revenues. For the twelve months ended December 31, 2006 and 2005
sales to one industrial customer, Alcan Rolled ProductsRavenswood, LLC, accounted for 4.9% and 10.1%, respectively, of total oil and natural gas revenues. The loss of any
significant customer may cause a temporary interruption in sales of, or a lower price for, our oil and natural gas, but we believe that the loss of any one customer would not have a material adverse
effect on our results of operations or financial condition.

We
may be unable to market all the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable price and contractual terms.
Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of economically recoverable oil and natural
gas contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

We
engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this
situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of
our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil
and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated.

Summary

For purposes of comparative analysis, we have combined the predecessor and successor operating results for the 2005 periods and refer to the combined results as
non-GAAP 2005.

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For
the year ended December 31, 2007, we had a net loss available to common shareholders of $83.3 million compared to net income of $139.0 million for 2006. For the
2005 non-GAAP combined period we incurred a net loss from continuing operations of $120.9 million and net income of $1.2 million, reflecting a gain on the sale of our
Canadian subsidiary of $122.0 million.

The
impact of acquisitions and derivative financial instruments are significant to our results of operations. During 2007, we closed approximately $2.5 billion of acquisitions of
oil and natural gas properties which significantly increased our production, revenues and operating costs. In addition, we do not designate our derivative financial instruments as hedges. Therefore,
we mark the changes in the fair value of our unsettled derivative financial instruments to market at the end of each reporting period. Due to significant fluctuations in the price of oil and natural
gas during 2005, 2006 and 2007, the impacts of derivative financial instruments, including the non-cash mark-to-market impacts, totaled losses of
$177.5 million and gains of $198.7 million for the non-GAAP combined 2005 and 2006, respectively, compared to 2007, in which the impacts of derivative financial instruments
resulted in a net gain of $26.8 million, which includes $81.6 million as an unrealized loss.

Oil and natural gas sales, production and prices

Total oil and natural gas sales, excluding the impact of derivative financial instruments, for 2007 were $846.1 million compared with $355.8 million
for 2006 and $202.9 million for the 2005 non-GAAP combined period. For 2007, natural gas represented 86.2% of our revenues and 91.9% of equivalent production. Both 2006 and 2005
also have natural gas percentages in excess of 80.0% of total revenues and total production. Our equivalent production volumes for 2007 were 121.3 Bcfe compared with 49.6 Bcfe for 2006, an increase of
144.6%, primarily due to our acquisitions. Equivalent production from our 2007 acquisitions represented over 40.8% of 2007 total volumes. Our equivalent production volumes for 2006 were 49.6 Bcfe, or
111.1% greater than the 2005 non-GAAP combined period. The average price per Mcfe, before the impact of derivative financial instruments, was $6.98, $7.17 and $8.62 for 2007, 2006 and the
2005 non-GAAP combined period, respectively.

For
2007, our average price received for natural gas, excluding the impact of derivative financial instruments, was $6.54 per Mcf compared with $6.77 per Mcf in 2006 and $8.58 in the
2005 non-GAAP combined period. The 2007 average price received for oil, also excluding the impacts of derivative financial instruments was $71.17 per Bbl, or 14.3% higher than the 2006
price of $62.27 per Bbl. The average price per Bbl for the 2005 non-GAAP combined period was $53.35. The price that we receive for the oil and natural gas we produce is largely a function
of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical
storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to
continue in the future. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows, quantities of estimated Proved Reserves and related liquidity.
Assuming our December 2007 production levels, a change of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues and cash flow of approximately $11.1 million and
a change of $1.00 per Bbl of oil sold would result in an increase or decrease in revenues and cash flow of approximately $1.6 million without considering the effects of derivative financial
instruments.

Changes
in oil and natural gas volumes from our acquisitions, development drilling and exploitation projects combined with significant price fluctuations significantly impacted our
operating revenues and
cash flows from operations. In 2007, our revenues (before the impact of derivative financial instruments) increased to $846.1 million from $355.8 million for 2006. The total increase of
$490.3 million was attributable to an increase of $492.3 million from increased volumes primarily due to 2006 and 2007 acquisitions. This increase was partially offset by a reduction in
our realized price per Mcfe, which lowered revenue by $2.0 million.

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The
2006 and 2007 acquisitions significantly increased our presence in the East Texas/North Louisiana and Mid-Continent regions. Following is a summary of production grouped
by our significant producing regions for the 2005 non-GAAP combined period and years ended December 31, 2006 and 2007.

|                           |                  | Years ended December 31,
|-------------------------- | ---------------- | ------------------------
|
|
|
|East Texas/North Louisiana |                  | 3,518                   
|Mid-Continent              |                  | 994                     
|Appalachia                 |                  | 12,892                  
|Permian                    |                  | 3,591                   
|Rockies                    |                  | 2,553                   
|                           |                  |                         
|                           | Total production |                         
|                           |                  |                         

In
January 2007, we completed the sale of our producing properties and undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. This transaction included
substantially all of our producing assets in the Rockies area. In May 2007, we sold a group of properties acquired in the Southern Gas Acquisition. While this sale, which provided proceeds of
approximately $235.5 million was substantial, it did not impact our results of operations as we did not hold the properties for a period of time sufficient to impact our operating results. In
July 2007, we completed the sale of substantially all of our interest in the Cement Field located in our Mid-Continent area. In October 2007, we completed the purchase of an additional 45%
ownership interest in approximately 28,000 acres of leasehold interests and 135 producing wells in our Canyon Sand field in West Texas located in our Permian area. We also completed several small
sales of producing properties and acreages throughout 2007. The acquisitions of the Vernon Assets and the Southern Gas Assets significantly increased our production in the East Texas/North Louisiana
and Mid-Continent areas during 2007.

Derivative financial instruments

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

The
following table presents our realized and unrealized gains and losses from derivative financial instruments. We expect that our revenues will continue to be significantly impacted in
future periods by

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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.

|                                            |                                                                   | Predecessor |   | Successor |   |   |         | Successor |   | Year to year change |  
|------------------------------------------- | ----------------------------------------------------------------- | ----------- | - | --------- | - | - | ------- | --------- | - | ------------------- | -
|
|Derivative financial instrument activities: |                                                                   |             |   |           |   |   |         |           |   |                     |  
|                                            | Cash settlements on derivative financial instruments              |             | $ | (62,842   | ) | $ | (22,210 | )         | $ | (85,052             | )
|                                            | Non-cash change in fair value of derivative financial instruments |             |   | (114,411  | ) |   | 21,954  |           |   | (92,457             | )
|                                            |                                                                   |             |   |           |   |   |         |           |   |                     |  
|                                            | Total derivative financial instrument activities                  |             | $ | (177,253  | ) | $ | (256    | )         | $ | (177,509            | )
|                                            |                                                                   |             |   |           |   |   |         |           |   |                     |  

---

The use of derivative financial instruments allow us to limit the impacts of volatile price fluctuations associated with oil and natural gas. The
following table presents our natural gas prices, before the impact of derivative financial instruments where average realized prices per Mcfe ranged from a high of $12.06 during the 90 day
period from October 3, 2005 to December 31, 2005 to a low of $6.98 during the year ended December 31, 2007 while the impact from realized settlements after the impact of our
derivative financial instruments reduced our price volatility from a high of $8.24 per Mcfe during the 90 day period from October 3, 2005 to December 31, 2005 to a range of $7.76
to $7.87 per Mcfe for the years ended December 31, 2006 and 2007, respectively.

|                                                                                   |  | Predecessor |       | Successor |   |       |   | Successor |       | Year to year change |  
|---------------------------------------------------------------------------------- |  | ----------- | ----- | --------- | - | ----- | - | --------- | ----- | ------------------- | -
|
|Realized pricing:                                                                  |  |             |       |           |   |       |   |           |       |                     |  
|Oil per Bbl, before impact of derivative financial instruments                     |  | $           | 52.07 |           | $ | 57.47 |   | $         | 53.35 |                     | $
|Natural gas per Mcf, before impact of derivative financial instruments             |  |             | 7.31  |           |   | 12.40 |   |           | 8.58  |                     |  
|Natural gas equivalent per Mcfe, before impact of derivative financial instruments |  |             | 7.49  |           |   | 12.06 |   |           | 8.62  |                     |  
|Effect of cash settlements on derivatives(b)                                       |  |             | (0.58 | )         |   | (3.82 | ) |           | (1.38 | )                   |  
|                                                                                   |  |             |       |           |   |       |   |           |       |                     |  
|Net price per Mcfe, net of derivative financial instruments                        |  | $           | 6.91  |           | $ | 8.24  |   | $         | 7.24  |                     | $
|                                                                                   |  |             |       |           |   |       |   |           |       |                     |  

---

Our cash settlements for 2007 increased revenue by $108.4 million, or $0.89 per Mcfe compared to $29.4 million, or $0.59 per Mcfe,
in 2006. The NYMEX oil and natural gas prices that we used to settle our derivative financial instruments varied significantly during 2006 and 2007.

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Our
non-cash mark-to-market changes in the value of derivative financial instruments for 2007 resulted in a loss of $81.6 million compared to a
gain of $169.2 million in the prior year. The significant fluctuation was, again, attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate
settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

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

Oil and natural gas operating costs

Operating costs, which include labor, materials and supplies necessary to produce our oil and natural gas, were $117.2 million, or $0.97 per Mcfe for 2007,
compared with $46.5 million, or $0.94 per Mcfe for 2006. The increase of $70.7 million is due primarily to $60.6 million of costs associated with the 2006 and 2007 acquisitions,
including TXOK, PGMT, Winchester, Vernon and Southern Gas. The per unit increase in cost reflects a general increase in the cost of goods and services for all of our producing areas and an increase in
workover activities, which is partially offset by lower per unit operating costs from the Vernon Acquisition due to high production volumes for the properties acquired in the Vernon Acquisition.

Operating
costs for 2005 non-GAAP combined period were $20.1 million, or $0.85 per Mcfe, compared with $46.5 million, or $0.94 per Mcfe in 2006. Operating costs
per unit increased from 2005 to 2006 due to a general increase in the cost of goods and services for all of our producing areas, including our 2006 acquisitions.

Production and ad valorem taxes

Production and ad valorem taxes were $53.3 million, $22.3 million and $11.0 million for 2007, 2006 and non-GAAP combined 2005,
respectively. Production and ad valorem taxes are set by state and local governments and vary as to the tax rate and the value to which the rate is applied. On a percentage of sales basis, our 2007
production and ad valorem taxes were 6.3% of oil and natural gas sales, excluding the impact of derivative financial instruments, compared with 6.3% in 2006 and 5.4% for non-GAAP combined
2005. The change in the consolidated rate in 2006 compared with non-GAAP combined 2005 is due to a higher percentage of revenues from our East Texas/North Louisiana and
Mid-Continent producing areas which have a higher combined production and ad valorem tax rates than our Appalachia producing areas.

Depreciation, depletion and amortization

The following table presents our depreciation, depletion and amortization expenses for the 275 day period from January 1, 2005 to October 2,
2005, the 90 day period from October 3, 2005 to December 31, 2005, non-GAAP combined 2005, the years ended December 31, 2006 and 2007. The Equity Buyout, which
resulted in a change of basis in our oil and natural gas assets, had a significant impact on the depletion rate, which increased to $2.28 per Mcfe for the 90 day successor period from
October 3, 2005 to December 31, 2005 from the predecessor period, where the depletion rate was $1.27 per Mcfe. The depreciation, depletion and amortization rate per Mcfe produced varies
significantly for each of the periods presented due to our acquisition of TXOK, PGMT and Winchester in 2006, which increased the depreciation, depletion and amortization rate to $2.74 per Mcfe in
2006. The Vernon Acquisition and the Southern Gas Acquisition, which included significant proved developed producing

64

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properties,
further increased the depreciation, depletion and amortization rate to $3.10 per Mcfe in 2007.

|                                                |                                                                     | Predecessor |   | Successor |  |   |        | Successor |   | Year to year change
|----------------------------------------------- | ------------------------------------------------------------------- | ----------- | - | --------- |  | - | ------ | --------- | - | -------------------
|
|Depreciation, depletion and amortization costs: |                                                                     |             |   |           |  |   |        |           |   |                    
|                                                | Depletion expense                                                   |             | $ | 22,541    |  | $ | 13,281 |           | $ | 35,822             
|                                                | Depreciation and amortization expense                               |             | $ | 2,146     |  | $ | 790    |           | $ | 2,936              
|                                                | Mmcfe produced                                                      |             |   | 17,740    |  |   | 5,808  |           |   | 23,548             
|                                                | Depletion calculated rate per Mmcfe                                 |             | $ | 1.27      |  | $ | 2.28   |           | $ | 1.52               
|                                                | Depreciation and amortization calculated rate per Mmcfe             |             | $ | 0.12      |  | $ | 0.14   |           | $ | 0.13               
|                                                | Consolidated depreciation, depletion and amortization rate per Mcfe |             | $ | 1.39      |  | $ | 2.42   |           | $ | 1.65               

---

Accretion of discount on asset retirement obligations increased to $4.9 million in 2007 from $2.0 million in 2006 and
$0.8 million in non-GAAP combined 2005. The increase in 2007 from 2006 and in 2006 from non-GAAP combined 2005 is due to the combination of significant well additions
and related plugging liabilities in connection with our 2006 and 2007 acquisitions and increased estimates for the costs to plug and abandon properties. The increased estimates for plugging and
abandoning properties reflect increased costs for labor, rig rates and materials used in those operations.

General and administrative expenses

The following table presents our general and administrative expenses for the 275 day period from January 1, 2005 to October 2, 2005, the
90 day period from October 3, 2005 to December 31, 2005, the twelve months non-GAAP combined 2005, the years ended December 31, 2006 and 2007 and changes for
each of the years then ended. The table also reflects significant non-recurring expenses incurred in connection with the October 3, 2005 Equity Buyout.

|                                  |                                                 | Predecessor |   | Successor |   |   |       | Successor |   | Year to year change |  
|--------------------------------- | ----------------------------------------------- | ----------- | - | --------- | - | - | ----- | --------- | - | ------------------- | -
|
|General and administrative costs: |                                                 |             |   |           |   |   |       |           |   |                     |  
|                                  | Gross general and administrative expense        |             | $ | 18,220    |   | $ | 7,329 |           | $ | 25,549              |  
|                                  | Operator overhead reimbursements                |             |   | (1,291    | ) |   | (532  | )         |   | (1,823              | )
|                                  | Nonrecurring bonus expense from equity buyout   |             |   | 29,624    |   |   |      |           |   | 29,624              |  
|                                  | Equity buyout non cashstock based compensation |             |   | 44,092    |   |   |      |           |   | 44,092              |  
|                                  | Capitalized acquisition, development            |             |   |           |   |   |       |           |   |                     |  
|                                  | and exploitation charges                        |             |   | (1,203    | ) |   | (422  | )         |   | (1,625              | )
|                                  |                                                 |             |   |           |   |   |       |           |   |                     |  
|                                  | Net general and administrative expense          |             | $ | 89,442    |   | $ | 6,375 |           | $ | 95,817              |  
|                                  |                                                 |             |   |           |   |   |       |           |   |                     |  
|                                  | General and administrative expense              |             |   |           |   |   |       |           |   |                     |  
|                                  | per Mcfe                                        |             | $ | 5.04      |   | $ | 1.10  |           | $ | 4.07                |  

---

65

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Net general and administrative expenses for the year ended December 31, 2007 were $64.7 million compared with $41.2 million in 2006, an increase of
$23.5 million. Each of the respective years contains significant and notable variances. In 2007, we experienced significant increases in personnel and support facilities related to our 2006 and
2007 acquisitions and our continued efforts to becoming compliant with Sarbanes-Oxley regulations. These increased personnel expenses totaled approximately $18.2 million of increased cash
expenses for 2007 and increases of approximately $2.5 million from share-based compensation for 2007. We also incurred approximately $16.5 million for 2007 of legal and project-oriented
costs including (i) audit and legal fees in connection with our 2006 and 2007 acquisitions, (ii) costs for implementation and compliance with Section 404 of the Sarbanes-Oxley Act
of 2002 and (iii) expenses incurred for conversion of our information technology systems to a common platform.

When
comparing 2006 general and administrative costs to non-GAAP combined 2005, general and administrative expenses for non-GAAP combined 2005 include
$73.7 million one-time charges related to the Equity Buyout. The decrease in general and administrative expenses from non-GAAP combined 2005 to the year ended
December 31, 2006 is partially offset by 2006 acquisition related expenses and Sarbanes-Oxley compliance efforts.

Partially
offsetting the increases in general and administrative expenses were operator overhead recoveries of $1.8 million, $7.8 million and $18.4 million for the
twelve months non-GAAP combined 2005 and the years ended 2006 and 2007, respectively. Additional offsets to general and administrative expenses were capitalized costs of
$1.6 million, $3.3 million and $5.7 million for the non-GAAP combined 2005 and the years ended December 31, 2006 and 2007, respectively.

Stock based and other compensation expense

We adopted the provisions of SFAS No. 123(R) on October 3, 2005 upon closing of the Equity Buyout. Upon closing of the initial public offering,
Holdings merged with us and we assumed the EXCO Holdings 2005 Long-Term Incentive Plan, or the 2005 Long-Term Incentive Plan.

During
2007, we issued options to purchase approximately 5.0 million shares of common stock under our 2005 Long-Term Incentive Plan to our employees, which resulted in
non-cash compensation expenses of $12.6 million to general and administrative and lease operating expense and $2.4 million of capital charges to our full cost pool.

During
2006, we issued options to purchase approximately 3.6 million shares of common stock to our employees, which resulted in non-cash compensation expenses of
$6.5 million to general and administrative expenses and $1.4 million of capital charges to our full cost pool.

Immediately
prior to the closing of the Equity Buyout on October 3, 2005, we recorded stock based and other compensation expense for the following items, which are included as
part of general and administrative expenses in the 275 day period ended October 2, 2005:



66

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During
the 90 day period from October 3, 2005 to December 31, 2005, we recorded a non-cash charge of $2.2 million, of which $1.0 million
was capitalized as part of our proved oil and natural gas properties as a result of the granting of options to purchase 4,992,650 shares of common stock under the 2005 Long-Term Incentive
Plan. The offset to this expense was to shareholders' equity as additional paid-in capital.

Interest expense

Our interest expense for the twelve months ended December 31, 2007 was $181.4 million compared to $84.9 million for the same period in 2006.
The increase in interest expense is due to an increase in long-term debt balances in 2006 from $461.8 million at December 31, 2005 to $2.1 billion at
December 31, 2006 while our total debt balance remained constant at $2.1 billion throughout 2007. During the last quarter of 2006, our debt increased by more than $1.2 billion. In
2007, this amount was outstanding the full twelve months. Additionally, in 2007 we had expenses related to amendments of our credit agreements along with retirement of debt. The following table
presents our interest expense, including charges of $32.1 million attributable to (a) redemption premium of $13.0 million from the retirement of the EPOP Senior Term Credit
Agreement, (b) write-off of $12.2 million for unamortized deferred financing costs and unamortized original issue discount on the EPOP Senior Term Credit

67

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Agreement
and (c) expensed fees of $6.9 million associated with commitment letters from members of our banking group which were not utilized as a result of the Private Placement on
March 30, 2007.

|                                                                          |                        | Predecessor |        | Successor |   |       |        |   |        |        |   |        |        |   |       
|------------------------------------------------------------------------- | ---------------------- | ----------- | ------ | --------- | - | ----- | ------ | - | ------ | ------ | - | ------ | ------ | - | ------
|
|
|
|Interest expense:                                                         |                        |             |        |           |   |       |        |   |        |        |   |        |        |   |       
|71/4% senior notes due 2011                                               |                        | $           | 24,615 |           | $ | 7,269 |        | $ | 31,884 |        | $ | 29,275 |        | $ | 28,922
|JP Morgan bridge loan                                                     |                        |             |       |           |   | 8,750 |        |   | 8,750  |        |   | 1,216  |        |   |      
|EXCO credit agreements                                                    |                        |             | 193    |           |   | 90    |        |   | 283    |        |   | 15,951 |        |   | 29,415
|Amortization and write-off of deferred financing costs on EXCO facilities |                        |             | 1,618  |           |   | 3,301 |        |   | 4,919  |        |   | 6,789  |        |   | 4,138 
|EPOP revolving credit facility                                            |                        |             |       |           |   |      |        |   |       |        |   | 11,937 |        |   | 68,462
|EPOP term loan                                                            |                        |             |       |           |   |      |        |   |       |        |   | 18,827 |        |   | 18,140
|Amortization and write-off of deferred financing costs on EPOP loans      |                        |             |       |           |   |      |        |   |       |        |   | 858    |        |   | 32,100
|$50 million senior term loan                                              |                        |             | 245    |           |   | 2     |        |   | 247    |        |   |       |        |   |      
|Other interest expense                                                    |                        |             | 4      |           |   | 2     |        |   | 6      |        |   | 18     |        |   | 173   
|                                                                          |                        |             |        |           |   |       |        |   |        |        |   |        |        |   |       
|                                                                          | Total interest expense |             | $      | 26,675    |   | $     | 19,414 |   | $      | 46,089 |   | $      | 84,871 |   | $     
|                                                                          |                        |             |        |           |   |       |        |   |        |        |   |        |        |   |       

---

Interest expense for the year ended December 31, 2006 was $84.9 million compared with $46.1 million for non-GAAP
combined 2005, an increase of $38.8 million, which is primarily attributable to the increase in our overall debt balances in 2006 related to the 2006 acquisitions of TXOK, PGMT and Winchester.

Income taxes

The following table presents a reconciliation of our income tax provision (benefit) for the 275 day period from January 1, 2005 to October 2,
2005, the 90 day period from October 3, 2005 to December 31, 2005, and the years ended December 31, 2006 and 2007.

|                                                                      |                                        | Predecessor |         |         |   |       |        |  
|--------------------------------------------------------------------- | -------------------------------------- | ----------- | ------- | ------- | - | ----- | ------ | -
|
|
|
|United States federal income taxes (benefit) at statutory rate of 35% |                                        | $           | (70,293 | )       | $ | 8,150 |        | $
|Increases (reductions) resulting from:                                |                                        |             |         |         |   |       |        |  
|                                                                      | Foreign tax items                      |             |         | 644     |   |       | (2,996 | )
|Change in U.S. tax law related to Canadian dividend                   |                                        |             | (2,075  | )       |   |      |        |  
|                                                                      | Adjustments to the valuation allowance |             |         |        |   |       |       |  
|                                                                      | Non-deductible compensation            |             |         | 15,432  |   |       | 604    |  
|                                                                      | State taxes net of federal benefit     |             |         | (6,665  | ) |       | 1,095  |  
|                                                                      | State tax rate change                  |             |         |        |   |       |       |  
|                                                                      | Other                                  |             |         | (741    | ) |       | 468    |  
|                                                                      |                                        |             |         |         |   |       |        |  
|                                                                      | Total income tax provision             |             | $       | (63,698 | ) | $     | 7,321  |  
|                                                                      |                                        |             |         |         |   |       |        |  

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On
February 9, 2005, we repatriated Cdn. $74.5 million ($59.6 million) in an extraordinary dividend from our Canadian subsidiary. We recognized a tax liability of
$8.2 million as of December 31, 2004 related to the extraordinary dividend. As a result of certain technical advice issued by the U.S. Treasury Department, we reduced the tax liability
by $2.1 million during the second quarter of 2005. EXCO Resources filed amended quarterly reports on Form 10-Q/A that included restated financial statements for the quarters
ended June 30, 2005 and September 30, 2005 to reflect the tax benefit in the earlier quarter and to classify the benefit as a component of continuing rather than discontinued operations
in the September 30, 2005 quarter. This additional tax benefit is recognized as a component of taxes from continuing operations pursuant to SFAS No. 109 and
EITF 93-13, which require that a tax effect of a change in enacted rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a
component of discontinued operations.

In
June 2005, the state of Ohio enacted new legislation that changed the method of taxing businesses that operate in Ohio. We have significant operations in the state of Ohio through our
North Coast subsidiary. As a result of the new tax legislation in Ohio, we recognized a reduction to our deferred tax liability of $5.2 million as of December 31, 2005, which reflects
the change in Ohio tax rates and the impacts of our stepped-up basis resulting from the Equity Buyout.

On
May 18, 2006, the Texas governor signed into law a Texas Margin tax that replaces the current franchise tax effective January 1, 2007. We had recorded the effect of the
change in the tax rate on our existing deferred balances in the second quarter of 2006. Our deferred income tax related to the Texas Margin tax is $0.5 million and $0.9 million at
December 31, 2007 and 2006, respectively.

During
2007, our income tax rate was impacted by the substitution of a current federal net operating loss carryback for previously claimed foreign tax credits resulting from the 2005
sale of our Canadian subsidiary. The impact, net of a federal refund of $6.1 million, was an $11.0 million non-cash expense, principally related to foreign tax credits which
are required since we no longer have any foreign operations.

Also,
as a result of our 2007 acquisitions, our state effective rate increased which required us to change the rate in which we record our deferred tax assets and liabilities. This
amount was recognized in our 2007 income tax expense as a current period expense and is presented as part of the Other line item.

On
February 10, 2005, we sold our Canadian subsidiary and certain intercompany notes associated with Canada. The aggregate purchase price after contractual adjustments was Cdn.
$551.3 million ($443.3 million) less the payment of the outstanding Canadian credit facility of Cdn. $90.1 million ($72.1 million). We have recognized a gain from the sale
of our Canadian subsidiary of $175.7 million before income tax expense of $50.1 million related to the gain. The income tax is composed of:

(unaudited, in thousands)

275 day period ended October 2, 2005U.S. income tax before foreign tax credits

$
50,128Canadian income tax on the gain


33,717U.S. foreign tax credit


(33,788
)Total income tax on gain

$
50,057


Income
taxes from discontinued operations for the 275 day period ended October 2, 2005 reflects the income tax on the gain of $50.1 million as discussed above, an
income tax benefit of $1.3 million from our Canadian subsidiary's operations during the period January 1, 2005 to February 10, 2005, and approximately $0.5 million of
Canadian income taxes withheld on interest paid by our Canadian subsidiary in 2005 on the intercompany notes.

69

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The
loss from discontinued operations of $4.4 million before the gain on the sale of our Canadian subsidiary and income taxes from discontinued operations for the 275 day
period ended October 2, 2005 includes:



EXCO
files income tax returns in the U.S. federal jurisdictions and various state jurisdictions. With few exceptions, EXCO is no longer subject to U.S. federal and state and local
examinations by tax authorities for years before 2004. The Internal Revenue Service, or IRS, completed its examination of EXCO's 2004 U.S. federal income tax return in January 2008. The result of the
audit was an adjustment between U.S. and our Canadian subsidiary for a hedge recorded to the wrong entity. There was no material change to EXCO's financial position.

The
Company adopted the provisions of FASB Interpretation No. 48, "Accounting for Uncertainties in Income Taxes" on January 1, 2007. As a result of the implementation of
Interpretation No. 48, the Company recognized a zero liability for unrecognized tax benefits. As of December 31, 2006 and December 31, 2007, the Company's policy is to recognize
interest related to unrecognized tax benefits of interest expense and penalties in operating expenses. The Company has not accrued any interest or penalties relating to unrecognized tax benefits in
the current financials.

Liquidity, capital resources and capital commitments

General

Most of our growth has resulted from acquisitions and our development and exploitation programs. Consistent with our strategy of acquiring and developing
reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to
fund our operations. Our general financial strategy is to use a combination of cash flow from operations, bank financing, cash received from the sale of oil and natural gas properties and the sale or
issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. We do not have a set budget for acquisitions as these tend to
be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our
ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders. In addition, our Indenture governing our senior notes contains restrictions on
incurring indebtedness and pledging our assets. Some of the significant transactions affecting our liquidity to support our growth strategy are discussed below.

In
February 2005, we sold our Canadian subsidiary for $443.3 million after contractual adjustments.

On
February 14, 2006, we completed an underwritten IPO of 53,615,200 shares of our common stock, including an exercise by the underwriters of their over-allotment
option, for aggregate net proceeds to EXCO Resources of $662.2 million. The net proceeds from the IPO, together with cash on hand and additional borrowings under EXCO's credit agreement, were
used as follows:



70

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On
March 30, 2007, we issued 200,000 shares of preferred stock for $2.0 billion in cash in connection with the Vernon Acquisition. In conjunction with the Vernon
Acquisition, the Southern Gas Acquisition and the Gulf Coast Sale, we amended our credit agreements which increased our aggregate borrowing base to $2.2 billion. Additional liquidity totaling
approximately $495.9 million, net of contractual purchase price adjustments, has been generated from the sale of oil and natural gas properties during 2007.

Net
cash provided by operating activities was $577.8 million for the twelve months ended December 31, 2007. At December 31, 2007, our cash and cash equivalents
balance was $55.5 million, an increase of $32.7 million from December 31, 2006.

Acquisitions and capital expenditures

The following table presents our capital expenditures and entity acquisitions for the 275 day period from January 1, 2005 to October 2, 2005,
the 90 day period from October 3, 2005 to December 31, 2005, the non-GAAP combined 2005 and the years ended December 31, 2006 and 2007.

|                                                                                                                                          |                    | Predecessor |         | Successor |   |        |        |   |         |        
|----------------------------------------------------------------------------------------------------------------------------------------- | ------------------ | ----------- | ------- | --------- | - | ------ | ------ | - | ------- | -------
|
|
|Property acquisitions                                                                                                                     |                    | $           | 103,222 |           | $ |       |        | $ | 103,222 |        
|Acquisition of TXOK Acquisition, Inc. preferred stock, net of cash acquired                                                               |                    |             |        |           |   |       |        |   |        |        
|Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired, excluded debt and derivative financial instruments assumed |                    |             |        |           |   |       |        |   |        |        
|Acquisition of Winchester Energy, Ltd., net of cash acquired                                                                              |                    |             |        |           |   |       |        |   |        |        
|Vernon Acquisition                                                                                                                        |                    |             |        |           |   |       |        |   |        |        
|Southern Gas Acquisition                                                                                                                  |                    |             |        |           |   |       |        |   |        |        
|Lease purchases                                                                                                                           |                    |             |        |           |   |       |        |   |        |        
|Development capital expenditures                                                                                                          |                    |             | 39,900  |           |   | 13,194 |        |   | 53,094  |        
|Corporate and other                                                                                                                       |                    |             | 5,944   |           |   | 1,712  |        |   | 7,656   |        
|                                                                                                                                          |                    |             |         |           |   |        |        |   |         |        
|                                                                                                                                          | Total expenditures |             | $       | 149,066   |   | $      | 14,906 |   | $       | 163,972
|                                                                                                                                          |                    |             |         |           |   |        |        |   |         |        

During 2006, we completed the following acquisitions of oil and natural gas properties and undeveloped acreage, including the acquisition of
Winchester. A summary of these acquisitions and

71

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their
related values to oil and natural gas properties and gathering facilities, net of contractual adjustments is presented on the following table.

|(in thousands)          |                                             | Effective dates         |                | Values allocated
|----------------------- | ------------------------------------------- | ----------------------- | -------------- | ----------------
|Asset acquisitions:     |                                             |                         |                |                 
|                        | West Texas properties from private producer |                         | April 2006     |                 
|                        | East Texas properties from private producer |                         | May 2006       |                 
|                        | Wyoming properties from private producer    |                         | August 2006    |                 
|                        | Appalachia properties from private producer |                         | September 2006 |                 
|                        | Mid-Continent region and other              |                         | Various        |                 
|Corporate acquisitions: |                                             |                         |                |                 
|                        | TXOK Acquisition, Inc.                      |                         | February 2006  |                 
|                        | Power Gas Marketing & Transmission, Inc.    |                         | April 2006     |                 
|                        | Winchester Energy Company, Ltd              |                         | October 2006   |                 
|                        |                                             | Total 2006 acquisitions |                |                 

Details
of the components of the purchase price and related allocation of the purchase price to the acquired assets and liabilities of our corporate acquisitions in 2006 are as follows:

|(in thousands)                                                         |                                                 | TXOK Acquisition, Inc. |         | Power Gas Marketing & Transmission, Inc. |   | Winchester Energy Company, Ltd. |        
|---------------------------------------------------------------------- | ----------------------------------------------- | ---------------------- | ------- | ---------------------------------------- | - | ------------------------------- | -------
|Purchase price calculations:                                           |                                                 |                        |         |                                          |   |                                 |        
|Carrying value of initial investment in TXOK Acquisition, Inc.         |                                                 | $                      | 21,531  |                                          | $ |                                |        
|Acquisition of preferred stock, including accrued and unpaid dividends |                                                 |                        | 158,750 |                                          |   |                                |        
|Value of preferred stock redemption premium                            |                                                 |                        | 4,667   |                                          |   |                                |        
|Cash payments for acquired equity                                      |                                                 |                        |        |                                          |   | 63,615                          |        
|Assumption of debt:                                                    |                                                 |                        |         |                                          |   |                                 |        
|                                                                       | Term loan, plus accrued interest                |                        |         | 202,755                                  |   |                                 |       
|                                                                       | Revolving credit facility plus accrued interest |                        |         | 309,701                                  |   |                                 | 13,096 
|Assumption of derivative financial instruments                         |                                                 |                        |        |                                          |   | 38,098                          |        
|Less cash acquired                                                     |                                                 |                        | (32,261 | )                                        |   | (1,839                          | )      
|                                                                       |                                                 |                        |         |                                          |   |                                 |        
|                                                                       | Net purchase price                              |                        | $       | 665,143                                  |   | $                               | 112,970
|                                                                       |                                                 |                        |         |                                          |   |                                 |        
|Allocation of purchase price:                                          |                                                 |                        |         |                                          |   |                                 |        
|Oil and natural gas propertiesproved                                  |                                                 | $                      | 489,076 |                                          | $ | 122,972                         |        
|Oil and natural gas propertiesunproved                                |                                                 |                        | 60,840  |                                          |   | 421                             |        
|Gathering and other fixed assets                                       |                                                 |                        | 20,079  |                                          |   | 2,573                           |        
|Goodwill                                                               |                                                 |                        | 64,887  |                                          |   | 21,249                          |        
|Current and non-current assets                                         |                                                 |                        | 37,460  |                                          |   | 2,024                           |        
|Deferred income taxes                                                  |                                                 |                        | 26,783  |                                          |   | (31,424                         | )      
|Accounts payable and other accrued expenses                            |                                                 |                        | (30,377 | )                                        |   | (3,318                          | )      
|Asset retirement obligations                                           |                                                 |                        | (8,203  | )                                        |   | (1,527                          | )      
|Fair value of oil and natural gas derivatives                          |                                                 |                        | 4,598   |                                          |   |                                |        
|                                                                       |                                                 |                        |         |                                          |   |                                 |        
|                                                                       | Total purchase price allocation                 |                        | $       | 665,143                                  |   | $                               | 112,970
|                                                                       |                                                 |                        |         |                                          |   |                                 |        

On
February 14, 2006, at closing of our IPO, we acquired the 89% of TXOK that we did not already own by redeeming their outstanding preferred stock and assuming TXOK's outstanding
debt of $512.5 million. The purchase price, net of cash acquired was $665.1 million.

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In April and May 2006, we acquired producing properties and undeveloped acreage in West Texas and the Cotton Valley trend in East Texas. The purchase price of these assets was
$135.8 million, after contractual adjustments, which was funded with indebtedness drawn under the EXCO Resources Credit Agreement.

On
April 28, 2006, we closed an acquisition and acquired 100% of the common stock of PGMT for a net purchase price of $113.0 million. The purchase price included the
assumption of $13.1 million of debt and $38.1 million outstanding derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under the
EXCO Resources Credit Agreement, we paid the assumed debt and terminated the assumed commodity hedges.

On
October 2, 2006, we closed our acquisition of Winchester and its affiliated entities from Progress Energy, Inc. for approximately $1.1 billion in cash, net of
purchase price adjustments. The assets included producing and undeveloped acreage located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. The assets also
include six gathering systems with 300 miles of pipe and a 53-mile pipeline system. The acquisition was financed with a $650.0 million loan under the EPOP Senior Term Credit
Agreement and $651.0 million of borrowings under the EPOP Revolving Credit Facility. We formed a new subsidiary to purchase Winchester and that subsidiary became an unrestricted subsidiary as
defined under the Indenture governing our senior notes and the EXCO Resources Credit Agreement. Concurrent with the closing of the purchase of Winchester, we contributed to EPOP all of our East Texas
properties, with an estimated value of approximately $425.0 million, and related indebtedness of approximately $150.0 million. EPOP is not a guarantor of the EXCO Resources Credit
Agreement nor does EXCO Resources guarantee the debt of EPOP.

During
2007, we completed the following acquisitions of oil and natural gas properties and undeveloped acreage, including the Vernon Acquisition and the Southern Gas Acquisition. A
summary of these acquisitions and their related values to oil and natural gas properties and gathering facilities, net of contractual adjustments is presented on the following table.

|(in thousands)                                                     |                                 | Vernon Acquisition |           | Southern Gas Acquisition |   | Other acquisitions |         | Consolidated total |        
|------------------------------------------------------------------ | ------------------------------- | ------------------ | --------- | ------------------------ | - | ------------------ | ------- | ------------------ | -------
|Purchase price calculations:                                       |                                 |                    |           |                          |   |                    |         |                    |        
|Purchase price                                                     |                                 | $                  | 1,520,183 |                          | $ | 759,100            |         | $                  | 180,160
|Acquisition related expenses                                       |                                 |                    | 1,755     |                          |   | 2,040              |         |                    |       
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        
|Total purchase price                                               |                                 | $                  | 1,521,938 |                          | $ | 761,140            |         | $                  | 180,160
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        
|Allocation of purchase price:                                      |                                 |                    |           |                          |   |                    |         |                    |        
|Proved oil and natural gas properties                              |                                 | $                  | 1,417,823 |                          | $ | 577,852            |         | $                  | 159,502
|Unproved oil and natural gas properties                            |                                 |                    | 58,192    |                          |   | 4,743              |         |                    | 20,658 
|Gulf coast sale                                                    |                                 |                    |          |                          |   | 235,477            |         |                    |       
|Gas gathering and related facilities                               |                                 |                    | 119,409   |                          |   |                   |         |                    |       
|Fair value (liability) of assumed derivative financial instruments |                                 |                    | (60,015   | )                        |   | (42,204            | )       |                    |       
|Asset retirement obligations                                       |                                 |                    | (10,726   | )                        |   | (12,567            | )       |                    |       
|Other liabilities, net                                             |                                 |                    | (2,745    | )                        |   | (2,161             | )       |                    |       
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        
|                                                                   | Total purchase price allocation |                    | $         | 1,521,938                |   | $                  | 761,140 |                    | $      
|                                                                   |                                 |                    |           |                          |   |                    |         |                    |        

On
March 30, 2007, EPOP completed the purchase of substantially all of the oil and natural gas properties and assets related to the Vernon and Ansley fields located in Jackson
Parish, Louisiana from Anadarko for approximately $1.5 billion in cash, net of purchase price adjustments. Pursuant to the purchase and sale agreement, the purchase price and resulting
allocation was finalized during the third quarter of 2007. The Vernon Acquisition was funded by a $1.75 billion capital contribution from EXCO

73

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to
EPOP. The capital contribution consisted of $1.67 billion in cash and an $80.0 million deposit made by EXCO in December 2006.

On
May 2, 2007, we completed the purchase of oil and natural gas properties and related assets, including derivative financial instruments, covering a significant portion of
estimated production for 2007, 2008 and 2009 from entities affiliated with Anadarko in multiple fields primarily located in Oklahoma, Texas and Louisiana for approximately $761.1 million in
cash, including acquisition related expenses, net of purchase price adjustments, or the Southern Gas Acquisition. The acquisition was funded with cash on hand of $145.2 million, including
$133.0 million from escrow accounts from prior sales, borrowings under the EXCO Resources Credit Agreement of $572.9 million and the application of a $43.0 million deposit paid by
EXCO to Anadarko in February 2007.

On
May 2, 2007, in connection with the Southern Gas Acquisition, EXCO entered into the Second Amended and Restated Credit Agreement, or the EXCO Resources Credit Agreement, among
EXCO, as borrower, certain subsidiaries of EXCO, as guarantors, and a group of lenders. As a result of the Southern Gas Acquisition, EXCO and the lenders agreed to increase the borrowing base from
$750.0 million to $1.0 billion.

On
October 9, 2007, we completed the acquisition of an additional 45.0% interest in 28,000 acres of leasehold interests and 135 producing wells in our Canyon Sand field in West
Texas for $155.0 million, subject to customary post-closing purchase price adjustments.

On
February 20, 2008, EXCO acquired shallow natural gas properties from EOG Resources, Inc. located primarily in EXCO's central Pennsylvania operating area. The properties
include approximately 2,500 producing wells, 2,000 shallow undrilled locations and 16 Mmcfe/d of net production. The purchase price was $395.0 million. After reduction for preliminary closing
adjustments of $7.4 million, the net purchase price paid on February 20, 2008 was $387.6 million and was financed with the EXCO Resources Credit Agreement.

2007 divestitures

During 2007, we sold various oil and natural gas properties to multiple purchasers for proceeds totaling approximately $490.3 million.

On
January 5, 2007, we completed the sale of oil and natural gas properties and undeveloped drilling locations in the Wattenberg field area of the DJ Basin, or the Wattenberg
Field, for approximately $130.9 million in cash, net of contractual adjustments. The transaction included substantially all of the assets EXCO held in the area. Proceeds from the sale were
deposited with a third party and used for the Southern Gas Acquisition to facilitate a like-kind exchange for federal income tax purposes.

On
May 8, 2007, we completed the sale of a portion of the oil and natural gas properties and related assets in multiple fields primarily located in South Texas and South Louisiana
acquired in the Southern Gas Acquisition to an entity affiliated with Crimson Exploration Inc., or Crimson, for an aggregate sale price of $235.5 million in cash, net of preliminary
purchase price adjustments, and 750,000 shares of unregistered restricted Crimson common stock, or the Gulf Coast Sale. In connection with the closing of the Gulf Coast Sale, the borrowing base on the
EXCO Resources Credit Agreement was reduced from $1.0 billion to $900.0 million.

On
July 13, 2007, we completed the sale of substantially all of our interest in the Cement Field, located in Caddo and Grady Counties, Oklahoma in our Mid-Continent
area for approximately $99.7 million, after contractual purchase price adjustments. Proceeds from this sale were deposited with a third party intermediary and used to purchase assets in West
Texas in October 2007.

74

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In
November 2007, we sold certain assets across our portfolio for approximately $20.4 million, subject to post-closing adjustments. Through this divestiture, we exited
Nebraska, Colorado, and certain non-operated properties in Texas and the Gulf Coast area of Louisiana.

No
gain or loss was recognized from these sales as we use the full cost method of accounting.

Capital budget

We have budgeted $625.2 million for capital expenditures in 2008. We anticipate increasing this amount in light of our recently completed acquisition of
properties from EOG Resources, Inc. and for increased activities related to our Marcellus Shale play in Appalachia.

We
expect to utilize our current cash balance, cash flow from operations and available funds under our credit agreements to fund our acquisitions, capital expenditures and working
capital. We also plan to continue pursuing sales of non-strategic assets to assist with meeting our business objectives.

We
believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreements are adequate to meet the cash
requirements of our business. However, future cash flows are subject to a number of variables including production volumes, fluctuations in oil and natural gas prices and our ability to service the
debt incurred in connection with our acquisitions. If cash flows decline we may be required to reduce our capital expenditure budget which in turn may affect our production in future periods. Our
operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. We experienced increased costs for tubular goods and
for certain services during 2006 and 2007 and some oil and natural gas producing companies encountered difficulties in contracting for drilling rigs and other services due to high demand. Currently,
we do not believe that these conditions have had a significant impact upon our capital expenditures programs or our results of operations. However, if such conditions arise that do affect us, projects
may be delayed due to lack of services or materials or we may have to delay projects to stay within our capital budget or available liquidity.

71/4% senior notes due January 15, 2011

At December 31, 2007, $444.7 million in principal was outstanding on our 71/4% senior notes due January 15, 2011, or senior
notes. Unamortized premium on the senior notes was $11.0 million. The
estimated fair value of the senior notes, based on quoted market prices for the senior notes, was $426.9 million on December 31, 2007.

Interest
is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011.
Prior to January 15, 2007, we may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the senior notes plus a premium.
We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the senior notes.

The
Indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:



75

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Credit agreements

EXCO Resources Credit Agreement

Effective February 20, 2008, the EXCO Resources Credit Agreement was amended and restated and the borrowing base was increased from $900.0 million
to $1.2 billion. All other terms remain unchanged. The borrowing base is redetermined semi-annually with EXCO and the lenders having the right to interim unscheduled
redeterminations in certain circumstances. Scheduled redeterminations are on March 1 and September 1 of each year beginning on September 1, 2007. The facility matures on
March 30, 2012. The interest rate ranges from London Inter Bank Offered Rate, or LIBOR, plus 100 bps to LIBOR plus 175 bps depending upon borrowing base usage. The facility also includes an
Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 0 bps to ABR plus 75 bps depending upon borrowing base usage. Borrowings under the EXCO Resources Credit Agreement are
collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO has also agreed to have in place commodity derivative contracts covering no more than
80% of its "forecasted production from total Proved Reserves" (as defined) for the next two years and 70% in the third, fourth and fifth years. EXCO will have in place mortgages covering 80% of the
Engineered Value of its Borrowing Base Properties (as defined). The foregoing description is not complete and is qualified in its entirety by the EXCO Resources Credit Agreement. As of
December 31, 2007, EXCO
was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:



At
December 31, 2007, the six month LIBOR rate was 4.6%, which would result in an interest rate of approximately 5.8%, on any new indebtedness we may incur under the EXCO
Resources Credit Agreement. At December 31, 2007, we had a borrowing base of $900.0 million of which $560.5 million was outstanding under the EXCO Resources Credit Agreement. At
February 20, 2008, we had $920.5 million outstanding under the EXCO Resources Credit Agreement.

EPOP Credit Agreement

The EPOP Credit Agreement has a borrowing base of $1.3 billion. The borrowing base is scheduled to be redetermined on a semi-annual basis, with
EPOP and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each
year, beginning October 1, 2007. The EPOP Credit

76

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Agreement
is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP's subsidiaries, and is guaranteed by all existing and future subsidiaries of EPOP. Effective
February 20, 2008, the EPOP Credit Agreement was amended to provide a valuation mechanism with respect to our midstream, pipeline and gathering assets in East Texas/North Louisiana for purposes
of setting the borrowing base. EPOP has agreed to have in place derivative financial instruments covering no more than 80.0% of the "forecasted production from total Proved Reserves" (as defined) for
the next two years and 70.0% of the forecasted production from total Proved Reserves in the third, fourth and fifth years. The foregoing description is not complete and is qualified in its entirety by
the EPOP Credit Agreement. As of December 31, 2007, EPOP was in compliance with the financial covenants contained the EPOP Credit Agreement, which require that EPOP:



The
EPOP Credit Agreement contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Credit Agreement matures
March 30, 2012. Interest under the EPOP Credit Agreement ranges from LIBOR plus 100 basis points (bps) to 175 bps or ABR, as defined, ranging from ABR plus 0 bps to ABR plus 75 bps.

At
December 31, 2007, the six month LIBOR rate was 4.6%, which would result in an interest rate of approximately 6.1% on any new indebtedness we may incur under the EPOP Credit
Agreement. At December 31, 2007, we had a borrowing base of $1.3 billion, of which $1.1 billion was outstanding under the EPOP Credit Agreement. At February 20, 2008,
$1.1 billion outstanding under the EPOP Credit Agreement.

Preferred stock

The 7.0% Preferred Stock and Hybrid Preferred Stock were issued in several series at a purchase price of $10,000 per share. As of December 31, 2007, the
liquidation preference of the 7.0% Preferred Stock and the Hybrid Preferred Stock was $0.4 billion and $1.6 billion, respectively.

We
paid dividends on the 7.0% Preferred Stock and Hybrid Preferred Stock totaling $127.1 million during 2007. We have accrued dividends of $5.8 million as of
December 31, 2007. EXCO held its annual meeting of shareholders on August 30, 2007. During this meeting, shareholders voted in favor of the transformation of the Hybrid Preferred Stock
into terms identical to the 7.0% Preferred Stock. As a result, the annual dividend requirement on the Hybrid Preferred Stock is reduced from $177.1 million to $112.7 million, a reduction
of $64.4 million per annum. Our annual dividends on the 7.0% Preferred Stock and Hybrid Preferred Stock now total $140.0 million.

Derivative financial instruments

We use derivative financial instruments to manage exposure to commodity prices and interest rate risks. Our objectives for holding derivatives are to minimize
risks using the most effective methods to eliminate or reduce the impacts of these exposures.

Our
production is generally sold at prevailing market prices. However, we periodically enter into derivative financial instrument 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.

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Our objective in entering into derivative financial instrument contracts is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition
activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. As of
December 31, 2007, including all contracts entered into through February 22, 2008, we had contracts in place for the volumes and prices shown in the table below, which includes contracts
we entered into or assumed in connection with acquisitions.

|(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 NYMEX:                  |  |                         |  |                                           |      |                        |       |                                        
|Q1 2008                       |  | 25,485                  |  | $                                         | 8.59 |                        | 355   |                                        
|Q2 2008                       |  | 26,685                  |  |                                           | 8.27 |                        | 355   |                                        
|Q3 2008                       |  | 26,910                  |  |                                           | 8.29 |                        | 358   |                                        
|Q4 2008                       |  | 26,910                  |  |                                           | 8.39 |                        | 358   |                                        
|2009                          |  | 95,055                  |  |                                           | 8.09 |                        | 1,215 |                                        
|2010                          |  | 37,098                  |  |                                           | 7.94 |                        | 473   |                                        
|2011                          |  | 1,825                   |  |                                           | 4.51 |                        |      |                                        
|2012                          |  | 1,830                   |  |                                           | 4.51 |                        |      |                                        
|2013                          |  | 1,825                   |  |                                           | 4.51 |                        |      |                                        

Off-balance sheet arrangements

None.

Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at December 31, 2007:

|                                      |  | Payments due by period
|------------------------------------- |  | ----------------------
|
|71/4% senior notes(1)                 |  | $                     
|EXCO Resources credit agreement(2)    |  |                       
|EPOP credit agreement(3)              |  |                       
|Operating leases(4)                   |  |                       
|Appalachia property acquisition(5)    |  |                       
|Drilling/work commitments             |  |                       
|                                      |  |                       
|Total contractual cash obligations(6) |  | $                     
|                                      |  |                       

---

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ITEM 7A.    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 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 use of derivative financial instruments activities as of December 31, 2007:

(in thousands, except prices)

Volume Mmbtus/Bbls

Weighted average strike price per Mmbtu/Bbl

Fair value at December 31, 2007Natural Gas:Swaps:2008

99,870

$
8.36

$
53,9932009

80,455


7.94


(43,826
)2010

29,798


7.79


(20,794
)2011

1,825


4.51


(5,923
)2012

1,830


4.51


(5,834
)2013

1,825


4.51

(5,618
)Total Natural Gas

215,603




(28,002
)Oil:Swaps:2008

1,425


68.22


(34,667
)2009

850


60.09


(22,295
)2010

108


59.85

(2,424
)Total Oil

2,383




(59,386
)Total Oil and Natural Gas






(87,388
)


At
December 31, 2007, the average forward spot oil prices per Bbl for calendar 2008 and for 2009 were $93.11 and $87.96, respectively, and the average forward spot natural gas
prices per Mmbtu for calendar 2008 and for 2009 were $7.81 and $8.52, respectively.

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Realized
gains or losses from the settlement of derivative financial instruments are recorded in our financial statements as increases or decreases in revenue. For example, using the oil
swaps in place at December 31, 2007, if the settlement price exceeds the actual weighted average strike price of $68.22, then a reduction in revenue will be recorded for the difference between
the settlement price and $69.22 multiplied by the hedged volume of 1,425 Bbls. Conversely, if the settlement price is less than $68.22, then an increase in revenue will be recorded for the difference
between the settlement price and $67.22 multiplied by the hedged volume of 1,425 Bbls. For example, for a hedged volume of 1,425 Bbls, if the settlement price is $69.22, then revenue will be decreased
by $1.4 million. Conversely, if the settlement price is $67.22 revenue will be increased by $1.4 million.

Interest rate risk

At December 31, 2007, our exposure to interest rate changes related primarily to borrowings under our credit agreements and interest earned on our
short-term investments. The interest rate is fixed at 71/4% on the $444.7 million in senior notes we have outstanding. As of December 31, 2007, we were not
using any derivatives to manage interest rate risk. Interest is payable on borrowings under our credit agreements based on a floating rate as more fully described in "Management's discussion and
analysis of financial condition and results of operationsOur liquidity, capital resources and capital commitments." At December 31, 2007, we had $560.5 million in
outstanding borrowings under the EXCO Resources Credit Agreement. As of February 20, 2008, the outstanding balance under the EXCO Resources Credit Agreement was $920.5 million as of that
date, the weighted average interest rate under the EXCO Resources Credit Agreement was 4.40%. A 1% change in interest rates based on the borrowings as of February 20, 2008 would result in an
increase or decrease in our interest costs of $9.2 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

The
EPOP Credit Agreement bears interest based on a floating rate. As of December 31, 2007, the outstanding balance under the EPOP Credit Agreement was $1.1 billion. As of
February 20, 2008, our outstanding balance under the EPOP Credit Agreement was $1.1 billion. As of that date, the weighted average interest rate under the EPOP Credit Agreement was
4.67%. A 1% change in interest rates based on the borrowings as of February 20, 2008 under the EPOP Credit Agreement would result in an increase or decrease in interest costs of
$10.7 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

In
January 2008, we entered into financial risk management instruments to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through
February 14, 2010 at LIBOR rates ranging from 2.45% to 2.8%.

80

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

EXCO RESOURCES, INC.    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS    Contents



|Management's Report on Internal Control Over Financial Reporting                                                                                                                                                                        |  | 82
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --
|Reports of Independent Registered Public Accounting Firms                                                                                                                                                                               |  | 83
|Consolidated balance sheets at December 31, 2006 and 2007                                                                                                                                                                               |  | 87
|Consolidated statements of operations for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the years ended December 31, 2006 and
2007                       |  | 89
|Consolidated statements of cash flows for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the years ended December 31, 2006 and
2007                       |  | 90
|Consolidated statements of changes in shareholders' equity for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the years ended December 31,
 2006 and 2007 |  | 91
|Notes to consolidated financial statements                                                                                                                                                                                              |  | 92

Financial
information for the 275 day period from January 1, 2005 to October 2, 2005, represents predecessor (Predecessor) basis financial statements for the period
prior to our Equity Buyout transaction. Beginning October 3, 2005, the effective date of the Equity Buyout, the accompanying consolidated financial statements reflect a stepped up (Successor)
basis of accounting to reflect the purchase of EXCO Resources by EXCO Holdings. See "Note 1. Organization" to the consolidated financial statements.

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

To
the Board of Directors and Shareholders of
EXCO Resources, Inc.:

Management
is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities
Exchange Act of 1934, as amended). Our internal control over financial reporting is designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair
presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over
financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal
ControlIntegrated Framework.Based on our assessment, we believe that, as of December 31, 2007, our internal control over
financial reporting is effective based on those criteria.

The
effectiveness of EXCO Resources, Inc.'s internal control over financial reporting as of December 31, 2007 has been audited by KPMG LLP, an independent registered
public accounting firm, as stated in their report which appears herein.

|By: /s/DOUGLAS H. MILLER        |  | By: /s/J. DOUGLAS RAMSEY
|------------------------------- |  | ------------------------
|Dallas, Texas
February 28, 2008 |  |                         

82

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Report of Independent Registered Public Accounting Firm

The
Board of Directors and Shareholders
EXCO Resources, Inc.:

We
have audited EXCO Resources, Inc.'s (the Company) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal ControlIntegrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). EXCO
Resources, Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We
conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.

A
company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In
our opinion, EXCO Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria
established inInternal ControlIntegrated Frameworkissued by the COSO.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of EXCO Resources, Inc.
and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the years in the two-year
period ended December 31, 2007, and our report dated February 27, 2008 expressed an unqualified opinion on those consolidated financial statements.

|                                |  | /s/ KPMG LLP
|------------------------------- |  | ------------
|Dallas, Texas
February 27, 2008 |  |             

83

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Report of Independent Registered Public Accounting Firm

The
Board of Directors and Shareholders
EXCO Resources, Inc.:

We
have audited the accompanying consolidated balance sheets of EXCO Resources, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated
statements of operations, shareholders' equity, and cash flows for each of the years in the two-year period ended December 31, 2007. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.

In
our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EXCO Resources, Inc. and subsidiaries
as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2007, in conformity
with U.S. generally accepted accounting principles.

We
also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EXCO Resources, Inc.'s internal control over financial
reporting as of December 31, 2007, based on criteria established inInternal ControlIntegrated Frameworkissued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2008 expressed an unqualified opinion on the effectiveness of the Company's internal control over
financial reporting.

|                                |  | /s/ KPMG LLP
|------------------------------- |  | ------------
|Dallas, Texas
February 27, 2008 |  |             

84

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Report of Independent Registered Public Accounting Firm

To
the Board of Directors and Shareholders of
EXCO Resources, Inc.:

In
our opinion, the accompanying consolidated statements of operations, of comprehensive income (loss), of shareholders' equity and of cash flows present fairly, in all material
respects, the results of operations and cash flows of EXCO Resources, Inc. and its subsidiaries (Predecessor Company) for the period from January 1, 2005 to October 2, 2005 in
conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As
discussed in Note 1 to the consolidated financial statements, all financial information presented reflects the consolidated results of operations of EXCO Resources, Inc.
and its former parent, EXCO Holdings Inc. in order to account for transactions between entities under common control as required by Statement of Financial Accounting Standards No. 141,
"Business Combinations".

|/s/ PRICEWATERHOUSECOOPERS LLP                                                            |  | 
|----------------------------------------------------------------------------------------- |  | 
|Dallas, Texas
May 15, 2006, except for Note 20,
as to which the date is February 28, 2008 |  | 

85

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Report of Independent Registered Public Accounting Firm

To
the Board of Directors and Shareholders of
EXCO Resources, Inc.:

In
our opinion, the accompanying consolidated statements of operations, of comprehensive income (loss), of shareholders' equity and of cash flows present fairly, in all material
respects, the results of operations and cash flows of EXCO Resources, Inc. and its subsidiaries (Successor Company) for the period from October 3, 2005 to December 31, 2005 in
conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As
discussed in Note 1 to the consolidated financial statements, all financial information presented reflects the consolidated results of operations of EXCO Resources, Inc.
and its former parent, EXCO Holdings Inc. in order to account for transactions between entities under common control as required by Statement of Financial Accounting Standards No. 141,
"Business Combinations".

|/s/ PRICEWATERHOUSECOOPERS LLP                                                            |  | 
|----------------------------------------------------------------------------------------- |  | 
|Dallas, Texas
May 15, 2006, except for Note 20,
as to which the date is February 28, 2008 |  | 

86

---





EXCO Resources, Inc.    Consolidated balance sheet

|                                                              |                                                                 | December 31,        |                     
|------------------------------------------------------------- | --------------------------------------------------------------- | ------------------- | --------------------
|
|
|Assets                                                        |                                                                 |                     |                     
|Current assets:                                               |                                                                 |                     |                     
|                                                              | Cash and cash equivalents                                       |                     | $                   
|                                                              | Accounts receivable:                                            |                     |                     
|                                                              |                                                                 | Oil and natural gas |                     
|                                                              |                                                                 | Joint interest      |                     
|                                                              |                                                                 | Interest and other  |                     
|                                                              | Oil and natural gas derivatives                                 |                     |                     
|                                                              | Deferred income taxes                                           |                     |                     
|                                                              | Other                                                           |                     |                     
|                                                              |                                                                 |                     |                     
|                                                              |                                                                 |                     | Total current assets
|                                                              |                                                                 |                     |                     
|Oil and natural gas properties (full cost accounting method): |                                                                 |                     |                     
|                                                              | Unproved oil and natural gas properties                         |                     |                     
|                                                              | Proved developed and undeveloped oil and natural gas properties |                     |                     
|                                                              | Accumulated depletion                                           |                     |                     
|                                                              |                                                                 |                     |                     
|                                                              | Oil and natural gas properties, net                             |                     |                     
|                                                              |                                                                 |                     |                     
|Gas gathering assets                                          |                                                                 |                     | 203,537             
|                                                              | Accumulated depreciation and amortization                       |                     |                     
|                                                              |                                                                 |                     |                     
|Gas gathering assets, net                                     |                                                                 |                     | 199,356             
|                                                              |                                                                 |                     |                     
|Office and field equipment, net                               |                                                                 |                     | 14,805              
|Advance on pending acquisition                                |                                                                 |                     | 80,000              
|Oil and natural gas derivatives                               |                                                                 |                     | 41,469              
|Deferred financing costs, net                                 |                                                                 |                     | 15,929              
|Other assets                                                  |                                                                 |                     | 520                 
|Goodwill                                                      |                                                                 |                     | 470,077             
|                                                              |                                                                 |                     |                     
|                                                              |                                                                 |                     | Total assets        
|                                                              |                                                                 |                     |                     

See accompanying notes.

87

---





EXCO Resources, Inc.    Consolidated balance sheets

|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        | December 31,                              
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | ------------------------------------------
|
|
|Liabilities and shareholders' equity                                                                                                                                                       |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Current liabilities:                                                                                                                                                                       |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           | Accounts payable and accrued liabilities                                                                                                                                                                                                                                                                                                                                                                                                               |                                           
|                                                                                                                                                                                           | Accrued interest payable                                                                                                                                                                                                                                                                                                                                                                                                                               |                                           
|                                                                                                                                                                                           | Revenues and royalties payable                                                                                                                                                                                                                                                                                                                                                                                                                         |                                           
|                                                                                                                                                                                           | Income taxes payable                                                                                                                                                                                                                                                                                                                                                                                                                                   |                                           
|                                                                                                                                                                                           | Deferred income taxes payable                                                                                                                                                                                                                                                                                                                                                                                                                          |                                           
|                                                                                                                                                                                           | Current portion of asset retirement obligations                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           | Current portion of long-term debt                                                                                                                                                                                                                                                                                                                                                                                                                      |                                           
|                                                                                                                                                                                           | Oil and natural gas derivatives                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        | Total current liabilities                 
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Long-term debt, net of current portion                                                                                                                                                     |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Asset retirement obligations and other long-term liabilities                                                                                                                               |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Deferred income taxes                                                                                                                                                                      |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Oil and natural gas derivatives                                                                                                                                                            |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Commitments and contingencies                                                                                                                                                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|7.0% Cumulative Convertible Perpetual Preferred Stock, par value $0.001 per share, 39,008 shares outstanding at December 31, 2007, liquidation preference of $391,218 at December 31, 2007 |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Hybrid Preferred Stock, par value $0.001 per share, 160,992 shares outstanding at December 31, 2007, liquidation preference of $1,614,616 at December 31, 2007                             |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|Shareholders' equity:                                                                                                                                                                      |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           | Preferred stock, par value $0.001 per share; 10,000,000 shares authorized at December 31, 2007, of which 39,008 shares have been designated as 7.0% Cumulative Convertible Perpetual Preferred Stock and 160,992 shares
have been designated as Hybrid Preferred Stock; no shares of preferred stock other than the 7.0% Cumulative Convertible Perpetual and Hybrid Preferred Stock (presented above) are issued and outstanding at December 31, 2007 |                                           
|                                                                                                                                                                                           | Common stock, $0.001 par value; Authorized shares350,000,000; issued and outstanding shares104,162,241 at December 31, 2006 and 104,578,941 at December 31, 2007                                                                                                                                                                                                                                                                                     |                                           
|                                                                                                                                                                                           | Additional paid-in capital                                                                                                                                                                                                                                                                                                                                                                                                                             |                                           
|                                                                                                                                                                                           | Retained earnings                                                                                                                                                                                                                                                                                                                                                                                                                                      |                                           
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        | Total shareholders' equity                
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        | Total liabilities and shareholders' equity
|                                                                                                                                                                                           |                                                                                                                                                                                                                                                                                                                                                                                                                                                        |                                           

See accompanying notes.

88

---





EXCO Resources, Inc.    Consolidated statements of operations

|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|-------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------- | -------- | -------- | ------- | - | - | ------ | ------ | ------ | -------
|
|
|Revenues and other income:                         |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   | Oil and natural gas                                                                                                                                                                                                                                                                                         |                                                                  | $        | 132,821  |         |   |   | $      | 70,061 |        | $      
|                                                   | Gain (loss) on derivative financial instruments                                                                                                                                                                                                                                                             |                                                                  |          | (177,253 | )       |   |   |        | (256   | )      |        
|                                                   | Other income                                                                                                                                                                                                                                                                                                |                                                                  |          | 7,096    |         |   |   |        | 2,374  |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Total revenues and other income                                  |          |          | (37,336 | ) |   |        |        | 72,179 |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Cost and expenses:                                 |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   | Oil and natural gas production (includes $0, $0, $0 and $3.6 million of non-cash compensation expense for the period from January 1, 2005 to October 2, 2005, the period from October 3, 2005 to
December 31, 2005 and the years ended December 31, 2006 and 2007, respectively)                            |                                                                  |          | 22,157   |         |   |   |        | 8,949  |        |        
|                                                   | Depreciation, depletion and amortization                                                                                                                                                                                                                                                                    |                                                                  |          | 24,687   |         |   |   |        | 14,071 |        |        
|                                                   | Accretion of discount on asset retirement obligations                                                                                                                                                                                                                                                       |                                                                  |          | 617      |         |   |   |        | 226    |        |        
|                                                   | General and administrative (includes $44.1 million, $2.2 million, $6.5 million and $9.0 million of non-cash compensation expense for the period from January 1, 2005 to October 2, 2005, the
period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007, respectively) |                                                                  |          | 89,442   |         |   |   |        | 6,375  |        |        
|                                                   | Interest                                                                                                                                                                                                                                                                                                    |                                                                  |          | 26,675   |         |   |   |        | 19,414 |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Total cost and expenses                                          |          |          | 163,578 |   |   |        |        | 49,035 |        
|                                                   | Equity in net income of TXOK Acquisition, Inc.                                                                                                                                                                                                                                                              |                                                                  |          |         |         |   |   |        | 837    |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Income (loss) before income taxes                  |                                                                                                                                                                                                                                                                                                             |                                                                  | (200,914 | )        |         |   |   | 23,981 |        |        | 228,355
|Income tax expense (benefit)                       |                                                                                                                                                                                                                                                                                                             |                                                                  | (63,698  | )        |         |   |   | 7,631  |        |        | 89,401 
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Income (loss) before discontinued operations       |                                                                                                                                                                                                                                                                                                             |                                                                  | (137,216 | )        |         |   |   | 16,350 |        |        | 138,954
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Discontinued operations:                           |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   | Loss from operations                                                                                                                                                                                                                                                                                        |                                                                  |          | (4,403   | )       |   |   |        |       |        |        
|                                                   | Gain on disposition of Addison Energy Inc.                                                                                                                                                                                                                                                                  |                                                                  |          | 175,717  |         |   |   |        |       |        |        
|                                                   | Income tax expense                                                                                                                                                                                                                                                                                          |                                                                  |          | 49,282   |         |   |   |        |       |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Income from discontinued operations                              |          |          | 122,032 |   |   |        |        |       |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Net income (loss)                                  |                                                                                                                                                                                                                                                                                                             |                                                                  | (15,184  | )        |         |   |   | 16,350 |        |        | 138,954
|                                                   | Preferred stock dividends                                                                                                                                                                                                                                                                                   |                                                                  |          |         |         |   |   |        |       |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Net income (loss) available to common shareholders |                                                                                                                                                                                                                                                                                                             | $                                                                | (15,184  | )        |         |   | $ | 16,350 |        | $      | 138,954
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|Earnings per share:                                |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   | Basic                                                                                                                                                                                                                                                                                                       |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Net income (loss) from continuing operations                     |          | $        | (1.18   | ) |   |        | $      | 0.35   |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Net income (loss) available to common shareholders               |          | $        | (0.13   | ) |   |        | $      | 0.35   |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Weighted average common shares outstanding                       |          |          | 116,504 |   |   |        |        | 47,222 |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   | Diluted                                                                                                                                                                                                                                                                                                     |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Net income (loss) from continuing operations                     |          | $        | (1.18   | ) |   |        | $      | 0.35   |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Net income (loss) available to common shareholders               |          | $        | (0.13   | ) |   |        | $      | 0.35   |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        
|                                                   |                                                                                                                                                                                                                                                                                                             | Weighted average common and common equivalent shares outstanding |          |          | 116,504 |   |   |        |        | 47,222 |        
|                                                   |                                                                                                                                                                                                                                                                                                             |                                                                  |          |          |         |   |   |        |        |        |        

See accompanying notes.

89

---





EXCO Resources, Inc.    Consolidated statements of cash flows

|                                                                                                           |                                                                                                                 | Predecessor                                        |          |          |         | Successor |  
|---------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------- | -------------------------------------------------- | -------- | -------- | ------- | --------- | -
|
|
|Operating Activities:                                                                                      |                                                                                                                 |                                                    |          |          |         |           |  
|Net income (loss)                                                                                          |                                                                                                                 | $                                                  | (15,184  | )        |         |           | $
|                                                                                                           | Income from discontinued operations                                                                             |                                                    |          | (122,032 | )       |           |  
|Adjustments to reconcile net income (loss) to net cash provided by operating activities:                   |                                                                                                                 |                                                    |          |          |         |           |  
|                                                                                                           | Equity in net income of TXOK Acquisition, Inc.                                                                  |                                                    |          |         |         |           |  
|                                                                                                           | Gain on sale of other assets                                                                                    |                                                    |          | (373     | )       |           |  
|                                                                                                           | Depreciation, depletion and amortization                                                                        |                                                    |          | 24,687   |         |           |  
|                                                                                                           | Stock option compensation expense                                                                               |                                                    |          | 44,092   |         |           |  
|                                                                                                           | Accretion of discount on asset retirement obligations                                                           |                                                    |          | 617      |         |           |  
|                                                                                                           | Non-cash change in fair value of derivatives                                                                    |                                                    |          | 114,410  |         |           |  
|                                                                                                           | Cash settlements of assumed derivative                                                                          |                                                    |          |         |         |           |  
|                                                                                                           | Deferred income taxes                                                                                           |                                                    |          | (59,467  | )       |           |  
|                                                                                                           | Amortization of deferred financing costs, premium on 71/4% senior notes due 2011 and discount on long-term debt |                                                    |          | 1,320    |         |           |  
|                                                                                                           | Gains from sales of marketable securities                                                                       |                                                    |          | 3        |         |           |  
|                                                                                                           |                                                                                                                 | Effect of changes, net of acquisition effects, in: |          |          |         |           |  
|                                                                                                           |                                                                                                                 | Accounts receivable                                |          |          | (24,512 | )         |  
|                                                                                                           |                                                                                                                 | Other current assets                               |          |          | (369    | )         |  
|                                                                                                           |                                                                                                                 | Accounts payable and other current liabilities     |          |          | 25,458  |           |  
|Net cash provided by (used in) operating activities of discontinued operations                             |                                                                                                                 |                                                    | (69,772  | )        |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Net cash provided by (used in) operating activities                                                        |                                                                                                                 |                                                    | (81,122  | )        |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Investing Activities:                                                                                      |                                                                                                                 |                                                    |          |          |         |           |  
|Investment in TXOK Acquisition, Inc.                                                                       |                                                                                                                 |                                                    |         |          |         |           |  
|Additions to oil and natural gas properties, gathering systems and equipment                               |                                                                                                                 |                                                    | (151,144 | )        |         |           |  
|Proceeds from disposition of property and equipment                                                        |                                                                                                                 |                                                    | 46,010   |          |         |           |  
|Payment to TXOK Acquisition, Inc. for preferred stock redemptions, net of cash acquired                    |                                                                                                                 |                                                    |         |          |         |           |  
|Acquisition of Power Gas Marketing & Transmission, Inc., net of cash acquired                              |                                                                                                                 |                                                    |         |          |         |           |  
|Acquisition of Winchester Energy Company, Ltd., net of cash acquired                                       |                                                                                                                 |                                                    |         |          |         |           |  
|Advance payment on pending acquisition                                                                     |                                                                                                                 |                                                    |         |          |         |           |  
|Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415                                      |                                                                                                                 |                                                    | 443,397  |          |         |           |  
|Advances/investments with affiliates                                                                       |                                                                                                                 |                                                    |         |          |         |           |  
|Proceeds from sales of marketable securities                                                               |                                                                                                                 |                                                    | 59       |          |         |           |  
|Net cash (provided by) used in investing activities of discontinued operations                             |                                                                                                                 |                                                    | (442     | )        |         |           |  
|Other investing activities                                                                                 |                                                                                                                 |                                                    |         |          |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Net cash provided by (used in) investing activities                                                        |                                                                                                                 |                                                    | 337,880  |          |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Financing Activities:                                                                                      |                                                                                                                 |                                                    |          |          |         |           |  
|Proceeds from long-term debt                                                                               |                                                                                                                 |                                                    | 41,300   |          |         |           |  
|Repayment of interim bank loan                                                                             |                                                                                                                 |                                                    |         |          |         |           |  
|Payments on long-term debt                                                                                 |                                                                                                                 |                                                    | (148,247 | )        |         |           |  
|Proceeds from issuance of common stock, net of underwriter's commissions and initial public offering costs |                                                                                                                 |                                                    |         |          |         |           |  
|Proceeds from issuance of preferred stock, net of underwriter's commissions and issuance costs             |                                                                                                                 |                                                    |         |          |         |           |  
|Dividends on preferred stock                                                                               |                                                                                                                 |                                                    |         |          |         |           |  
|Principal and interest on notes receivable-employees                                                       |                                                                                                                 |                                                    | 311      |          |         |           |  
|Settlement of derivative financial instruments on Power Gas Marketing & Transmission, Inc. acquisition     |                                                                                                                 |                                                    |         |          |         |           |  
|Settlements of derivative financial instruments with a financing element                                   |                                                                                                                 |                                                    |         |          |         |           |  
|Deferred financing costs and other                                                                         |                                                                                                                 |                                                    |         |          |         |           |  
|Net cash provided by (used in) financing activities of discontinued operations                             |                                                                                                                 |                                                    | 59,601   |          |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Net cash provided by (used in) financing activities                                                        |                                                                                                                 |                                                    | (47,035  | )        |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Net increase (decrease) in cash                                                                            |                                                                                                                 |                                                    | 209,723  |          |         |           |  
|Cash at beginning of period                                                                                |                                                                                                                 |                                                    | 26,408   |          |         |           |  
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Cash at end of period                                                                                      |                                                                                                                 | $                                                  | 236,131  |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Supplemental Cash Flow Information:                                                                        |                                                                                                                 |                                                    |          |          |         |           |  
|Interest paid                                                                                              |                                                                                                                 | $                                                  | 33,099   |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Income taxes paid (received)                                                                               |                                                                                                                 | $                                                  | 38,213   |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Value of shares issued in connection with redemption of TXOK Acquisition, Inc. preferred stock             |                                                                                                                 | $                                                  |         |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Long-term debt assumed in TXOK Acquisition, Inc. acquisition                                               |                                                                                                                 | $                                                  |         |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Long-term debt assumed in Power Gas Marketing & Transmission, Inc. acquisition                             |                                                                                                                 | $                                                  |         |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Derivative financial instruments assumed in acquisitions                                                   |                                                                                                                 | $                                                  |         |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Value of common stockCrimson                                                                              |                                                                                                                 | $                                                  |         |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Supplemental non cash investing:                                                                           |                                                                                                                 |                                                    |          |          |         |           |  
|Capitalized stock compensation                                                                             |                                                                                                                 | $                                                  |         |          |         |           | $
|                                                                                                           |                                                                                                                 |                                                    |          |          |         |           |  

See accompanying notes.

90

---





EXCO Resources, Inc.    Consolidated statements of changes in shareholders' equity

|                                                      |  | Common Stock |  |   |     |  |   |           |   |   |        |   |  
|----------------------------------------------------- |  | ------------ |  | - | --- |  | - | --------- | - | - | ------ | - | -
|
|
|Predecessor:                                          |  |              |  |   |     |  |   |           |   |   |        |   |  
|Balance, December 31, 2004                            |  | 127,873      |  | $ | 128 |  | $ | 173,804   |   | $ | (1,573 | ) | $
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Foreign currency translation adjustments              |  |             |  |   |    |  |   |          |   |   |       |   |  
|Unrealized gain on equity investments                 |  |             |  |   |    |  |   |          |   |   |       |   |  
|Principal and interest payable                        |  |             |  |   |    |  |   |          |   |   | 311    |   |  
|Net loss                                              |  |             |  |   |    |  |   |          |   |   |       |   |  
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Balance for the 275 day period ended October 2, 2005  |  | 127,873      |  |   | 128 |  |   | 173,804   |   |   | (1,262 | ) | $
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Successor:                                            |  |              |  |   |     |  |   |           |   |   |        |   |  
|Acquisition by Holdings II                            |  | 50,000       |  |   | 50  |  |   | 350,965   |   |   |       |   |  
|Stock based compensation                              |  |             |  |   |    |  |   | 3,517     |   |   |       |   |  
|Net income                                            |  |             |  |   |    |  |   |          |   |   |       |   |  
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Balance for the 90 day period ended December 31, 2005 |  | 50,000       |  |   | 50  |  |   | 354,482   |   |   |       |   |  
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Issuance of common stock, net of expenses             |  | 54,162       |  |   | 54  |  |   | 668,021   |   |   |       |   |  
|Deferred initial public offering costs                |  |             |  |   |    |  |   | (6,027    | ) |   |       |   |  
|Share-based compensation                              |  |             |  |   |    |  |   | 7,966     |   |   |       |   |  
|Net income                                            |  |             |  |   |    |  |   |          |   |   |       |   |  
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Balance at December 31, 2006                          |  | 104,162      |  |   | 104 |  |   | 1,024,442 |   |   |       |   |  
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Issuance of common stock                              |  | 417          |  |   | 1   |  |   | 4,161     |   |   |       |   |  
|Preferred stock dividends                             |  |             |  |   |    |  |   |          |   |   |       |   |  
|Share-based compensation                              |  |             |  |   |    |  |   | 15,042    |   |   |       |   |  
|Net income                                            |  |             |  |   |    |  |   |          |   |   |       |   |  
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  
|Balance at December 31, 2007                          |  | 104,579      |  | $ | 105 |  | $ | 1,043,645 |   | $ |       |   | $
|                                                      |  |              |  |   |     |  |   |           |   |   |        |   |  

See accompanying notes.

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EXCO Resources, Inc.    Notes to consolidated financial statements

1.     Organization

Unless the context requires otherwise, references in this Annual Report on Form 10-K to "EXCO," "EXCO Resources," "Company," "we," "us," and
"our" are to EXCO Resources, Inc., its consolidated subsidiaries and EXCO Holdings Inc., or EXCO Holdings, our former parent company that merged with us on February 14, 2006.

EXCO
Resources, Inc., a Texas corporation, was formed in October 1955. We are an independent oil and natural gas company engaged in the acquisition, development and exploitation
of onshore North American oil and natural gas properties. We expect to continue to grow by leveraging our management team's experience, exploiting our multi-year inventory of development
drilling locations and exploitation projects, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive derivative
financial instrument program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on
investment, and manage our capital structure. Our operations are focused in key North American oil and natural gas areas including East Texas/North Louisiana, Appalachia, Mid-Continent and
Permian. In February 2005, we sold our Canadian subsidiary. As a result, all of our operations include onshore United States oil and natural gas properties and related facilities.

Due
to the merger of our parent, EXCO Holdings (formerly EXCO Holdings II), into EXCO Resources on February 14, 2006 concurrent with the closing of our initial public offering, or
IPO, all financial information in this Annual Report on Form 10-K contains the consolidated financial position and results of EXCO Resources and EXCO Holdings pursuant to
presentation requirements contained in Statement of Financial Accounting Standards, or SFAS, No. 141, "Business Combinations", or SFAS No. 141, for transactions between entities under
common control. For comparative purposes pursuant to SFAS No. 141, the prior period financial statements of EXCO
Resources present the consolidated operations of EXCO Resources and EXCO Holdings for all periods. As described below, our financial statements contain two separate and distinct bases of accounting.

PredecessorFor
the 275 day period from January 1, 2005 to October 2, 2005, financial information presented in our consolidated statements of operations,
consolidated statements of cash flows and consolidated statements of shareholders' equity reflect the consolidated information of EXCO Resources and EXCO Holdings, our parent company until
October 2, 2005.

SuccessorFor
the 90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007, financial information
presented in our consolidated financial statements of operations, statements of cash flows and consolidated statements of shareholders' equity reflect the consolidated information of EXCO Resources
and Holdings II, which became our parent company on October 3, 2005 effective when all of the outstanding equity securities of EXCO Holdings was purchased in a private transaction, or the
Equity Buyout, and with the acquisition by and merger of Holdings II into EXCO Holdings. The Equity Buyout was accounted for as a purchase pursuant to SFAS No. 141 and resulted in a new basis
of accounting. The consolidated balance sheets as of December 31, 2006 and 2007 reflect this new basis of accounting.

In
addition, as a result of the redemption of TXOK preferred stock (See "Note 4. Significant transactionsRedemption of preferred stock and consolidation of TXOK") on
February 14, 2006, our investment in TXOK Acquisition, Inc., or TXOK, which was accounted for using the equity method of accounting until our redemption of the preferred stock, became a
wholly-owned subsidiary.

On
February 8, 2006, our registration statement on Form S-1, as amended, was declared effective by the Securities and Exchange Commission, or SEC, pursuant to
which we offered 50,000,000 shares

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of
our common stock, par value $.001 per share, at an initial offering price of $13.00 per share, or a net price after underwriting discount of $12.35 per share. Net proceeds from the offering after
underwriting discount, but before other expenses, were approximately $617.5 million. Concurrent with the February 14, 2006 closing of the IPO, EXCO Holdings, our parent company, was
merged into and with EXCO Resources and EXCO Resources became the surviving company. Shares of stock and stock options of EXCO Holdings were automatically converted into an equal number of like
securities of EXCO Resources. Subsequently, the underwriters of our IPO exercised their over-allotment option to purchase an additional 3,615,200 shares of our common stock at $12.35 per
share which yielded additional net proceeds of approximately $44.6 million.

The
accompanying consolidated balance sheets as of December 31, 2006 and 2007, results of operations, cash flows and changes in shareholders' equity for the 275 day period
from January 1, 2005 to October 2,
2005, the 90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007 are for EXCO, its subsidiaries, and prior to the IPO, its
parent. All intercompany transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation.

2.     Summary of significant accounting policies

Principles of consolidation

The accompanying consolidated balance sheets as of December 31, 2006 and December 31, 2007 and the results of operations and cash flows for the
90 day period from October 3, 2005 to December 31, 2005 and for the twelve months ended December 31, 2006 and 2007 are for EXCO and its subsidiaries and represent the
stepped up accounting basis of the Successor company following the Equity Buyout transaction.

The
accompanying results of operations and cash flows for the 275 day period from January 1, 2005 to October 2, 2005 are for EXCO and its subsidiaries and represent
the Predecessor company's basis of accounting.

All
intercompany transactions and accounts have been eliminated.

Management estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States, we are required to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting periods. The most significant estimates pertain to proved oil and natural gas reserve
volumes, future development costs, dismantlement and abandonment costs, share-based compensation expenses, estimates relating to certain oil and natural gas revenues and expenses and the fair market
value of assets and liabilities acquired in business combinations, derivatives and equity securities. Actual results may differ from management's estimates.

Cash equivalents

We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.

Concentration of credit risk and accounts receivable

Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial
instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling,
completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants

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in
oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to wells which we operate. Oil and natural gas receivables
are generally uncollateralized. The allowance for doubtful accounts receivable aggregated $1.9 million and $2.0 million at December 31, 2006 and 2007, respectively. We place our
derivative financial instruments with financial institutions and other firms that we believe have high credit ratings. For a discussion of the credit risks associated with our commodity price risk
management activities, see "Note 6. Derivative financial instruments."

Derivative financial instruments

In connection with the incurrence of debt related to our acquisition activities, our management has adopted a policy of entering into oil and natural gas
derivative financial instruments to protect against commodity price fluctuations and to achieve a more predictable cash flow. SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," or SFAS No. 133, requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an
asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria
are met, or exemptions for normal purchases and normal sales as permitted by SFAS No. 133 exist. We do not designate our derivative financial instruments as hedging instruments and, as a
result, recognize the change in the derivative's fair value currently in earnings.

Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. Once we incur costs, they
are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs, which totaled $297.9 million and
$334.8 million as of December 31, 2006 and 2007, respectively, are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis, and we expect
these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease
and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds.

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

At
the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net
revenues from our oil and natural gas properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). Until February 10, 2005,
this ceiling test calculation was done separately for the United States and for our Canadian subsidiary full cost pools. When computing our ceiling test, we evaluate the limitation at the end of each
reporting period date. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation for price changes that occur after the
balance sheet to assess impairment as permitted by Staff Accounting Bulletin Topic 12Oil and Gas Producing Activities. In addition, in July 2007, we sought, and received, an exemption
from the SEC to exclude the acquisitions of Winchester, Vernon and Southern Gas from our ceiling test for a period of 12 months from the closing date of each acquisition, provided that we could
demonstrate beyond a reasonable doubt that the fair value of the oil and natural gas reserves exceeded their unamortized carrying costs. The exemption related to

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Winchester
expired October 2, 2007 and therefore was included in our December 31, 2007 ceiling test calculation. The exemption related to Vernon will expire on March 30, 2008 and
the exemption related to Southern Gas will expire on May 2, 2008.

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.

The
allocated value of proved properties for the 2007 Acquisitions totaled approximately $2.2 billion, which represented an increase of over 87% to the full cost pool from
December 31, 2006. The request for exemption was made because the Company believes the fair value of the 2007 Acquisitions' proved oil and gas properties, in certain cases, can be demonstrated
beyond a reasonable doubt to exceed their unamortized costs. The Company's expectation of future prices is principally based on NYMEX futures contracts, adjusted for basis differentials, for a period
of five years. After a five year period we have historically elected to use flat pricing as the NYMEX futures contracts become more thinly traded. Generally, the flat price used for the sixth year
through the economic life of the property is management's internal long-term price estimate, which is, in large part, based on an extension of the NYMEX pricing. EXCO believes the NYMEX
futures contract reflects an independent proxy for fair value.

We
recognize that, due to the volatility associated with oil and natural gas prices, a downward trend in market prices could occur. If such a trend were to occur and is deemed to be
other than a temporary trend, we would assess the 2007 Acquisitions for impairment during the 2008 exemption period.

The
calculation of the ceiling test is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the
future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing 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.

Full cost ceiling test

As of December 31, 2007, the ceiling test computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of
deferred taxes, exceeding the December 31, 2007 present value of future net revenues by approximately $206.2 million, of which approximately $112.3 million was attributable to our
Vernon and Southern Gas acquisitions, which would have resulted in a net ceiling test impairment of $93.9 million. Even though the December 31, 2007 prices for oil and natural gas
indicated impairment, the spot price for natural gas and oil increased on February 22, 2008 to a level sufficient to eliminate the need for a ceiling test write-down.

Gas gathering assets

Gas gathering assets are capitalized at cost and depreciated on a straight line basis over their estimated useful lives of 25 to 40 years.

Office and field equipment

Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field equipment useful
lives range from 3 to 15 years.

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Goodwill

In accordance with SFAS No. 142, "Goodwill and Intangible Assets," or SFAS No. 142, goodwill is not amortized, but is tested for impairment on an
annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is
associated, are performed at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. In a February 2005
letter to oil and natural gas companies, the SEC provided guidance concerning the treatment of goodwill in situations when a company sells less than 25% of its proved oil and natural gas reserves in a
cost pool. The guidance indicated that such dispositions may trigger a need to evaluate goodwill for impairment under SFAS No. 142. As a result of this guidance, beginning January 1,
2005, we no longer reduce the balance of goodwill for property dispositions of less than 25% of our oil and natural gas reserves unless there is an indication that our goodwill is impaired as a result
of the sale.

The
following table reflects our balances for goodwill as of December 31, 2005, 2006 and 2007 (in thousands):

Successor:Balance as of December 31, 2005

$
220,006Acquisition of TXOK


64,887Acquisition of Power Gas Marketing and Transmission, Inc.


21,249Acquisition of Winchester Energy Company, Ltd.


163,935Balance as of December 31, 2006 and 2007

$
470,077


Deferred abandonment and asset retirement obligations

In June 2001, the Financial Accounting Standards Board, or FASB, issued SFAS No. 143, "Accounting for Asset Retirement Obligations," or SFAS
No. 143. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are
incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our
asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive
lives, in accordance with applicable state laws.

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The
following is a reconciliation of our asset retirement obligations for the periods indicated (in thousands):

|                                                                                                  |  | Predecessor |        | Successor |  
|------------------------------------------------------------------------------------------------- |  | ----------- | ------ | --------- | -
|
|Asset retirement obligations at beginning of period                                               |  | $           | 13,247 |           | $
|Activity during the period:                                                                       |  |             |        |           |  
|Adjustment to liability due to purchase of EXCO Resources, Inc. by EXCO Holdings II, Inc. in 2005 |  |             |       |           |  
|Adjustment to liability due to 2006 acquisitions                                                  |  |             |       |           |  
|Adjustment to liability due to 2007 acquisitions                                                  |  |             |       |           |  
|Liabilities incurred during period                                                                |  |             | 1,686  |           |  
|Liabilities settled during period                                                                 |  |             | (1,275 | )         |  
|Accretion of discount                                                                             |  |             | 617    |           |  
|                                                                                                  |  |             |        |           |  
|Asset retirement obligations at end of period:                                                    |  |             | 14,275 |           |  
|Less current portion                                                                              |  |             | 1,713  |           |  
|                                                                                                  |  |             |        |           |  
|Long-term portion                                                                                 |  | $           | 12,562 |           | $
|                                                                                                  |  |             |        |           |  

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

Revenue recognition and gas imbalances

We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural
gas sold to purchasers. Gas imbalances at December 31, 2006 and 2007 were not significant.

Capitalization of internal costs

We capitalize as part of our proved developed oil and natural gas properties a portion of salaries and, beginning in October 2005, related share-based
compensation for employees who are directly involved in the acquisition and exploitation of oil and natural gas properties. During the 275 day period from January 1, 2005 to
October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007, we have capitalized $1.2 million,
$1.5 million, $4.7 million and $8.1 million, respectively. Included in the $1.5 million, the $4.7 million and $8.1 million are $1.0 million,
$1.4 million and $2.4 million of share based compensation for the 90 day period from October 3, 2005 to December 31, 2005, the years ended December 31, 2006
and 2007, respectively, resulting from the adoption of SFAS No. 123(R), "Share-Based Compensation," or SFAS No. 123(R), on October 3, 2005. See "Note 13. Stock
transactions" for further discussion.

Overhead reimbursement fees

We have classified fees from overhead charges billed to working interest owners, including ourselves, of $1.3 million, $0.5 million,
$7.8 million and $18.4 million, for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to
December 31, 2005 and

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the
years ended December 31, 2006 and 2007, respectively, as a reduction of general and administrative expenses in the accompanying consolidated statements of operations. Our share of these
charges was $0.8 million, $0.3 million, $5.5 million and $13.5 million for the 275 day period from January 1, 2005 to October 2, 2005, the
90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007, respectively, and are classified as oil and natural gas production
costs.

Environmental costs

Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations
are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.

Income taxes

Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences
between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred
taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that
the benefit from the deferred tax asset will not be realized.

Earnings per share

We account for earnings per share in accordance with SFAS No. 128, "Earnings Per Share", or SFAS No. 128. SFAS No. 128 requires companies to
present two calculations of earnings per share, or EPS; basic and diluted. Basic earnings per common share are based on the weighted average number of common shares outstanding during the period.
Diluted earnings per common share is computed in the same manner as basic earnings per share after assuming issuance of common stock for all potentially dilutive equivalent shares, whether exercisable
or not.

Stock options

On December 16, 2004, FASB issued SFAS No. 123(R), which is a revision of SFAS No. 123, "Accounting for Stock-Based Compensation," or SFAS
No. 123. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, "Statement of Cash Flows." Generally, the approach in SFAS No. 123(R) is similar to the approach
described in SFAS No. 123. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in our consolidated statements of
operations based on their estimated fair values. Pro forma disclosure is no longer an alternative.

EXCO
adopted the 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, which provides for the granting of options to purchase up to 20,000,000 shares of our common
stock. New shares will be issued for any stock options exercised. As a result of the new basis in accounting due to the Equity Buyout, we adopted the provisions of SFAS No. 123(R) as of
October 3, 2005 in connection with the Equity Buyout. See "Note 14. Stock transactions" for additional information related to the 2005 Incentive Plan. The adoption of SFAS
No. 123(R) did not have a cumulative affect on our financial statements as no options were outstanding prior to October 5, 2005.

3.     Recent accounting pronouncements

The FASB issued FASB Staff Position 00-19-2 "Accounting for Registration Payment Arrangements," or FSP 00-19-2, on
December 21, 2006. FSP 00-19-2 requires contingent obligations to make future payments under a registration payment arrangement to be recognized separately in

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accordance
with SFAS No. 5, "Accounting for Contingencies," or SFAS No. 5. SFAS No. 5 requires that an estimated loss from a loss contingency be accrued if the loss is probable
and can reasonably be estimated. Our 7.0% Preferred Stock and Hybrid Preferred Stock contain requirements for EXCO, in certain circumstances, to register shares on behalf of the preferred
stockholders. On September 5, 2007, we filed an automatically effective registration statement on Form S-3 with the SEC to register for resale the shares of common stock
issuable upon conversion of the Series A-1 7.0% Preferred Stock and the Series A-1 Hybrid Preferred Stock. If such registration deadlines are not met, or a prior
registration statement ceases to remain effective, we may be obligated to pay liquidated damages. We adopted FSP 00-19-2 upon issuance of the 7.0% Preferred Stock and the
Hybrid Preferred Stock. We do not believe any of the contingencies associated with the registration rights of the preferred stockholders are probable as of December 31, 2007 and therefore are
not valued separately at December 31, 2007.

In
September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements," or SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in
generally accepted accounting principles, or GAAP, and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and
interim periods within those fiscal years for financial instruments. In February 2008, the FASB issued a one year deferral for non-financial assets and liabilities. We adopted SFAS
No. 157 for financial assets and liabilities on January 1, 2008. We will adopt SFAS No. 157 for non-financial assets and liabilities on January 1, 2009. The
effect of adopting SFAS No. 157 is not expected to have a significant effect on our financial statements.

In
February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial LiabilitiesIncluding an Amendment of FASB Statement
No. 115," or SFAS No. 159. SFAS No. 159 permits an entity to choose to measure many financial instruments and certain
other items at fair value. The fair value option established by SFAS No. 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains
and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS No. 159 is effective for financial statements
issued for fiscal years beginning after November 15, 2007, and as such, was adopted by us on January 1, 2008. The effect of adopting SFAS No. 159 is not expected to have a
significant effect on our financial statements.

In
December 2007, the FASB issued SFAS No. 141(R), "Business Combinations," or SFAS No. 141(R). SFAS No. 141(R) replaces SFAS No. 141. SFAS No. 141(R)
broadens the scope of business combinations to include bargain purchases, combinations of related companies, provides guidance on measuring goodwill and requires acquisition costs to be separate from
the value of assets and liabilities purchased. SFAS No. 141(R) is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be
adopted by us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 141(R) on our financial statements.

In
December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements," or SFAS No. 160. SFAS No. 160 amends Accounting
Research Bulletin 51, or ARB 51. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements separate from the
parent's equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. It also amends certain of ARB
No. 51's consolidation procedures for consistency with the requirements of SFAS No. 141(R). SFAS No. 160 also includes expanded disclosure requirements regarding the interests of
the parent and its noncontrolling interest. SFAS No. 160 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and as such, will be adopted by
us on January 1, 2009. We are currently evaluating the effect of adopting SFAS No. 160 on our financial statements.

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4.     Significant transactions

Initial public offering

On February 14, 2006, we closed our IPO and subsequently issued 53.6 million shares of our common stock, including shares subsequently issued
pursuant to an exercise by the underwriters of their
over-allotment option, for net proceeds of $662.2 million. Concurrent with the consummation of the IPO, we advanced $158.8 million to TXOK to redeem the TXOK preferred stock
and issued an additional 388,889 shares of our common stock as a redemption premium (seeRedemption of preferred stock and consolidation of TXOK). The redemption of this preferred stock
caused TXOK to become our wholly-owned subsidiary. In addition to the redemption of the preferred stock of TXOK, we used proceeds from the IPO, together with cash on hand to repay the interim bank
loan, repay the TXOK term loan, repay a portion of TXOK's revolving credit facility and pay fees and expenses incurred in connection with the IPO. Concurrent with the closing of the IPO, EXCO Holdings
merged with and into Resources and the shares of stock and stock options of EXCO Holdings were automatically converted into an equal number of like securities of EXCO Resources. As a result, we became
the surviving company.

Redemption of preferred stock and consolidation of TXOK

On February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights and an 89% economic interest in
TXOK. The redemption price for the TXOK preferred stock was cash in the amount of $150.0 million plus $8.8 million of unpaid dividends at a rate of 15% and 388,889 shares of our common
stock. The EXCO common stock issued in connection with the preferred redemption represented the value necessary to produce an overall 23% annualized rate of return on the stated value of the TXOK
preferred stock as of the date of redemption pursuant to the terms of the preferred stock agreement. For purposes of calculating the rate of return, the common stock of EXCO was valued at $12.00 as
required by the terms of the preferred stock. Once the TXOK preferred stock was redeemed, our acquisition of TXOK, or the TXOK acquisition, was complete and it became our wholly-owned subsidiary. We
accounted for the acquisition of TXOK as a step acquisition using the purchase method of accounting and began consolidating its operations effective February 14, 2006. As a result, 89% of the
fair value of the assets and liabilities of TXOK was recorded at the redemption date and the remaining 11% was recorded as an adjustment to book value as of the date of the initial investment. The
total purchase price of TXOK was $665.1 million representing the redemption of the TXOK preferred stock, the initial investment in TXOK common stock and the assumption of liabilities as
detailed below. The allocation of the purchase price to the assets and liabilities acquired, which reflects certain second quarter adjustments

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to
the original fair values assigned to certain current assets, current liabilities and deferred income taxes, are also presented (in thousands).

Purchase price calculation:Carrying value of initial investment in TXOK Acquisition, Inc.

$
21,531Acquisition of preferred stock, including accrued and unpaid dividends


158,750Value of preferred stock redemption premium


4,667Assumption of debt:Term loan, plus accrued interest


202,755Revolving credit facility plus accrued interest


309,701Less cash acquired


(32,261
)Net purchase price

$
665,143Allocation of purchase price:Oil and natural gas propertiesproved

$
489,076Oil and natural gas propertiesunproved


60,840Other fixed assets


20,079Current and non-current assets


37,460Deferred income taxes


26,783Goodwill


64,887Fair value of oil and natural gas derivatives


4,598Accounts payable and other accrued expenses


(30,377
)Asset retirement obligations


(8,203
)Total purchase price allocation

$
665,143


Acquisition of Power Gas Marketing & Transmission, Inc.

On April 28, 2006, our wholly-owned subsidiary, North Coast Energy, Inc., or North Coast, closed an acquisition of 100% of the common stock of Power
Gas Marketing & Transmission, Inc., or PGMT, for a purchase price of $115.0 million before contractual adjustments, and a net purchase price of $113.0 million. The purchase
price included the assumption of $13.1 million of debt and $38.1 million of derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn
under our credit facility, we paid the assumed debt and terminated the assumed derivative financial instruments. The acquisition was accounted for as a purchase in accordance with

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SFAS
No. 141. The allocation of the purchase price to the assets and liabilities of PGMT is presented on the following table (in thousands).

Purchase price calculation:Cash payments for acquired shares and contractual payments

$
63,615Assumption of debt including accrued interest


13,096Assumption of derivative financial instruments


38,098Less cash acquired


(1,839
)Net purchase price

$
112,970Allocation of purchase price:Oil and natural gas propertiesproved

$
122,972Oil and natural gas propertiesunproved


421Land, field equipment and other assets


2,573Current assets


2,024Goodwill


21,249Current liabilities


(3,267
)Other liabilities


(51
)Deferred taxes, net


(31,424
)Asset retirement obligations


(1,527
)Total purchase price allocation

$
112,970


Winchester Acquisition

On October 2, 2006, our wholly-owned subsidiary, Winchester Acquisition, LLC, or Winchester Acquisition, acquired Winchester Energy
Company, Ltd., or Winchester, and its affiliated entities from Progress Fuels Corporation for $1.1 billion in cash which was funded with $1.3 billion of indebtedness incurred by
EXCO Partners Operating Partnership, or EPOP, an unrestricted wholly-owned subsidiary of EXCO. For a detailed description of the EPOP debt incurred in connection with the Winchester acquisition, see
"Note 7. Long-term debtEPOP Credit Agreement and EPOP Senior Term Credit Agreement." The acquisition was accounted for as a purchase in accordance with SFAS
No. 141. Goodwill of $163.9 million resulted from the acquisition, primarily due to the Company's emphasis in concentrating on assets in the East Texas/North Louisiana producing regions.

The
allocation of the purchase price to the assets and liabilities of Winchester is presented on the following table (in thousands):

Purchase price calculation:Cash payments for acquired shares of common stock

$
1,095,028Less cash acquired


(118
)Net purchase price

$
1,094,910Allocation of purchase price:Oil and natural gas propertiesproved

$
583,683Oil and natural gas propertiesunproved


154,291Gathering and other fixed assets


151,149Current and non-current assets


31,872Fair value of oil and natural gas derivatives


57,193Goodwill


163,935Accounts payable and other accrued expenses


(39,420
)Asset retirement obligations


(7,793
)Total purchase price allocation

$
1,094,910


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Private placement of preferred stock

On March 30, 2007, we completed a private placement, or Private Placement, of an aggregate of $390.0 million of 7.0% Preferred Stock and
$1.61 billion of Hybrid Preferred Stock to accredited investors pursuant to the terms and conditions of a Preferred Stock Purchase Agreement dated March 28, 2007. The purchase price for
each share was $10,000 (which equaled the liquidation preference per share on March 30, 2007). The issuance and sale of the shares in the Private Placement was exempt from registration under
the Securities Act of 1933, or Securities Act, pursuant to Section 4(2) thereof and Regulation D promulgated thereunder.

The
net proceeds of the Private Placement were used to fund the purchase price of approximately $1.5 billion for the acquisition on March 30, 2007 of substantially all of
the oil and natural gas properties, acreage and related assets, including derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009, from
Anadarko Petroleum Corporation, or Anadarko, in the Vernon and Ansley Fields located in Jackson Parish, Louisiana, or the Vernon Acquisition, and to repay certain outstanding indebtedness.

The
7.0% Preferred Stock is convertible into shares of our common stock at an initial conversion price of $19.00 per share, subject to anti-dilution adjustments, which
equates to each share of 7.0% Preferred Stock being initially convertible into approximately 526.3 shares of our common stock, subject to adjustment for fractional shares. The Hybrid Preferred Stock
was not initially convertible into shares of our common stock. Under applicable New York Stock Exchange, or NYSE, rules, shareholder approval is required to issue common stock, or securities
convertible into or exercisable for common stock, if (i) such common stock has, or will have upon issuance, 20.0% or more of the voting power outstanding before the issuance, (ii) the
number of shares of common stock to be issued is, or will be upon issuance, equal to 20.0% or more of the number of shares of common stock outstanding before the issuance, (iii) such common
stock, or securities convertible into or exercisable for common stock, will be issued to a director, officer or substantial security holder of the Company and such securities exceed either a threshold
of one percent or, if issued to a substantial security holder who is not a director or officer at a price that is not less than the book and market value of the common stock, five percent of the
number of shares of common stock or the voting power outstanding before the issuance or (iv) such issuance will result in a change of control of the Company.

As
a result of the NYSE rules, limited time period to fund the Vernon Acquisition and the time required to organize a special meeting of shareholders, we issued 39,008 shares of 7.0%
Preferred Stock and 160,992 shares of Hybrid Preferred Stock.

We
agreed with the preferred stock investors to seek the shareholder approval required by the NYSE, or NYSE Shareholder Approval, to transform the terms of the Hybrid Preferred Stock
into the same terms as the 7.0% Preferred Stock. On August 30, 2007, NYSE Shareholder Approval was obtained and the designations, preferences, limitations and relative voting rights of the
Series A-1 Hybrid Preferred Stock and Series A-2 Hybrid Preferred Stock became identical to the designations, preferences, limitations and relative voting rights
of the Series A-1 7.0% Preferred Stock and the Series A-2 7.0% Preferred Stock, respectively, including the right to receive dividends at an annual rate of 7.0%
and the right to convert into shares of our common stock at an initial conversion price of $19.00 per share, subject to anti-dilution adjustments.

Principal terms of the preferred stock

The following summarizes the principal terms of the 7.0% Preferred Stock and the Hybrid Preferred Stock. This discussion is not complete and is qualified in its
entirety by, and should be read in conjunction with, the Statements of Designation establishing each series of the 7.0% Preferred Stock and the Hybrid Preferred Stock, which are filed as exhibits to
our Current Report on Form 8-K dated March 28, 2007 and filed with the SEC on April 2, 2007.

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Series A-1 7.0% Preferred Stock

The
Series A-1 7.0% Preferred Stock has an initial liquidation preference equal to $10,000 per share and is convertible into common stock at a price of $19.00 per
share, as may be adjusted in accordance with the terms of the Series A-1 7.0% Preferred Stock. We may force the conversion of the Series A-1 7.0% Preferred Stock
at any time if the common stock trades for 20 days within a period of 30 consecutive days at a price (i) above 175% of the then effective conversion price ($33.25 per share at the
current conversion price of $19.00 per share) at any time during the 24 months after issuance, (ii) above 150% of the then effective conversion price ($28.50 per share at the current
conversion price of $19.00 per share) thereafter through the 48th month after issuance and (iii) above 125% of the then effective conversion price ($23.75 per share at the
current conversion price of $19.00 per share) at any time thereafter. Cash dividends will accrue at the rate of 7.0% per annum prior to March 30, 2013 and at the rate of 9.0% per annum
thereafter. In lieu of
paying cash dividends, we may, under certain circumstances prior to March 30, 2013, pay dividends at a rate of 9.0% per annum by adding the dividends to the liquidation preference of the shares
of Series A-1 7.0% Preferred Stock. Upon the occurrence of a change of control, holders of the Series A-1 7.0% Preferred Stock may require us to repurchase their
shares for cash at the liquidation preference plus accumulated dividends. Holders of the Series A-1 7.0% Preferred Stock have the right to vote with the holders of common stock, the
holders of other series of 7.0% Preferred Stock and the holders of Hybrid Preferred Stock, together as a single class, on all matters submitted to our shareholders (except the election of directors)
on an as-converted basis. Holders of Series A-1 7.0% Preferred Stock, Series B 7.0% Preferred Stock, Series C 7.0% Preferred Stock and
Series A-1 Hybrid Preferred Stock have the right to separately elect up to four directors, subject to the rights of the holders of Series B 7.0% Preferred Stock and
Series C 7.0% Preferred Stock to vote as separate classes to each elect one of such preferred directors. In addition, upon the occurrence of specified defaults in the Statements of Designation
for the 7.0% Preferred Stock and the Hybrid Preferred Stock, the holders of the 7.0% Preferred Stock and Hybrid Preferred Stock, voting together as a class, have the right to elect four additional
directors, or Default Directors, until such default is cured.

Series B 7.0% Preferred Stock

The
Series B 7.0% Preferred Stock has substantially the same rights as the Series A-1 7.0% Preferred Stock, except that the holders of Series B 7.0%
Preferred Stock have the right to designate one of the preferred directors and do not have registration rights under the 7.0% Registration Rights Agreement. The Series B 7.0% Preferred Stock is
convertible into Series A-1 7.0% Preferred Stock at any time at the election of the holder and will automatically convert into Series A-1 7.0% Preferred Stock
when such holder ceases to own an aggregate of 10,000 shares of Series B 7.0% Preferred Stock and/or Hybrid Preferred Stock.

Series C 7.0% Preferred Stock

The
Series C 7.0% Preferred Stock has substantially the same rights as the Series A-1 7.0% Preferred Stock, except that the holders of Series C 7.0%
Preferred Stock have the right to designate one of the preferred directors and do not have any registration rights under the 7.0% Registration Rights Agreement. The Series C 7.0% Preferred
Stock is convertible into Series A-1 7.0% Preferred Stock at any time at the election of the holder and will automatically convert into Series A-1 7.0% Preferred
Stock when such holder ceases to own an aggregate of 10,000 shares of Series C 7.0% Preferred Stock and/or Hybrid Preferred Stock.

Series A-1 Hybrid Preferred Stock

Since
NYSE Shareholder Approval was obtained on August 30, 2007, the designations, preferences, limitations and relative voting rights of the Series A-1 Hybrid
Preferred Stock became

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identical
to the designations, preferences, limitations and relative voting rights of the Series A-1 7.0% Preferred Stock, including the right to dividends and the right to convert
into our common stock.

7.0% Preferred Stock Registration Rights Agreement

In connection with the Private Placement, we entered into the 7.0% Registration Rights Agreement with the Preferred Stock investors. The 7.0% Registration Rights
Agreement contemplates the registration of the resale of the shares of common stock underlying the 7.0% Preferred Stock and the Hybrid Preferred Stock. The 7.0% Registration Rights Agreement contains
customary terms and conditions for a transaction of this type. We agreed to file with the SEC, not later than September 26, 2007, a registration statement to register the offer and sale of the
common shares issuable upon conversion of the 7.0% Preferred Stock and the Hybrid Preferred Stock and to use our best efforts to have the registration statement declared effective by March 24,
2008. On September 5, 2007, we filed an automatically effective registration statement on Form S-3 with the SEC to register for resale the shares of common stock issuable
upon conversion of the Series A-1 Hybrid Preferred Stock and the Series A-1 7.0% Preferred Stock. If any shares of 7.0% Preferred Stock or Hybrid Preferred are
outstanding on March 30, 2011, we agreed to file a registration statement with the SEC by June 28, 2011 registering such shares for resale and to use our best efforts to have such
registration statement declared effective by September 26, 2011. If we are unable to meet the deadlines described above, if a registration statement ceases to remain effective or if we restrict
sales under a registration statement under certain "blackout provisions" for longer than the contractually permitted period, we must pay liquidated damages at a rate of 0.5% per annum of the
liquidation preference applicable to the 7.0% Preferred Stock and the Hybrid Preferred Stock for the first 90 days and thereafter for each subsequent 90-day period at an additional
rate of 0.25% up to a maximum of 2.0% per annum during any default period. We also agreed to indemnify holders against certain liabilities under the Securities Act in respect of any such resale
registration.

Hybrid Preferred Stock Registration Rights Agreement

In connection with the Private Placement, we entered into a registration rights agreement, or Hybrid Registration Rights Agreement, with the Hybrid Preferred
Stock investors. The Hybrid Registration Rights Agreement contemplates the registration of the resale of the shares of Series A-1
Hybrid Preferred Stock. If NYSE Shareholder Approval had not been obtained by September 26, 2007, we would have been required to file a registration statement with the SEC by
December 24, 2007, covering the resale prior to such shareholder approval of shares of Hybrid Preferred Stock and to use our best efforts to have the registration statement declared effective
by March 24, 2008. The Hybrid Registration Rights Agreement and the obligation of the parties thereunder terminated on August 30, 2007 because NYSE Shareholder Approval was obtained.

Vernon Acquisition

On March 30, 2007, EPOP completed the purchase of substantially all of the oil and natural gas properties and related assets, including derivative
financial instruments, covering a significant portion of estimated production for 2007, 2008 and 2009 from entities affiliated with Anadarko in the Vernon and Ansley fields located in Jackson Parish,
Louisiana for approximately $1.5 billion in cash, net of final purchase price adjustments. The Vernon Acquisition was funded by a $1.75 billion capital contribution from EXCO to EPOP.
The capital contribution consisted of $1.67 billion in cash and application of an $80.0 million deposit paid by EXCO to Anadarko in December 2006.

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The
allocation of the purchase price to the assets and liabilities of the Vernon Acquisition is presented in the following table (in thousands):

Purchase price calculation:Purchase price

$
1,520,183Acquisition related expenses


1,755Total purchase price

$
1,521,938Allocation of purchase price:Oil and natural gas propertiesproved

$
1,417,823Oil and natural gas propertiesunproved


58,192Gas gathering and related facilities


119,409Other liabilities, net


(2,745
)Fair value (liability) of assumed derivative financial instruments


(60,015
)Asset retirement obligations


(10,726
)Total purchase price allocation

$
1,521,938


Amended and restated credit agreement of EPOP

Concurrent with the Vernon Acquisition, EPOP entered into an Amended and Restated Credit Agreement, or the EPOP Credit Agreement, among EPOP, as borrower, certain
subsidiaries of EPOP, as guarantors, and certain lenders. The initial interest rate was London Inter Bank Offered Rate, or LIBOR, plus 150 basis points with a maximum rate of LIBOR plus 175 basis
points. The material changes reflected in the EPOP Credit Agreement included an increase in the borrowing base from $750.0 million to $1.3 billion, principally to reflect the assets
acquired in the Vernon Acquisition. EPOP used a portion of the increased borrowing capacity and the remaining cash from EXCO's capital contribution to repay $668.7 million of an existing EPOP
term loan, or the Senior Term Credit Facility, which included principal of $650.0 million, accrued interest of $5.7 million and a prepayment premium of $13.0 million. Upon
consummation of the Vernon Acquisition and repayment of the Senior Term Credit Facility, approximately $1.1 billion was outstanding under the EPOP Credit Agreement.

Southern Gas Acquisition

On May 2, 2007, we completed the purchase of oil and natural gas properties and related assets, including derivative financial instruments, covering a
significant portion of estimated production for 2007, 2008 and 2009, from entities affiliated with Anadarko in multiple fields primarily located in Oklahoma, Texas and Louisiana for approximately
$761.1 million in cash, including acquisition related expenses, net of preliminary purchase price adjustments, or the Southern Gas Acquisition. The acquisition was funded with cash on hand of
$145.2 million, including $133.0 million from escrow accounts from prior sales, borrowings under the EXCO Resources Credit Agreement of $572.9 million and the application of a
$43.0 million deposit paid by EXCO to Anadarko in February 2007. The purchase price allocation will be finalized when purchase price adjustments are agreed to with Anadarko.

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The
allocation of the preliminary purchase price to the assets and liabilities of the Southern Gas Acquisition is presented in the following table (in thousands):

Purchase price calculation:Preliminary purchase price

$
759,100Acquisition related expenses


2,040Total purchase price

$
761,140Allocation of purchase price:Oil and natural gas propertiesproved

$
577,852Oil and natural gas propertiesunproved


4,743Gulf Coast Sale


235,477Other, net


(2,161
)Fair value (liability) of assumed derivative financial instruments


(42,204
)Asset retirement obligations


(12,567
)Total purchase price allocation

$
761,140


On
May 2, 2007, in connection with the Southern Gas Acquisition, EXCO entered into the Second Amended and Restated Credit Agreement, or the EXCO Resources Credit Agreement, among
EXCO, as borrower, certain subsidiaries of EXCO, as guarantors, and a group of lenders. As a result of the Southern Gas Acquisition, EXCO and the lenders agreed to increase the borrowing base from
$750.0 million to $1.0 billion.

Gulf Coast Sale

On May 8, 2007, we completed the sale of a portion of the oil and natural gas properties and related assets in multiple fields primarily located in South
Texas and South Louisiana acquired in the Southern Gas Acquisition to an entity affiliated with Crimson Exploration Inc., or Crimson, for an aggregate sale price of $235.5 million in
cash, net of preliminary purchase price adjustments, and 750,000 shares of unregistered restricted Crimson common stock, or the Gulf Coast Sale. In connection with the closing of the Gulf Coast Sale,
the borrowing base on the EXCO Resources Credit Agreement was reduced from $1.0 billion to $900.0 million.

On
August 15, 2007, we sold the 750,000 shares of unregistered restricted common stock of Crimson for an aggregate sales price of approximately $5.2 million. We recorded a
gain of $0.7 million on the sale, which is included in other income for the year ended December 31, 2007.

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Pro forma results of operations

The following table reflects the unaudited pro forma results of operations as though the acquisitions of TXOK, PGMT, Winchester, the Private Placement, the Vernon
Acquisition, the Southern Gas Acquisition and the Gulf Coast Sale had occurred on January 1, 2006.

|(in thousands, except per share data)              |  | Year ended
December 31, 2006 |           | Year ended
December 31, 2007 |  
|-------------------------------------------------- |  | ---------------------------- | --------- | ---------------------------- | -
|Revenues and other income                          |  | $                            | 1,430,863 |                              | $
|                                                   |  |                              |           |                              |  
|Net income                                         |  |                              | 335,129   |                              |  
|Preferred stock dividends                          |  |                              | (140,000  | )                            |  
|                                                   |  |                              |           |                              |  
|Net income (loss) available to common shareholders |  | $                            | 195,129   |                              | $
|                                                   |  |                              |           |                              |  
|Basic earnings (loss) per share                    |  | $                            | 2.02      |                              | $
|                                                   |  |                              |           |                              |  
|Diluted earnings (loss) per share                  |  | $                            | 1.65      |                              | $
|                                                   |  |                              |           |                              |  

The
following table reflects the unaudited pro forma results of operations as though our significant 2006 acquisitions of TXOK, PGMT and Winchester had occurred at the beginning of each
respective period.

|(in thousands except per share data, unaudited) |  | For the 275 day
period from
January 1, 2005
to
October 2, 2005 |          | For the 90 day
period from
October 3, 2005
to
December 31, 2005
|----------------------------------------------- |  | -------------------------------------------------------------- | -------- | ---------------------------------------------------------------
|Revenues and other income                       |  | $                                                              | 177,774  |                                                                
|Income (loss) from continuing operations        |  |                                                                | (133,545 | )                                                              
|Net income (loss)                               |  |                                                                | (87,333  | )                                                              
|Basic earnings (loss) per share                 |  | $                                                              | (0.84    | )                                                              
|Diluted earnings (loss) per share               |  | $                                                              | (0.84    | )                                                              

5.     Other acquisitions and dispositions

Transactions other than TXOK, PGMT and Winchester that occurred during 2006

In April and May 2006, we acquired producing properties and undeveloped acreage in West Texas and the Cotton Valley trend in East Texas in two separate
acquisitions. The aggregate purchase price of these assets was $135.8 million, after contractual adjustments, which was funded with indebtedness drawn under our credit agreement.

In
August and September 2006, we closed two acquisitions of producing properties and acreage for an aggregate purchase price of $76.9 million, after contractual adjustments,
adding properties and acreage in our Appalachia and Rockies areas. We paid $27.5 million for properties located in Wyoming.

For
the year ended December 31, 2006, property and other asset sales totaled $5.8 million.

Transactions other than the Vernon Acquisition, the Southern Gas Acquisition and Gulf Coast Sale that occurred during 2007

On January 5, 2007, we completed the sale of oil and natural gas properties and undeveloped drilling locations in the Wattenberg Field area of the DJ
Basin, or the Wattenberg Field, for approximately $130.9 million in cash, net of contractual adjustments. The transaction included substantially all of the assets EXCO held in the area.
Proceeds from the sale were deposited with a

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third
party intermediary pending closing of the Southern Gas Acquisition to facilitate a like-kind exchange for federal income tax purposes.

On
July 13, 2007, we completed the sale of substantially all of our interest in the Cement Field, located in Caddo and Grady Counties Oklahoma, in our Mid-Continent
area for approximately $99.7 million, after contractual purchase price adjustments. Proceeds from this sale were deposited with a third party intermediary pending closing of assets purchased in
West Texas in October 2007.

No
gain or loss was recognized from these sales since we use the full cost method of accounting as the sales do not represent a significant divestiture as defined in full cost accounting
rules.

On
October 9, 2007, we closed the acquisition of an additional 45% interest in 28,000 acres of leasehold interests and 135 producing wells in our Canyon Sand field in West Texas
for $155.0 million from private sellers.

6.     Derivative financial instruments

The following table sets forth our oil and natural gas derivatives as of December 31, 2007. The fair values at December 31, 2007 are estimated by us
and represent the amount that we would expect to receive or pay to terminate the contracts at December 31, 2007. We have the right to offset amounts we expect to receive or pay among our
individual counterparties. As a result, we have offset amounts for financial statement presentation purposes.

(in thousands, except prices)

Volume Mmbtus/Bbls

Weighted average strike price per Mmbtu/Bbl

Fair value at December 31, 2007Natural Gas:Swaps:2008

99,870

$
8.36

$
53,9932009

80,455


7.94


(43,826
)2010

29,798


7.79


(20,794
)2011

1,825


4.51


(5,923
)2012

1,830


4.51


(5,834
)2013

1,825


4.51


(5,618
)Total Natural Gas

215,603





(28,002
)Oil:Swaps:2008

1,425


68.22


(34,667
)2009

850


60.09


(22,295
)2010

108


59.85


(2,424
)Total Oil

2,383





(59,386
)Total Oil and Natural Gas






$
(87,388
)


At
December 31, 2007, the average forward NYMEX oil prices per Bbl for calendar 2008 and 2009 were $93.11 and $87.96, respectively, and the average forward NYMEX natural gas
prices per Mmbtu for calendar 2008 and 2009 were $7.81 and $8.52, respectively.

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7.     Long-term debt

December 31,(in thousands)2006

2007Short-term debt:Current portion of long-term debt

$
6,500

$
Long term debt:EXCO Credit Agreement

$
339,000

$
560,500EPOP Credit Agreement


643,500


1,083,000EPOP Senior Term Credit Agreement


643,500


Unamortized discount on EPOP Senior Term Credit Agreement


(3,180
)

71/4% senior notes due 2011


444,720


444,720Unamortized premium on 71/4% senior notes due 2011


14,113


10,951Total

$
2,081,653

$
2,099,171


Credit agreements

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement has a borrowing base of $900.0 million. The borrowing base is redetermined semi-annually with EXCO and the
lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are on March 1 and September 1 of each year beginning on
September 1, 2007. The facility matures on March 30, 2012. The interest rate ranges from LIBOR plus 100 bps to plus 175 bps depending upon borrowing base usage. The facility also
includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 0 bps to ABR plus 75 bps depending upon borrowing base usage. Borrowings under the EXCO Resources Credit Agreement
are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO has also agreed to have in place commodity derivative contracts covering no more
than 80% of its "forecasted production from total Proved Reserves" (as defined) for the next two years and 70% in the third, fourth and fifth years. EXCO shall have in place mortgages covering 80% of
the Engineered Value of its Borrowing Base Properties (as defined). The foregoing description is not complete and is qualified in its entirety by the EXCO Resources Credit Agreement. As of
December 31, 2007, EXCO was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:



At
December 31, 2007, the six month LIBOR rate was 4.6%, which would result in an interest rate of approximately 5.8%, on any new indebtedness we may incur under the EXCO
Resources Credit Agreement. At December 31, 2007, we had $560.5 million of outstanding indebtedness under the EXCO Resources Credit Agreement.

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EPOP Credit Agreement

The EPOP Credit Agreement has a borrowing base of $1.3 billion. The borrowing base is scheduled to be redetermined on a semi-annual basis, with
EPOP and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each
year, beginning October 1, 2007. The EPOP Credit Agreement is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP's subsidiaries, and is guaranteed by
all existing and future subsidiaries of EPOP. EPOP has agreed to have in place derivative financial instruments covering no more than 80.0% of the "forecasted production from total Proved Reserves"
(as defined) for the next two years and 70.0% of the forecasted production from total Proved Reserves in the third, fourth and fifth years. The foregoing description is not complete and is qualified
in its entirety by the EPOP Credit Agreement. As of December 31, 2007, EPOP was in compliance with the financial covenants contained the EPOP Credit Agreement, which require that EPOP:



The
EPOP Credit Agreement contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Credit Agreement matures
March 30, 2012. Interest under the EPOP Credit Agreement ranges from LIBOR plus 100 basis points, or bps, to 175 bps or an ABR, as defined, ranging from ABR plus 0 bps to ABR plus 75 bps.

At
December 31, 2007, the six month LIBOR rate was 4.6%, which would result in an interest rate of approximately 6.1% on any new indebtedness we may incur under the EPOP Credit
Agreement. At December 31, 2007, we had approximately $1.1 billion of outstanding indebtedness under the EPOP Credit Agreement.

EPOP Senior Term Credit Agreement

In connection with the Winchester Acquisition, EPOP entered into the EPOP Senior Term Credit Agreement dated October 2, 2006 (as amended and restated as of
October 13, 2006). On March 30, 2007, in connection with the $1.75 billion capital contribution from EXCO and the amendments to the EPOP Credit Agreement, the EPOP Senior Term
Credit Agreement was paid in full. Total costs to retire the debt was $668.7 million consisting of $650.0 million of principal, $5.7 million of accrued interest and
$13.0 million representing a 2.0% redemption premium pursuant to terms of the EPOP Senior Term Credit Agreement. The $13.0 million redemption premium is reported as a component of
interest expense in the consolidated statement of operations for the year ended December 31, 2007. Unamortized deferred financing costs and unamortized original issue discount of
$12.2 million associated with the EPOP Senior Term Credit Agreement and $6.9 million of bank fees associated with a commitment letter arrangement entered into to ensure sufficient
financing to complete acquisitions from Anadarko were also written off and reported as a component of interest expense as a result of the retirement of this debt.

71/4% senior notes due January 15, 2011

As of December 31, 2007, $444.7 million in principal was outstanding on our 71/4% senior notes due January 15, 2011, or senior
notes. Unamortized premium on the senior notes at December 31,

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2007
was $11.0 million. The estimated fair value of the senior notes, based on quoted market prices for the senior notes, was $426.9 million on December 31, 2007.

Interest
is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011. We
may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the senior notes.

The
indenture governing the senior notes contains covenants, which limit our ability and the ability of our subsidiaries to:



8.     Environmental regulation

Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the
environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable
future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being
changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.

9.     Commitments and contingencies

We lease our offices and certain equipment. Our rental expenses were approximately $0.6 million, $0.2 million, $1.7 million and
$8.8 million for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the years
ended December 31, 2006 and 2007, respectively. Our future minimum rental payments under operating leases

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with
remaining noncancellable lease terms at December 31, 2007, are as follows (in thousands). The table excludes month-to-month rental expenses on compressors:

Amount2008

$
4,1722009


3,7112010


3,3072011


2,6772012


2,286Thereafter


878Total

$
17,031


We
regularly enter into agreements with contract drilling companies which commit us to utilize, or to pay for if not utilized, drilling rigs. As of December 31, 2007, the minimum
amount that we are obligated to pay under these contracts is $39.4 million.

On
October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styledPRC Holdings, LLC,
et al. v. North Coast Energy, Inc.and was filed in the Circuit Court of Roane County, West Virginia. This action has been removed to the United States District Court
for the Southern District of West Virginia. The action has been brought by certain landowners and lessors in West Virginia for themselves and on behalf of other similarly situated landowners and
lessors in West Virginia. The lawsuit alleges that North Coast Energy, Inc. has not been paying royalties to the plaintiffs in the manner required under the applicable leases, has provided
misleading documentation
to the plaintiffs regarding the royalties due, and has breached various other contractual, statutory and fiduciary duties to the plaintiffs with regard to the payment of royalties. In a case styled The Estate of Garrison
Tawney v. Columbia Natural Resources, LLCannounced in June 2006, the West Virginia Supreme Court held that language such
as "at the wellhead" and similar language contained in leases when used in describing how to calculate royalties due lessors was ambiguous and, therefore, should be construed strictly against the
lessee. Accordingly, in the absence of express language in a lease that is intended to allocate between a lessor and lessee post-production costs such as the costs of marketing the product
and transporting it to the point of sale, no post-production costs may be deducted from the lessor's royalty payment due from the lessee. The claims alleged by the plaintiffs in the
lawsuit filed against us are similar to the claims alleged in theTawneycase. Plaintiffs are seeking common law and statutory compensatory and punitive
damages, interest and costs and other remedies. We are vigorously defending the existing lawsuit. The action is in a very preliminary stage. The preliminary status of the lawsuit leaves the ultimate
outcome of this litigation uncertain. We believe that we have substantial defenses to this lawsuit and that the adverse affects from this litigation, if any, are reflected in our financial statements
and we do not expect the ultimate outcome of the lawsuit to have a material effect on our financial position, results of operations or cash flows.

In
the ordinary course of business, we are periodically a party to lawsuits. 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.

10.   Employee benefit plans

At December 31, 2007, we sponsored two 401(k) plans for our U.S. employees and match up to 100% of employee contributions based on years of service with
us. Our matching contributions of $0.4 million, $0.1 million, $1.1 million and $2.6 million for the 275 day period from January 1, 2005 to October 2,
2005, for the 90 day period from October 3, 2005 to December 31, 2005 and for the years ended December 31, 2006 and 2007, respectively, have been included as general and
administrative expense.

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11.   Bonus retention program

We established a bonus retention program in 2003 to provide an incentive for the employee stockholders to remain employed with the company and its subsidiaries.
The program provided for equal quarterly payments to the employee stockholders totaling $1.8 million on an annual basis.

The
payments to employee stockholders were to continue for four years unless the employee stockholder voluntarily terminated employment or was dismissed for cause, at which time the
payments would cease. On February 10, 2005, in conjunction with the sale of our Canadian subsidiary, the Canadian subsidiary's employee bonus retention plan was terminated and all bonus
retention amounts payable, aggregating approximately $1.0 million, were accelerated and paid in full pursuant to the terms of the plan. This amount has been included in the loss from operations
of discontinued operations during the 275 day period from January 1, 2005 to October 2, 2005. The Equity Buyout on October 3, 2005 constituted a change of control as
defined in the agreement. As a result, the employee bonus retention plan was terminated resulting in an additional charge of $2.6 million. Accordingly, all bonus retention amounts payable,
aggregating approximately $2.8 million, were accelerated and paid in full pursuant to the terms of the plan. As a result, we have included this amount in general and administrative expense
related to this program during the 275 day period from January 1, 2005 to October 2, 2005.

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12.   Earnings per share

The following table presents basic and diluted earnings (loss) per share for 275 day period from January 1, 2005 to October 2, 2005, the
90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007 (in thousands, except per share amounts):

|                                   |                                                                           | Predecessor |   | Successor |  
|---------------------------------- | ------------------------------------------------------------------------- | ----------- | - | --------- | -
|
|Basic earnings per share:          |                                                                           |             |   |           |  
|                                   | Income (loss) from continuing operations available to common shareholders |             | $ | (137,216  | )
|                                   | Income from discontinued operations                                       |             |   | 122,032   |  
|                                   |                                                                           |             |   |           |  
|                                   | Net income available to common shareholders                               |             | $ | (15,184   | )
|                                   |                                                                           |             |   |           |  
|Shares:                            |                                                                           |             |   |           |  
|                                   | Weighted average number of common shares outstanding                      |             |   | 116,504   |  
|                                   |                                                                           |             |   |           |  
|Basic earnings (loss) per share:   |                                                                           |             |   |           |  
|                                   | Continuing operations                                                     |             | $ | (1.18     | )
|                                   | Discontinued operations                                                   |             |   | 1.05      |  
|                                   |                                                                           |             |   |           |  
|                                   | Total basic earnings per share                                            |             | $ | (0.13     | )
|                                   |                                                                           |             |   |           |  
|Diluted earnings per share:        |                                                                           |             |   |           |  
|                                   | Income (loss) from continuing operations available to common shareholders |             | $ | (137,216  | )
|                                   | Income from discontinued operations                                       |             |   | 122,032   |  
|                                   |                                                                           |             |   |           |  
|                                   | Net income available to common shareholders                               |             | $ | (15,184   | )
|                                   |                                                                           |             |   |           |  
|Shares:                            |                                                                           |             |   |           |  
|                                   | Weighted average number of common shares outstanding                      |             |   | 116,504   |  
|                                   | Dilutive effect of stock options                                          |             |   |          |  
|                                   |                                                                           |             |   |           |  
|                                   | Weighted average common shares and common stock equivalents               |             |   | 116,504   |  
|                                   |                                                                           |             |   |           |  
|Diluted earnings (loss) per share: |                                                                           |             |   |           |  
|                                   | Continuing operations                                                     |             | $ | (1.18     | )
|                                   | Discontinued operations                                                   |             |   | 1.05      |  
|                                   |                                                                           |             |   |           |  
|                                   | Total diluted earnings per share                                          |             | $ | (0.13     | )
|                                   |                                                                           |             |   |           |  

As
a result of the loss from continuing operations for the 275 day period from January 1, 2005 to October 2, 2005 and the year ended December 31, 2007, the
potential common stock equivalents from the assumed conversion of stock options of 8,801,351 and 2,619,522, respectively, have been excluded from the diluted EPS calculation. Also excluded from the
2007 diluted earnings per share are 105,263,158 shares of common stock from the assumed conversion of the 7.0% Preferred Stock and Hybrid Preferred Stock as their effect is antidilutive. For financial
accounting purposes, the Class B shares of Holdings for the 275 day period from January 1, 2005 to October 2, 2005, were considered to

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be
a "variable" plan since a holder of the shares had to be employed at the date of a change in control to receive fair value for the Class B shares. As a result, the Class B shares have
been excluded from per share calculations as required under SFAS No. 128.

13.   Stock transactions

Stock options

All of the issued and outstanding EXCO Holdings stock options as of October 3, 2005 were purchased as a part of the Equity Buyout transaction. This
resulted in a charge of $17.8 million to general and administrative expense during the 275 day period from January 1, 2005 to October 2, 2005.

We
adopted SFAS No. 123(R) on October 3, 2005. As required by SFAS No. 123(R), the granting of options to our employees under the 2005 Long-Term
Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in
capital.

The
2005 Incentive Plan provides for the granting of options to purchase up to 20,000,000 shares of EXCO's common stock. The options expire ten years following the date of grant and have
a weighted average remaining life of 8.79 years. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries
of the date of the grant. We generally grant incentive stock options.

On
August 30, 2007, shareholder approval was obtained to increase the number of shares authorized to be issued under the 2005 Incentive Plan by an additional 10,000,000 shares to
a total of 20,000,000 shares. Therefore, as of December 31, 2006 and 2007, there were 1,574,475 and 7,022,375 shares available to be granted under the 2005 Incentive Plan, respectively.

The
following table summarizes stock option activity related to our employees under the 2005 Incentive Plan:

|                                         |             | Stock options |           | Weighted average exercise price per share |       | Weighted average remaining terms (in years) |      | Aggregate intrinsic value
(in thousands)
|---------------------------------------- | ----------- | ------------- | --------- | ----------------------------------------- | ----- | ------------------------------------------- | ---- | ----------------------------------------
|Options outstanding at October 3, 2005   |             |              |           | $                                         |      |                                             |      |                                         
|                                         | Granted     |               | 4,992,650 |                                           |       | 7.50                                        |      |                                         
|                                         | Forfeitures |               | 19,575    |                                           |       | 7.50                                        |      |                                         
|                                         | Exercised   |               |          |                                           |       |                                            |      |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         
|Options outstanding at December 31, 2005 |             | 4,973,075     |           |                                           | 7.50  |                                             |      |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         
|                                         | Granted     |               | 3,615,700 |                                           |       | 14.02                                       |      |                                         
|                                         | Forfeitures |               | 163,250   |                                           |       | 8.83                                        |      |                                         
|                                         | Exercised   |               | 158,152   |                                           |       | 7.97                                        |      |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         
|Options outstanding at December 31, 2006 |             | 8,267,373     |           |                                           | 10.32 |                                             |      |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         
|                                         | Granted     |               | 4,951,700 |                                           |       | 14.94                                       |      |                                         
|                                         | Forfeitures |               | 399,600   |                                           |       | 13.83                                       |      |                                         
|                                         | Exercised   |               | 416,700   |                                           |       | 9.99                                        |      |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         
|Options outstanding at December 31, 2007 |             | 12,402,773    |           | $                                         | 12.06 |                                             | 8.79 |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         
|Options exercisable at December 31, 2007 |             | 5,993,786     |           | $                                         | 10.71 |                                             | 8.42 |                                         
|                                         |             |               |           |                                           |       |                                             |      |                                         

The
weighted average grant date fair value of stock options granted during the years 2005, 2006 and 2007 were $2.29, $4.75 and $5.43, respectively. The total intrinsic value of stock
options exercised

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for
the 90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007 was $0, $0.9 million and $2.9 million,
respectively.

The
following summarizes the status of the nonvested stock options as of December 31, 2007 and changes for the year ended December 31, 2007:

Number of shares

Weighted average grant date fair valueNonvested at January 1, 2007

5,087,899

$
3.59Granted

4,951,700


5.43Forfeitures

(399,600
)

4.72Vested

(3,231,012
)

4.08Nonvested at December 31, 2007

6,408,987

$
4.65


The
fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. Options are granted at the fair market value of the common stock on
the date of grant. The following assumptions were used for the options included in the above table:

|                         |  | 2005    |   | 2006         |   | 2007         |  
|------------------------ |  | ------- | - | ------------ | - | ------------ | -
|Expected life            |  | 4 years |   | 4 years      |   | 46 years    |  
|Risk-free rate of return |  | 4.22    | % | 4.22%5.13   | % | 3.28%4.97   | %
|Volatility               |  | 30.40   | % | 30.40%35.58 | % | 35.67%37.72 | %
|Dividend yield           |  | 0       | % | 0            | % | 0            | %

As
required by SFAS No. 123(R), the granting of options under the 2005 Incentive Plan to our employees are share-based payment transactions and are to be treated as compensation
expense by us with a corresponding increase to additional paid-in capital. Expected life was determined based on exercise history, as well as five comparable public companies.
Risk-free rate of return is a rate of a similar term U.S. Treasury zero coupon bond. Volatility was determined based on the weighted average of historical volatility of our common stock
and the daily closing prices from five comparable public companies. Total share-based compensation for the 90 day period from October 1, 2005 to December 31, 2005 and the years
ended December 31, 2006 and 2007 was $3.2 million, $7.9 million and $15.0 million, of which $2.2 million, $6.5 million and $12.6 million is included in
general and administrative and lease operating expense and $1.0 million, $1.4 million and $2.4 million was capitalized as part of proved developed and undeveloped oil and natural
gas properties, respectively, as discussed in "Note 2. Summary of significant accounting policies." The total tax benefit for the 90 day period from October 3, 2005 to
December 31, 2005 and the years ended December 31, 2006 and 2007 was $0.2 million, $0.9 million and $1.1 million, respectively. Total share-based compensation to be
recognized on unvested awards is $24.2 million over a weighted average period of 1.45 years as of December 31, 2007.

The
Class B common stock issued in July 2003 was considered to be a "variable" plan for financial reporting purposes. As a result, we recognized a non-cash charge of
approximately $44.1 million during the 275 day period from January 1, 2005 to October 2, 2005 related to the Class B common stock.

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14.   Income taxes

The income tax provision attributable to our income (loss) before income taxes consists of the following:

|          |      | Predecessor                         |  | Successor |        
|--------- | ---- | ----------------------------------- |  | --------- | -------
|
|Current:  |      |                                     |  |           |        
|          | U.S. |                                     |  |           |        
|          |      | Federal                             |  | $         | (3,563 
|          |      | State                               |  |           | (668   
|          |      |                                     |  |           |        
|          |      | Total current income tax (benefit)  |  |           | (4,231 
|          |      |                                     |  |           |        
|Deferred: |      |                                     |  |           |        
|          | U.S. |                                     |  |           |        
|          |      | Federal                             |  |           | (49,881
|          |      | State                               |  |           | (9,586 
|          |      | Canadian                            |  |           |       
|          |      |                                     |  |           |        
|          |      | Total deferred income tax (benefit) |  |           | (59,467
|          |      |                                     |  |           |        
|          |      | Total income tax (benefit)          |  | $         | (63,698
|          |      |                                     |  |           |        

We
have net operating loss carryforwards, or NOLs, for United States income tax purposes that have either been generated from our operations or were purchased in our acquisitions. Our
ability to use the purchased NOLs has been restricted by Section 382 of the Internal Revenue Code due to ownership changes which occurred on December 19, 1997 and July 29, 2003,
the change in ownership of Rio Grande, Inc. which occurred on March 16, 1999, as well as the Equity Buyout, which occurred on October 3, 2005. In addition, we experienced another
change in control on August 30, 2007 based upon the transformation of the Hybrid Preferred Stock to the same terms as the 7.0% Preferred Stock, but the result is no limitation on current year
net operating losses. We estimate that approximately $8.5 million of the NOLs limited by Section 382 will expire prior to their utilization. Expiration is expected to occur from 2007
through 2016. Our NOL available for utilization at December 31, 2007 is approximately $29.0 million.

On
February 9, 2005, we repatriated Cdn. $74.5 million ($59.6 million) in an extraordinary dividend from our Canadian subsidiary. We recognized a tax liability of
$8.2 million as of December 31, 2004 related to the extraordinary dividend. As a result of certain technical advice issued by the U.S. Treasury
Department, we reduced the tax liability by $2.1 million during the second quarter of 2005. EXCO Resources filed amended quarterly reports on Form 10-Q/A that included
restated financial statements for the quarters ended June 30, 2005 and September 30, 2005 to reflect the tax benefit in the earlier quarter and to classify the benefit as a component of
continuing rather than discontinued operations in the September 30, 2005 quarter. This additional tax benefit is recognized as a component of taxes from continuing operations pursuant to SFAS
No. 109, "Accounting for Income Taxes," or SFAS No. 109, and EITF 93-13, "Effect of a Retroactive Change in Enacted Tax Rates that is Included in Income from
Continuing Operations,", or EITF 93-13, which require that a tax effect of a change in enacted rates be allocated to continuing operations without regard to whether the item giving
rise to the effect is a component of discontinued operations.

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Deferred
income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used
for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:

December 31,(in thousands)2006

2007Current deferred tax assets (liabilities):Basis difference in fair value of derivative financial instruments

$
(32,639
)
$
6,764Other





Total current deferred tax assets (liabilities)


(32,639
)

6,764Long-term deferred tax assets:Net operating loss and AMT credits carryforwardsU.S


48,654


11,642Basis difference in fair value of derivative financial instruments


32,684


53,099Purchase accounting adjustment to bond premium


9,511


9,233Share-based compensation


1,234


2,257Foreign tax credits carryforwards





9,336Other


118


30Total long-term deferred tax assets


92,201


85,597Valuation allowance





(9,336
)Net total long-term deferred tax assets


92,201


76,261Long-term deferred tax liabilities:Book basis of oil and natural gas properties in excess of tax basisU.S


(258,337
)

(347,659
)Taxes on undistributed earnings of foreign subsidiaryU.S





Total deferred liabilities


(258,337
)

(347,659
)Net noncurrent deferred tax liabilities

$
(166,136
)
$
(271,398
)


A
reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the
275 day period from

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January 1,
2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the years ended December 31, 2006 and 2007 is presented in
the following table:

|                                                                      |                                                     | Predecessor |         | Successor
|--------------------------------------------------------------------- | --------------------------------------------------- | ----------- | ------- | ---------
|
|United States federal income taxes (benefit) at statutory rate of 35% |                                                     | $           | (70,293 | )        
|Increases (reductions) resulting from:                                |                                                     |             |         |          
|                                                                      | Foreign tax items                                   |             |         | 644      
|                                                                      | Change in U.S. tax law related to Canadian dividend |             |         | (2,075   
|                                                                      | Adjustments to the valuation allowance              |             |         |         
|                                                                      | Non-deductible compensation                         |             |         | 15,432   
|                                                                      | State taxes net of federal benefit                  |             |         | (6,665   
|                                                                      | State tax rate change                               |             |         |         
|                                                                      | Other                                               |             |         | (741     
|                                                                      |                                                     |             |         |          
|                                                                      | Total income tax provision                          |             | $       | (63,698  
|                                                                      |                                                     |             |         |          

During
2007, our income tax rate was impacted by the substitution of a current federal net operating loss carryback for previously claimed foreign tax credits resulting from the 2005
sale of our Canadian subsidiary. The impact, net of a federal refund of $6.1 million, was an $11.0 million non-cash expense, principally related to foreign tax credits which
are required since we no longer have any foreign operations.

Also,
as a result of our 2007 acquisitions, our state effective rate increased which required us to change the rate in which we record our deferred tax assets and liabilities. This
amount was recognized in our 2007 income tax expense as a current period expense and is presented as part of the Other line item in the above table.

15.   Related party transactions

TXOK acquisition

On February 14, 2006, TXOK became our wholly-owned subsidiary and the accounts under the related party arrangements were settled. Also on this date, in
connection with our IPO, EXCO advanced TXOK $158.8 million to redeem its preferred stock and TXOK became our wholly-owned subsidiary. The TXOK preferred stock had full voting rights to vote
with the TXOK common stock on all matters submitted to a vote by stockholders. Accordingly, holders of the TXOK preferred stock held voting control of TXOK prior to the February 14, 2006
redemption. If the TXOK preferred stock was not redeemed on or before September 27, 2006, the TXOK preferred stock and accumulated dividends would have automatically converted into common stock
representing 90% of the outstanding common
stock of TXOK. We used the equity method of accounting for our investment in TXOK until February 14, 2006, when TXOK became a wholly-owned subsidiary.

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Corporate use of personal aircraft

We periodically charter, for company business, a jet aircraft from DHM Aviation, LLC, a company owned by Douglas H. Miller, our chairman and chief
executive officer. The Board of Directors has adopted a written policy covering the use of this aircraft. The Company believes that prudent use of a chartered private airplane by our senior management
while on company business can promote efficient use of management time. Such usage can allow for unfettered, confidential communications among management during the course of the flight and minimize
airport commuting and waiting time, thereby promoting maximum use of management time for company business. However, we restrict the use of the aircraft to priority company business being conducted by
senior management in a manner that is cost effective for us and our shareholders. As a result, EXCO's reimbursed use of the aircraft is restricted to company business. Such use must be approved in
advance by our President and our Chief Financial Officer. We maintain a detailed written log of such usage specifying the company personnel (and others, if any) that fly on the aircraft, the travel
dates and destination(s), and the company business being conducted. In addition, the log contains a detail of all charges paid or reimbursed by us with supporting written documentation.

In
the event the aircraft is chartered for a mixture of company business and personal use, all charges will be reasonably allocated between company reimbursed charges and charges to the
person using the aircraft for personal use.

At
least annually, and more frequently if requested by the Audit Committee, our Director of Internal Audit surveys fixed base operators and other charter operators located at Dallas Love
Field, Dallas, Texas to ascertain hourly flight rates for aircraft of comparable size and equipment in relation to the aircraft. This survey also ascertains other charges (including fuel surcharges)
invoiced by such charter operators as well as out-of-pocket reimbursement policies. Such survey is supplied to the Audit Committee in order for the Audit Committee to establish
an hourly rate and other charges EXCO shall pay for the upcoming calendar year for the use of the aircraft. The present hourly rate paid by EXCO to DHM Aviation, LLC is in line with the market
rate for similar aircraft.

During
2007, DHM Aviation, LLC purchased a larger used jet aircraft. Based upon a national survey of corporate aircraft charter rates, in August 2007, the Board of Directors
approved a rate of $5,700 per flight hour plus $600 per flight hour fuel surcharge for the new aircraft.

During
2007, we reimbursed DHM Aviation, LLC at a rate of $3,600 per hour, including fuel surcharges, for use of the aircraft and $5,700 per flight hour plus $600 per flight hour
fuel surcharge for use of the new aircraft. For the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to
December 31, 2005, we paid DHM Aviation, LLC $0.3 million and $0.1 million, respectively. Payments to DHM Aviation, LLC for the year ended December 31, 2006
and 2007 were $0.4 million and $0.5 million, respectively, for use of the aircraft.

Suite

The Company maintains a suite at the American Airlines Center in Dallas, Texas. During 2006 the Company shared the suite with and was reimbursed for 50% of its
expenses relative to the suite by an entity affiliated with Boone Pickens, one of our directors, pursuant to an arrangement entered into in 2006 between the Company and such entity. During the year
ended December 31, 2006, the Company paid a total of $350,000 to maintain the suite, of which $175,000 was reimbursed by the entity affiliated with Mr. Pickens. During 2007, this
arrangement was terminated and EXCO paid 100% of the costs associated with the American Airlines Center, which totaled $350,000.

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Private Placement of Preferred Stock

On March 30, 2007, we completed the Private Placement of an aggregate of $390.0 million of 7.0% Preferred Stock and $1.61 billion of Hybrid
Preferred Stock to accredited investors pursuant to the terms and conditions of a Preferred Stock Purchase Agreement dated March 28, 2007. The following related persons participated in the
transaction:



In
connection with the Private Placement, we entered into a letter agreement, dated March 28, 2007, with Oaktree pursuant to which we agreed to cause an individual designated by
Oaktree to be nominated to serve on our Board of Directors following such time as (i) Oaktree ceases to have the right to elect a director to serve on our Board of Directors pursuant to the
Statement of Designation for the Series B 7.0% Preferred Stock and (ii) less than 25% of the shares of 7.0% Preferred Stock and Hybrid Preferred Stock originally issued on
March 30, 2007 remain outstanding, and for so long as Oaktree owns at least 10,000,000 shares of our common stock (including, for this purpose, shares of common stock into which any Preferred
Stock then held by Oaktree is convertible).

In
connection with the Private Placement, we also entered into a letter agreement, dated March 28, 2007, with certain investors affiliated with Ares pursuant to which we agreed to
cause an individual designated by Ares to be nominated to serve on our Board of Directors following such time as (i) Ares ceases to have the right to elect a director to serve on our Board of
Directors pursuant to the Statement of Designation for the Series C 7.0% Preferred Stock and (ii) less than 25% of the shares of 7.0% Preferred Stock and Hybrid Preferred Stock
originally issued on March 30, 2007 remain

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outstanding,
for so long as Ares owns at least 10,000,000 shares of our common stock (including, for this purpose, shares of common stock into which any Preferred Stock then held by Ares is
convertible).

For
more information about the Private Placement, see "Note 4. Significant TransactionsPrivate Placement of Preferred Stock".

Gulf Coast Sale

On May 8, 2007, we completed the sale of a portion of the oil and natural gas properties and related assets in multiple fields primarily located in South
Texas and South Louisiana acquired in the Southern Gas Acquisition to an entity affiliated with Crimson, for an aggregate sale price of $235.5 million in cash, net of preliminary purchase price
adjustments, and 750,000 shares of unregistered restricted Crimson common stock, or the Gulf Coast Sale. The purchase price was negotiated on an arm's-length basis based upon customary industry
metrics for acquisitions of oil and natural gas reserves. The purchase agreement for the Gulf Coast Sale contained customary representations, warranties and covenants. Crimson is a
publicly-held company that is controlled by investment funds managed by Oaktree. At the time of the Gulf Coast Sale, one of our directors, Vincent J. Cebula was a managing director of
Oaktree. Rajath Shourie, a managing director of Oaktree, began serving on our Board of Directors on August 30, 2007. B. James Ford, a managing director of Oaktree and a member of Crimson's
board of directors, began serving on our Board of Directors on December 1, 2007.

On
August 15, 2007, we entered into an agreement with funds managed by Oaktree to sell our 750,000 shares of Crimson's unregistered restricted common stock for an aggregate sales
price of approximately $5.2 million.

Other

Robert Stillwell, Jr., the son of Robert L. Stillwell, one of our directors, was employed by us from October 2002 until July 2005 as a financial analyst. In
connection with the Equity Buyout in 2005, Robert Stillwell, Jr. received a payment of $71,187 for certain options granted to him as compensation
for his employment with us and a payment of $41,064 under the Employee Stock Participation Plan. These payments were in addition to the prorated annualized salary of $45,000 that Robert Stillwell, Jr.
received during the period of his employment in 2005.

Penny
Wilson, the spouse of Mark E. Wilson, our Vice President, Chief Accounting Officer and Controller, was retained by us from February 2007 to January 2008 as a consultant, through an
independent consulting firm to perform accounting work related to our 2007 acquisitions. In addition to Ms. Wilson's base salary, she also received approximately $19,000 in bonus and
commissions from the consulting firm, which were directly tied to her engagement at EXCO. During 2007, fees paid to the consulting firm for Ms. Wilson and other consultants totaled
approximately $0.6 million.

16.   Concentration of credit risk

For the twelve months ended December 31, 2007, sales to a regulated natural gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, and an
independent oil and natural gas company, Anadarko and its affiliates, accounted for 20.0% and 12.1%, respectively, of total oil and natural gas revenues. For the twelve months ended
December 31, 2006 and 2005 sales to one industrial customer, Alcan Rolled ProductsRavenswood, LLC, accounted for 4.9% and 10.1%, respectively, of total oil and natural gas
revenues. If we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser's
service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser.

123

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17.   Geographic operating segment information and oil and natural gas disclosures

We follow SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information," or SFAS No. 131. We have operations in only one
industry segment, that being the oil and natural gas exploration and production industry.

18.   Subsequent events



On January 10, 2008, we announced the withdrawal of our registration statement related to our proposed master limited partnership. As such, approximately
$3.5 to $4.5 million in registration costs, $3.4 of which was deferred in 2007, will be expensed in the first quarter of 2008.



In January 2008, we entered into financial risk management instruments to mitigate our exposure to fluctuations in interest rates on $700.0 million in
principal through February 14, 2010 at LIBOR rates ranging from 2.45% to 2.8%.



Subsequent to December 31, 2007, we entered into additional derivative financial instruments covering 28,021 Mmbtu of natural gas and
731 Bbls of oil at weighted average prices of $8.79 per Mmbtu and $91.18 per Bbl, respectively.



On February 20, 2008, EXCO acquired shallow natural gas properties from EOG Resources, Inc. located primarily in EXCO's central Pennsylvania
operating area. The purchase price was $395.0 million. After reduction for preliminary closing adjustments of $7.4 million, the net purchase price paid on February 20, 2008 was
$387.6 and was financed with borrowings under the EXCO Resources Credit Agreement.

EXCO Resources Credit Agreement

In conjunction with the Appalachian acquisition on February 20, 2008, we amended and restated our EXCO Resources Credit Agreement. Our borrowing base was
increased from $900 million to $1.2 billion. All other terms remained unchanged. At February 20, 2008, our outstanding balance was $920.5 million.

124

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19.   Quarterly financial data (unaudited)

The following are summarized quarterly financial data for the years ended December 31, 2006 and 2007:

|     |                                                    | Quarter |  
|---- | -------------------------------------------------- | ------- | -
|
|
|2006 |                                                    |         |  
|     | Total revenues and other income                    |         | $
|     | Operating income (loss)                            |         |  
|     | Net income (loss) available to common shareholders |         | $
|     | Basic earnings (loss) per share:                   |         |  
|     | Net income (loss)                                  |         | $
|     | Diluted earnings (loss) per share:                 |         |  
|     | Net income (loss)                                  |         | $
|2007 |                                                    |         |  
|     | Total revenues and other income                    |         | $
|     | Operating income (loss)                            |         |  
|     | Net income (loss) available to common shareholders |         | $
|     | Basic earnings (loss) per share:                   |         |  
|     | Net income (loss)                                  |         | $
|     | Diluted earnings (loss) per share:                 |         |  
|     | Net income (loss)                                  |         | $

20.   Consolidating financial statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The senior
notes are jointly and severally guaranteed by some of our subsidiaries in the United States (referred to as 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. In 2007, certain subsidiaries, previously guarantor subsidiaries, were merged into and with
Resources.

In
connection with the 2007 mergers discussed above, the consolidating balance sheet as of December 31, 2006 and the consolidating statements of operations and consolidating
statements of cash flows for the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005 and
for the year ended December 31, 2006 have been restated to reflect the guarantor subsidiaries as if they had been part of Resources for all periods presented. We have also presented the 2007
consolidating financial statements to reflect these changes as if it was in place at the beginning of the year.

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



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

125

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EXCO Resources, Inc.  Consolidating balance sheet  December 31, 2006

|(in thousands)                                                  |  | Resources |           | Guarantor subsidiaries |   | Non-guarantor subsidiaries |   | Eliminations |           | Consolidated |  
|--------------------------------------------------------------- |  | --------- | --------- | ---------------------- | - | -------------------------- | - | ------------ | --------- | ------------ | -
|Assets                                                          |  |           |           |                        |   |                            |   |              |           |              |  
|Current assets:                                                 |  |           |           |                        |   |                            |   |              |           |              |  
|Cash and cash equivalents                                       |  | $         | 6,522     |                        | $ | 6,233                      |   | $            | 10,067    |              | $
|Other current assets                                            |  |           | 44,050    |                        |   | 36,484                     |   |              | 133,354   |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Total current assets                                            |  |           | 50,572    |                        |   | 42,717                     |   |              | 143,421   |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Oil and natural gas properties (full cost accounting method):   |  |           |           |                        |   |                            |   |              |           |              |  
|Unproved oil and natural gas properties                         |  |           | 88,299    |                        |   | 19,921                     |   |              | 189,699   |              |  
|Proved developed and undeveloped oil and natural gas properties |  |           | 607,892   |                        |   | 818,427                    |   |              | 1,066,544 |              |  
|Allowance for depreciation, depletion and amortization          |  |           | (43,863   | )                      |   | (43,260                    | ) |              | (55,468   | )            |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Oil and natural gas properties, net                             |  |           | 652,328   |                        |   | 795,088                    |   |              | 1,200,775 |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Gas gathering, office and field equipment, net                  |  |           | 5,911     |                        |   | 33,367                     |   |              | 174,883   |              |  
|Deferred financing costs                                        |  |           | 946       |                        |   |                           |   |              | 14,983    |              |  
|Oil and natural gas derivatives                                 |  |           | 4,950     |                        |   | 6,440                      |   |              | 30,079    |              |  
|Goodwill                                                        |  |           | 110,800   |                        |   | 164,469                    |   |              | 194,808   |              |  
|Investments in and advances to affiliates                       |  |           | 1,167,846 |                        |   | (465,797                   | ) |              |          |              |  
|Advance on probable acquisition                                 |  |           | 80,000    |                        |   |                           |   |              |          |              |  
|Other assets, net                                               |  |           | 17        |                        |   | 471                        |   |              | 32        |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Total assets                                                    |  | $         | 2,073,370 |                        | $ | 576,755                    |   | $            | 1,758,981 |              | $
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Liabilities and shareholders' equity                            |  |           |           |                        |   |                            |   |              |           |              |  
|Current liabilities                                             |  | $         | 66,859    |                        | $ | 25,098                     |   | $            | 98,967    |              | $
|Long-term debt                                                  |  |           | 797,832   |                        |   |                           |   |              | 1,283,821 |              |  
|Deferred income taxes                                           |  |           | 11,147    |                        |   | 154,989                    |   |              |          |              |  
|Other liabilities                                               |  |           | 17,682    |                        |   | 60,116                     |   |              | 10,696    |              |  
|Payable to parent                                               |  |           |          |                        |   |                           |   |              | 16,385    |              |  
|Commitments and contingencies                                   |  |           |          |                        |   |                           |   |              |          |              |  
|Shareholders' equity                                            |  |           | 1,179,850 |                        |   | 336,552                    |   |              | 349,112   |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Total liabilities and shareholders' equity                      |  | $         | 2,073,370 |                        | $ | 576,755                    |   | $            | 1,758,981 |              | $
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  

126

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EXCO Resources, Inc.    Consolidating balance sheet    December 31, 2007

|(in thousands)                                                  |  | Resources |           | Guarantor subsidiaries |   | Non-guarantor subsidiaries |   | Eliminations |           | Consolidated |  
|--------------------------------------------------------------- |  | --------- | --------- | ---------------------- | - | -------------------------- | - | ------------ | --------- | ------------ | -
|Assets                                                          |  |           |           |                        |   |                            |   |              |           |              |  
|Current assets:                                                 |  |           |           |                        |   |                            |   |              |           |              |  
|Cash and cash equivalents                                       |  | $         | 23,069    |                        | $ | 7,250                      |   | $            | 25,191    |              | $
|Other current assets                                            |  |           | 76,261    |                        |   | 31,601                     |   |              | 147,928   |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Total current assets                                            |  |           | 99,330    |                        |   | 38,851                     |   |              | 173,119   |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Oil and natural gas properties (full cost accounting method):   |  |           |           |                        |   |                            |   |              |           |              |  
|Unproved oil and natural gas properties                         |  |           | 92,680    |                        |   | 17,142                     |   |              | 224,981   |              |  
|Proved developed and undeveloped oil and natural gas properties |  |           | 1,192,337 |                        |   | 899,745                    |   |              | 2,833,971 |              |  
|Allowance for depreciation, depletion and amortization          |  |           | (112,548  | )                      |   | (84,288                    | ) |              | (303,657  | )            |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Oil and natural gas properties, net                             |  |           | 1,172,469 |                        |   | 832,599                    |   |              | 2,755,295 |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Gas gathering, office and field equipment, net                  |  |           | 7,449     |                        |   | 32,665                     |   |              | 305,294   |              |  
|Advance on pending acquisition                                  |  |           | 39,500    |                        |   |                           |   |              |          |              |  
|Deferred financing costs                                        |  |           | 7,619     |                        |   |                           |   |              | 12,787    |              |  
|Oil and natural gas derivatives                                 |  |           | 851       |                        |   |                           |   |              | 1,640     |              |  
|Goodwill                                                        |  |           | 110,800   |                        |   | 164,469                    |   |              | 194,808   |              |  
|Investments in and advances to affiliates                       |  |           | 2,525,487 |                        |   |                           |   |              |          |              |  
|Other assets, net                                               |  |           |          |                        |   | 668                        |   |              | 5,558     |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Total assets                                                    |  | $         | 3,963,505 |                        | $ | 1,069,252                  |   | $            | 3,448,501 |              | $
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Liabilities and shareholders' equity                            |  |           |           |                        |   |                            |   |              |           |              |  
|Current liabilities                                             |  | $         | 118,522   |                        | $ | 35,959                     |   | $            | 123,686   |              | $
|Long-term debt                                                  |  |           | 1,016,171 |                        |   |                           |   |              | 1,083,000 |              |  
|Deferred income taxes                                           |  |           | 105,531   |                        |   | 165,867                    |   |              |          |              |  
|Other liabilities                                               |  |           | 77,189    |                        |   | 67,197                     |   |              | 54,629    |              |  
|Payable to parent                                               |  |           | (461,928  | )                      |   | 468,607                    |   |              | (6,679    | )            |  
|Commitments and contingencies                                   |  |           |          |                        |   |                           |   |              |          |              |  
|Preferred stock                                                 |  |           | 1,992,278 |                        |   |                           |   |              |          |              |  
|Shareholders' equity                                            |  |           | 1,115,742 |                        |   | 331,622                    |   |              | 2,193,865 |              |  
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  
|Total liabilities and shareholders' equity                      |  | $         | 3,963,505 |                        | $ | 1,069,252                  |   | $            | 3,448,501 |              | $
|                                                                |  |           |           |                        |   |                            |   |              |           |              |  

127

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EXCO Resources, Inc.  Consolidating statement of operations  For the 275 day period ended October 2, 2005

|(in thousands)                                        |                                            | Resources |          | Guarantor
subsidiaries |   | Non-
guarantor
subsidiaries |   | Eliminations |        | Consolidated |  
|----------------------------------------------------- | ------------------------------------------ | --------- | -------- | ---------------------- | - | --------------------------- | - | ------------ | ------ | ------------ | -
|Revenues:                                             |                                            |           |          |                        |   |                             |   |              |        |              |  
|Oil and natural gas sales                             |                                            | $         | 41,222   |                        | $ | 77,644                      |   | $            | 13,955 |              | $
|Derivative financial instruments                      |                                            |           | (56,706  | )                      |   | (120,547                    | ) |              |       |              |  
|Other income (loss)                                   |                                            |           | 32,012   |                        |   | 1,269                       |   |              | 141    |              |  
|Equity in earnings of subsidiaries                    |                                            |           | (59,838  | )                      |   |                            |   |              |       |              |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Total revenues                                        |                                            |           | (43,310  | )                      |   | (41,634                     | ) |              | 14,096 |              |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Costs and expenses:                                   |                                            |           |          |                        |   |                             |   |              |        |              |  
|Oil and natural gas production                        |                                            |           | 9,010    |                        |   | 10,750                      |   |              | 2,397  |              |  
|Depreciation, depletion and amortization              |                                            |           | 5,888    |                        |   | 13,332                      |   |              | 5,467  |              |  
|Accretion of discount on asset retirement obligations |                                            |           | 263      |                        |   | 340                         |   |              | 14     |              |  
|General and administrative                            |                                            |           | 76,680   |                        |   | 10,124                      |   |              | 2,638  |              |  
|Interest                                              |                                            |           | 26,675   |                        |   | 26,326                      |   |              |       |              |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Total costs and expenses                              |                                            |           | 118,516  |                        |   | 60,872                      |   |              | 10,516 |              |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Income (loss) before income taxes                     |                                            |           | (161,826 | )                      |   | (102,506                    | ) |              | 3,580  |              |  
|Income tax benefit                                    |                                            |           | (21,538  | )                      |   | (42,160                     | ) |              |       |              |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Income (loss) before discontinued operations          |                                            |           | (140,288 | )                      |   | (60,346                     | ) |              | 3,580  |              |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Discontinued operations:                              |                                            |           |          |                        |   |                             |   |              |        |              |  
|Loss from operations                                  |                                            |           |         |                        |   |                            |   |              | (4,403 | )            |  
|                                                      | Gain on disposition of Addison Energy Inc. |           |          | 175,717                |   |                             |  |              |        |             |  
|                                                      | Income tax (benefit) expense               |           |          | 50,613                 |   |                             |  |              |        | (1,331       | )
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Income (loss) from discontinued operations            |                                            |           | 125,104  |                        |   |                            |   |              | (3,072 | )            |  
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  
|Net income (loss)                                     |                                            | $         | (15,184  | )                      | $ | (60,346                     | ) | $            | 508    |              | $
|                                                      |                                            |           |          |                        |   |                             |   |              |        |              |  

128

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EXCO Resources, Inc.  Consolidating statement of operations  For the 90 day period ended December 31, 2005

|(in thousands)                                        |  | Resources |        | Guarantor
subsidiaries |   | Non-
guarantor
subsidiaries |   | Eliminations |       | Consolidated |  
|----------------------------------------------------- |  | --------- | ------ | ---------------------- | - | --------------------------- | - | ------------ | ----- | ------------ | -
|Revenues:                                             |  |           |        |                        |   |                             |   |              |       |              |  
|Oil and natural gas sales                             |  | $         | 14,885 |                        | $ | 46,790                      |   | $            | 8,386 |              | $
|Derivative financial instruments                      |  |           | 2,856  |                        |   | (3,112                      | ) |              |      |              |  
|Other income (loss)                                   |  |           | 7,821  |                        |   | 516                         |   |              | 112   |              |  
|Equity earnings of subsidiaries                       |  |           | 17,444 |                        |   |                            |   |              |      |              |  
|                                                      |  |           |        |                        |   |                             |   |              |       |              |  
|Total revenues                                        |  |           | 43,006 |                        |   | 44,194                      |   |              | 8,498 |              |  
|                                                      |  |           |        |                        |   |                             |   |              |       |              |  
|Costs and expenses:                                   |  |           |        |                        |   |                             |   |              |       |              |  
|Oil and natural gas production                        |  |           | 3,312  |                        |   | 4,380                       |   |              | 1,257 |              |  
|Depreciation, depletion and amortization              |  |           | 3,110  |                        |   | 8,382                       |   |              | 2,579 |              |  
|Accretion of discount on asset retirement obligations |  |           | 75     |                        |   | 142                         |   |              | 9     |              |  
|General and administrative                            |  |           | 3,942  |                        |   | 1,387                       |   |              | 1,046 |              |  
|Interest                                              |  |           | 19,414 |                        |   | 6,075                       |   |              |      |              |  
|                                                      |  |           |        |                        |   |                             |   |              |       |              |  
|Total costs and expenses                              |  |           | 29,853 |                        |   | 20,366                      |   |              | 4,891 |              |  
|                                                      |  |           |        |                        |   |                             |   |              |       |              |  
|Income (loss) before income taxes                     |  |           | 13,153 |                        |   | 23,828                      |   |              | 3,607 |              |  
|Income tax expense (benefit)                          |  |           | (3,197 | )                      |   | 10,828                      |   |              |      |              |  
|                                                      |  |           |        |                        |   |                             |   |              |       |              |  
|Net income (loss)                                     |  | $         | 16,350 |                        | $ | 13,000                      |   | $            | 3,607 |              | $
|                                                      |  |           |        |                        |   |                             |   |              |       |              |  

129

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EXCO Resources, Inc.  Consolidating statement of operations  For the year ended December 31, 2006

|(in thousands)                                        |  | Resources |         | Guarantor subsidiaries |   | Non-guarantor subsidiaries |  | Eliminations |        | Consolidated
|----------------------------------------------------- |  | --------- | ------- | ---------------------- | - | -------------------------- |  | ------------ | ------ | ------------
|Revenues:                                             |  |           |         |                        |   |                            |  |              |        |             
|Oil and natural gas sales                             |  | $         | 174,507 |                        | $ | 121,787                    |  | $            | 59,486 |             
|Commodity price risk management activities            |  |           | 84,349  |                        |   | 88,768                     |  |              | 25,547 |             
|Other income (loss)                                   |  |           | 30,909  |                        |   | 1,755                      |  |              | 948    |             
|Equity in earnings of subsidiaries                    |  |           | 73,153  |                        |   |                           |  |              |       |             
|                                                      |  |           |         |                        |   |                            |  |              |        |             
|Total revenues                                        |  |           | 362,918 |                        |   | 212,310                    |  |              | 85,981 |             
|                                                      |  |           |         |                        |   |                            |  |              |        |             
|Costs and expenses:                                   |  |           |         |                        |   |                            |  |              |        |             
|Oil and natural gas production                        |  |           | 33,391  |                        |   | 20,590                     |  |              | 14,893 |             
|Depreciation, depletion and amortization              |  |           | 67,122  |                        |   | 38,241                     |  |              | 30,359 |             
|Accretion of discount on asset retirement obligations |  |           | 854     |                        |   | 941                        |  |              | 219    |             
|General and administrative                            |  |           | 25,176  |                        |   | 11,121                     |  |              | 4,909  |             
|Interest                                              |  |           | 53,246  |                        |   | 28,607                     |  |              | 31,625 |             
|                                                      |  |           |         |                        |   |                            |  |              |        |             
|Total costs and expenses                              |  |           | 179,789 |                        |   | 99,500                     |  |              | 82,005 |             
|                                                      |  |           |         |                        |   |                            |  |              |        |             
|Income before income taxes                            |  |           | 183,129 |                        |   | 112,810                    |  |              | 3,976  |             
|Income tax expense                                    |  |           | 44,175  |                        |   | 45,226                     |  |              |       |             
|                                                      |  |           |         |                        |   |                            |  |              |        |             
|Income (loss) from operations                         |  | $         | 138,954 |                        | $ | 67,584                     |  | $            | 3,976  |             
|                                                      |  |           |         |                        |   |                            |  |              |        |             

130

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EXCO Resources, Inc.  Consolidating statement of operations  For the year ended December 31, 2007

|(in thousands)                                        |  | Resources |          | Guarantor subsidiaries |   | Non-guarantor subsidiaries |   | Eliminations |         | Consolidated |  
|----------------------------------------------------- |  | --------- | -------- | ---------------------- | - | -------------------------- | - | ------------ | ------- | ------------ | -
|Revenues and other income:                            |  |           |          |                        |   |                            |   |              |         |              |  
|Oil and natural gas sales                             |  | $         | 224,238  |                        | $ | 121,994                    |   | $            | 499,828 |              | $
|Derivative financial instruments                      |  |           | (25,788  | )                      |   | (8,612                     | ) |              | 61,207  |              |  
|Other income (loss)                                   |  |           | 35,572   |                        |   | (27,177                    | ) |              | 25,248  |              |  
|Equity in earnings of subsidiaries                    |  |           | 89,823   |                        |   |                           |   |              |        |              |  
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  
|Total revenues and other income                       |  |           | 323,845  |                        |   | 86,205                     |   |              | 586,283 |              |  
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  
|Costs and expenses:                                   |  |           |          |                        |   |                            |   |              |         |              |  
|Oil and natural gas production                        |  |           | 50,755   |                        |   | 26,279                     |   |              | 93,406  |              |  
|Depreciation, depletion and amortization              |  |           | 70,767   |                        |   | 44,427                     |   |              | 260,226 |              |  
|Accretion of discount on asset retirement obligations |  |           | 1,512    |                        |   | 1,946                      |   |              | 1,420   |              |  
|General and administrative                            |  |           | 36,040   |                        |   | 10,962                     |   |              | 17,668  |              |  
|Interest                                              |  |           | 62,540   |                        |   |                           |   |              | 118,810 |              |  
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  
|Total costs and expenses                              |  |           | 221,614  |                        |   | 83,614                     |   |              | 491,530 |              |  
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  
|Income before income taxes                            |  |           | 102,231  |                        |   | 2,591                      |   |              | 94,753  |              |  
|Income tax expense                                    |  |           | 52,575   |                        |   | 7,521                      |   |              |        |              |  
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  
|Net income (loss)                                     |  |           | 49,656   |                        |   | (4,930                     | ) |              | 94,753  |              |  
|Preferred stock dividends                             |  |           | (132,968 | )                      |   |                           |   |              |        |              |  
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  
|Net income (loss) available to common shareholders    |  | $         | (83,312  | )                      | $ | (4,930                     | ) | $            | 94,753  |              | $
|                                                      |  |           |          |                        |   |                            |   |              |         |              |  

131

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EXCO Resources, Inc.  Consolidating statement of cash flow  For the 275 day period ended October 2, 2005

|(in thousands)                                                               |  | Resources |          | Guarantor Subsidiaries |   | Non-
Guarantor Subsidiaries |   | Eliminations |         | Consolidated |  
|---------------------------------------------------------------------------- |  | --------- | -------- | ---------------------- | - | --------------------------- | - | ------------ | ------- | ------------ | -
|Operating Activities:                                                        |  |           |          |                        |   |                             |   |              |         |              |  
|Net cash used in operating activities                                        |  | $         | (55,614  | )                      | $ | (13,621                     | ) | $            | (11,887 | )            | $
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  
|Investing Activities:                                                        |  |           |          |                        |   |                             |   |              |         |              |  
|Additions to oil and natural gas properties, gathering systems and equipment |  |           | (6,601   | )                      |   | (101,835                    | ) |              | (42,708 | )            |  
|Proceeds from dispositions of oil and natural gas properties                 |  |           | 45,375   |                        |   | 635                         |   |              |        |              |  
|Proceeds from sale of Addison                                                |  |           | 444,812  |                        |   |                            |   |              | (1,415  | )            |  
|Advances/investments with affiliates                                         |  |           | (114,314 | )                      |   | 127,864                     |   |              | (13,550 | )            |  
|Proceeds from sales of marketable securities                                 |  |           | 59       |                        |   |                            |   |              |        |              |  
|Net cash used in investing activities of discontinued operations             |  |           |         |                        |   |                            |   |              | (442    | )            |  
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  
|Net cash provided by (used in) investing activities                          |  |           | 369,331  |                        |   | 26,664                      |   |              | (58,115 | )            |  
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  
|Financing Activities:                                                        |  |           |          |                        |   |                             |   |              |         |              |  
|Proceeds from long-term debt                                                 |  |           | 41,300   |                        |   |                            |   |              |        |              |  
|Payments on long-term debt                                                   |  |           | (148,247 | )                      |   |                            |   |              |        |              |  
|Principal and interest on notes receivable-employees                         |  |           | 311      |                        |   |                             |   |              |         |              |  
|Net cash used in financing of discontinued operations                        |  |           |         |                        |   |                            |   |              | 59,601  |              |  
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  
|Net cash provided by (used in) financing activities                          |  |           | (106,636 | )                      |   |                            |   |              | 59,601  |              |  
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  
|Net increase (decrease) in cash                                              |  |           | 207,081  |                        |   | 13,043                      |   |              | (10,401 | )            |  
|Cash at the beginning of the period                                          |  |           | 8,535    |                        |   | 7,472                       |   |              | 10,401  |              |  
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  
|Cash at end of period                                                        |  | $         | 215,616  |                        | $ | 20,515                      |   | $            |        |              | $
|                                                                             |  |           |          |                        |   |                             |   |              |         |              |  

132

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EXCO Resources, Inc.  Consolidating statement of cash flow  For the 90 day period ended December 31, 2005

|(in thousands)                                                               |  | Resources |         | Guarantor Subsidiaries |   | Non-
Guarantor Subsidiaries |   | Eliminations |        | Consolidated |  
|---------------------------------------------------------------------------- |  | --------- | ------- | ---------------------- | - | --------------------------- | - | ------------ | ------ | ------------ | -
|Operating Activities:                                                        |  |           |         |                        |   |                             |   |              |        |              |  
|Net cash provided by (used in) operating activities                          |  | $         | (13,402 | )                      | $ | 15,360                      |   | $            | 6,219  |              | $
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  
|Investing Activities:                                                        |  |           |         |                        |   |                             |   |              |        |              |  
|Investment in TXOK Acquisition, Inc.                                         |  |           | (20,000 | )                      |   |                            |   |              |       |              |  
|Additions to oil and natural gas properties, gathering systems and equipment |  |           | 126     |                        |   | (6,880                      | ) |              | (6,453 | )            |  
|Proceeds from dispositions of oil and natural gas properties                 |  |           | (395    | )                      |   | 2                           |   |              |       |              |  
|Advances/investments in affiliates                                           |  |           | 13,544  |                        |   | 6,456                       |   |              |       |              |  
|Advances from related parties                                                |  |           |        |                        |   |                            |   |              |       |              |  
|Other investing activities                                                   |  |           | 29      |                        |   |                            |   |              | 234    |              |  
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  
|Net cash provided by (used in) investing activities                          |  |           | (6,696  | )                      |   | (422                        | ) |              | (6,219 | )            |  
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  
|Financing Activities:                                                        |  |           |         |                        |   |                             |   |              |        |              |  
|Proceeds from long-term debt                                                 |  |           | 9,999   |                        |   |                            |   |              |       |              |  
|Payments on long-term debt                                                   |  |           | (15,279 | )                      |   |                            |   |              |       |              |  
|Principal and interest on notes receivableemployees                         |  |           | 1,262   |                        |   |                            |   |              |       |              |  
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  
|Net cash used in financing activities                                        |  |           | (4,018  | )                      |   |                            |   |              |       |              |  
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  
|Net increase (decrease) in cash                                              |  |           | (24,116 | )                      |   | 14,938                      |   |              |       |              |  
|Cash at the beginning of the period                                          |  |           | 215,616 |                        |   | 20,515                      |   |              |       |              |  
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  
|Cash at end of period                                                        |  | $         | 191,500 |                        | $ | 35,453                      |   | $            |       |              | $
|                                                                             |  |           |         |                        |   |                             |   |              |        |              |  

133

---



EXCO Resources, Inc.  Consolidating statement of cash flow  For the year ended December 31, 2006

|(in thousands)                                                               |                                | Resources |            | Guarantor subsidiaries |   | Non-
guarantor subsidiaries |         | Eliminations |            | Consolidated |  
|---------------------------------------------------------------------------- | ------------------------------ | --------- | ---------- | ---------------------- | - | --------------------------- | ------- | ------------ | ---------- | ------------ | -
|Operating Activities:                                                        |                                |           |            |                        |   |                             |         |              |            |              |  
|Net cash provided by operating activities                                    |                                | $         | 94,535     |                        | $ | 74,773                      |         | $            | 58,351     |              | $
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  
|Investing Activities:                                                        |                                |           |            |                        |   |                             |         |              |            |              |  
|Additions to oil and natural gas properties, gathering systems and equipment |                                |           | (146,077   | )                      |   | (111,370                    | )       |              | (176,719   | )            |  
|Proceeds from dispositions of oil and natural gas properties                 |                                |           | 4,556      |                        |   | 150                         |         |              | 1,118      |              |  
|Cash acquired in acquisition of TXOK Acquisition, Inc.                       |                                |           | 32,259     |                        |   |                            |         |              |           |              |  
|Advance to TXOK Acquisition, Inc. for preferred stock redemption             |                                |           | (158,750   | )                      |   |                            |         |              |           |              |  
|Acquisition of Power Gas Marketing & Transmission, Inc.,                     |                                |           |            |                        |   |                             |         |              |            |              |  
|                                                                             | net of cash acquired           |           |            |                       |   |                             | (61,774 | )            |            |             |  
|Acquisition of Winchester Energy Company, Ltd., net of cash acquired         |                                |           |           |                        |   |                            |         |              | (1,094,910 | )            |  
|Advances/investments with affiliates                                         |                                |           | (44,635    | )                      |   | 120,197                     |         |              | (75,562    | )            |  
|Advance payment on probable acquisition                                      |                                |           | (80,000    | )                      |   |                            |         |              |           |              |  
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  
|Net cash used in investing activities                                        |                                |           | (392,647   | )                      |   | (52,797                     | )       |              | (1,346,073 | )            |  
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  
|Financing Activities:                                                        |                                |           |            |                        |   |                             |         |              |            |              |  
|Proceeds from long-term debt                                                 |                                |           | 583,000    |                        |   |                            |         |              | 1,301,250  |              |  
|Payments on long-term debt                                                   |                                |           | (1,102,751 | )                      |   | (13,098                     | )       |              | (11,000    | )            |  
|Payments of hedges in conjunction with Power Gas Marketing &                 |                                |           |            |                        |   |                             |         |              |            |              |  
|                                                                             | Transmission, Inc. acquisition |           |            |                       |   |                             | (38,098 | )            |            |             |  
|Cash settlements of assumed derivative financial instruments                 |                                |           |           |                        |   |                            |         |              |           |              |  
|Proceeds from issuance of common stock, net                                  |                                |           | 657,381    |                        |   |                            |         |              |           |              |  
|Deferred financing costs and other                                           |                                |           | (1,117     | )                      |   |                            |         |              | (15,840    | )            |  
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  
|Net cash provided by (used in) financing activities                          |                                |           | 136,513    |                        |   | (51,196                     | )       |              | 1,274,410  |              |  
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  
|Net decrease in cash                                                         |                                |           | (161,599   | )                      |   | (29,220                     | )       |              | (13,312    | )            |  
|Cash at the beginning of the period                                          |                                |           | 168,121    |                        |   | 35,453                      |         |              | 23,379     |              |  
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  
|Cash at end of period                                                        |                                | $         | 6,522      |                        | $ | 6,233                       |         | $            | 10,067     |              | $
|                                                                             |                                |           |            |                        |   |                             |         |              |            |              |  

134

---



EXCO Resources, Inc.  Consolidating statement of cash flow  For the year ended December 31, 2007

|(in thousands)                                                               |  | Resources |            | Guarantor subsidiaries |   | Non-
guarantor subsidiaries |   | Eliminations |            | Consolidated |  
|---------------------------------------------------------------------------- |  | --------- | ---------- | ---------------------- | - | --------------------------- | - | ------------ | ---------- | ------------ | -
|Operating Activities:                                                        |  |           |            |                        |   |                             |   |              |            |              |  
|Net cash provided by operating activities                                    |  | $         | 141,403    |                        | $ | 69,223                      |   | $            | 367,203    |              | $
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  
|Investing Activities:                                                        |  |           |            |                        |   |                             |   |              |            |              |  
|Additions to oil and natural gas properties, gathering systems and equipment |  |           | (999,434   | )                      |   | (68,154                     | ) |              | (1,779,381 | )            |  
|Proceeds from dispositions of property and equipment                         |  |           | 485,714    |                        |   | 354                         |   |              | 4,294      |              |  
|Advance payment on probable acquisition                                      |  |           | (39,500    | )                      |   |                            |   |              |           |              |  
|Sale of Crimson stock                                                        |  |           | 5,228      |                        |   |                            |   |              |           |              |  
|Other                                                                        |  |           |           |                        |   |                            |   |              | (5,558     | )            |  
|Advances/investments with affiliates                                         |  |           | (1,648,245 | )                      |   | (406                        | ) |              | 1,648,651  |              |  
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  
|Net cash used in investing activities                                        |  |           | (2,196,237 | )                      |   | (68,206                     | ) |              | (131,994   | )            |  
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  
|Financing Activities:                                                        |  |           |            |                        |   |                             |   |              |            |              |  
|Proceeds from long-term debt                                                 |  |           | 972,500    |                        |   |                            |   |              | 1,263,000  |              |  
|Payments on long-term debt                                                   |  |           | (751,000   | )                      |   |                            |   |              | (1,470,532 | )            |  
|Settlement of derivative financial instruments with a financing element      |  |           | (11,578    | )                      |   |                            |   |              | (2,636     | )            |  
|Proceeds from issuance of common stock, net                                  |  |           | 4,162      |                        |   |                            |   |              |           |              |  
|Proceeds from issuance of preferred stock, net                               |  |           | 1,992,273  |                        |   |                            |   |              |           |              |  
|Payment of preferred stock dividend                                          |  |           | (127,134   | )                      |   |                            |   |              |           |              |  
|Deferred financing costs and other                                           |  |           | (7,850     | )                      |   |                            |   |              | (9,909     | )            |  
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  
|Net cash provided by (used in) financing activities                          |  |           | 2,071,373  |                        |   |                            |   |              | (220,077   | )            |  
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  
|Net increase in cash                                                         |  |           | 16,539     |                        |   | 1,017                       |   |              | 15,132     |              |  
|Cash at the beginning of the period                                          |  |           | 6,522      |                        |   | 6,233                       |   |              | 10,067     |              |  
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  
|Cash at end of period                                                        |  | $         | 23,061     |                        | $ | 7,250                       |   | $            | 25,199     |              | $
|                                                                             |  |           |            |                        |   |                             |   |              |            |              |  

135

---





21.   Supplemental information relating to oil and natural gas producing activities continuing operations
(unaudited)

Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities (excluding all amounts related to our
former Canadian subsidiary):

(in thousands, except per unit amounts)

AmountFor the 275 day period from January 1, 2005 to October 2, 2005:Proved property acquisition costs

$
103,222Development and exploration costs(1)


39,900Capitalized asset retirement costs


1,686Depreciation, depletion and amortization per Boe

$
8.35Depreciation, depletion and amortization per Mcfe

$
1.39For the 90 day period from October 3, 2005 to December 31, 2005:Development and exploration costs(1)

$
13,194Capitalized asset retirement costs


51Depreciation, depletion and amortization per Boe

$
14.54Depreciation, depletion and amortization per Mcfe

$
2.422006:Proved property acquisition costs(2)

$
1,384,056Unproved property acquisition costs(3)


248,330Total property acquisition costs


1,632,386Development and exploration costs(1)


194,312Lease acquisitions and other


8,991Capitalized asset retirement costs


21,681Depreciation, depletion and amortization per Boe

$
16.44Depreciation, depletion and amortization per Mcfe

$
2.742007:Proved property acquisition costs(4)

$
2,356,354Unproved property acquisition costs(5)


117,893Total property acquisition costs


2,474,247Development and exploration costs(1)


446,675Lease acquisitions and other


21,415Capitalized asset retirement costs


5,127Depreciation, depletion and amortization per Boe

$
18.57Depreciation, depletion and amortization per Mcfe

$
3.10


---

136

---



We
retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil and natural gas reserves. The estimated proved
net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory
practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include
those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.
All of our reserves are located onshore in the continental United States of America.

Discounted
future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value
should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because
of these and other considerations, any estimate of fair value is subjective and imprecise. All amounts related to our former Canadian subsidiary, have been excluded from the information contained in
this note.

Estimated Quantities of Proved Reserves

(in thousands)

Oil (Bbls)

Natural Gas (Mcf)

NGLs (Bbls)(1)

Mcfe(2)December 31, 2004

7,236

361,392

210

406,068Purchase of reserves in place

60

59,780



60,140New discoveries and extensions

349

30,834



32,928Revisions of previous estimates

11

(12,608
)
(190
)
(13,682
)Production

(491
)
(20,482
)
(20
)
(23,548
)Sales of reserves in place

(343
)
(17,886
)


(19,944
)December 31, 2005

6,822

401,030



441,962Purchase of reserves in place

8,775

723,427



776,077New discoveries and extensions

2,018

80,832



92,940Revisions of previous estimates

(487
)
(33,467
)


(36,389
)Production

(916
)
(44,123
)


(49,619
)Sales of reserves in place

(57
)
(1,097
)


(1,439
)December 31, 2006

16,155

1,126,602



1,223,532Purchase of reserves in place

10,500

770,567



833,567New discoveries and extensions(3)

2,469

178,248



193,062Revisions of previous estimates(4)

(188
)
(78,647
)


(79,775
)Production

(1,645
)
(111,419
)


(121,289
)Sales of reserves in place

(6,361
)
(145,801
)


(183,967
)December 31, 2007

20,930

1,739,550



1,865,130


Estimated Quantities of Proved Developed Reserves

(in thousands)

Oil (Bbls)

Natural Gas (Mcf)

NGLs (Bbls)(1)

Mcfe(2)December 31, 2005

5,527

321,716



354,878December 31, 2006

11,290

665,263



733,003December 31, 2007

15,180

1,228,736



1,319,816


---



137

---





Standardized measure of discounted future net cash flows

We have summarized the Standardized Measure related to our proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of Proved
Reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in
place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could
also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information
indicative of any trends.

Standardized Measure of Discounted Future Net Cash Flows

(in thousands)

AmountYear ended December 31, 2005:Future cash inflows

$
4,334,629Future production, development and abandonment costs


1,148,283Future income taxes


1,097,606Future net cash flows


2,088,740Discount of future net cash flows at 10% per annum.


1,265,441Standardized measure of discounted future net cash flows(1)

$
823,299Year ended December 31, 2006:Future cash inflows

$
7,173,640Future production, development and abandonment costs


3,397,690Future income taxes


721,154Future net cash flows


3,054,796Discount of future net cash flows at 10% per annum


1,743,021Standardized measure of discounted future net cash flows

$
1,311,775Year ended December 31, 2007:Future cash inflows

$
13,562,925Future production, development and abandonment costs


5,115,858Future income taxes


1,857,530Future net cash flows


6,589,537Discount of future net cash flows at 10% per annum


3,470,650Standardized measure of discounted future net cash flows

$
3,118,887


During
recent years, prices paid for oil and natural gas have fluctuated significantly. The spot prices at December 31, 2005, 2006 and 2007 used in the above
table, were $61.03, $60.82 and $95.92 per Bbl of
oil, respectively, and $10.08, $5.64 and $6.80 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials.

138

---



The
following are the principal sources of change in the Standardized Measure:

(in thousands)Year ended December 31, 2005:Sales and transfers of oil and natural gas produced, net of production costs

$
(171,775
)Net changes in prices and production costs


511,666Extensions and discoveries, net of future development and production costs


87,239Development costs during the period


53,094Changes in estimated future development costs


(58,997
)Revisions of previous quantity estimates


(21,895
)Sales of reserves in place


(29,363
)Purchase of reserves in place


117,572Accretion of discount before income taxes


69,849Changes in timing, foreign currency translation and other


(7,344
)Net change in income taxes


(200,484
)Net change

$
349,562Year ended December 31, 2006:Sales and transfers of oil and natural gas produced, net of production costs

$
(286,906
)Net changes in prices and production costs


(541,139
)Extensions and discoveries, net of future development and production costs


96,494Development costs during the period


194,312Changes in estimated future development costs


(140,061
)Revisions of previous quantity estimates


(108,658
)Sales of reserves in place


(4,298
)Purchase of reserves in place


991,548Accretion of discount before income taxes


124,395Changes in timing, foreign currency translation and other


23,900Net change in income taxes


138,889Net change

$
488,476Year ended December 31, 2007:Sales and transfers of oil and natural gas produced, net of production costs

$
(679,211
)Net changes in prices and production costs


513,856Extensions and discoveries, net of future development and production costs


461,961Development costs during the period


446,675Changes in estimated future development costs


(125,395
)Revisions of previous quantity estimates


(175,857
)Sales of reserves in place


(298,328
)Purchase of reserves in place


1,923,731Accretion of discount before income taxes


156,736Changes in timing and other


126,192Net change in income taxes


(543,248
)Net change

$
1,807,112


139

---





Supplemental information relating to oil and natural gas producing activitiesdiscontinued operations (unaudited)

Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities of our discontinued operations, which
relate to our former Canadian subsidiary.

(in thousands, except per unit amounts)For the 275 day period from January 1, 2005 to October 2, 2005:Property acquisition costs

$
16Development costs


272Capitalized asset retirement costs


Depreciation, depletion and amortization per Boe

$
7.49Depreciation, depletion and amortization per Mcfe

$
1.16


We
used our internal engineers for 2004 to provide annual year-end estimates of our future net recoverable oil, natural gas and NGL reserves. The estimated proved net
recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory
practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those
reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must
make a relatively major expenditure for recompletion or secondary recovery operations.

Discounted
future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value
should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because
of these and other considerations, any estimate of fair value is subjective and imprecise.



|(in thousands)    |                                 | Oil (Bbls) |        | Natural Gas
(Mcf) |          | NGLs (Bbls) |        | Mcfe(1) |         
|----------------- | ------------------------------- | ---------- | ------ | ----------------- | -------- | ----------- | ------ | ------- | --------
|December 31, 2004 |                                 | 9,339      |        | 167,172           |          | 9,502       |        | 280,218 |         
|                  | Purchase of reserves in place   |            |       |                   |         |             |       |         |        
|                  | New discoveries and extensions  |            |       |                   |         |             |       |         |        
|                  | Revisions of previous estimates |            |       |                   |         |             |       |         |        
|                  | Production                      |            | (64    | )                 | (1,142   | )           | (84    | )       | (2,030  
|                  | Sales of reserves in place      |            | (9,275 | )                 | (166,030 | )           | (9,418 | )       | (278,188
|                  |                                 |            |        |                   |          |             |        |         |         
|December 31, 2005 |                                 |           |        |                  |          |            |        |        |         
|                  |                                 |            |        |                   |          |             |        |         |         

---

Standardized measure of discounted future net cash flowsdiscontinued operations

We have summarized the Standardized Measure related to our former Canadian subsidiary's proved oil, natural gas, and NGL reserves. We have based the following
summary on a valuation of Proved Reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from
the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves
proved in prior years could also be significant.

140

---



Accordingly,
you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information
indicative of any trends.

Changes in standardized measurediscontinued operations

The following are the principal sources of change in the Standardized Measure:

(in thousands)Year ended December 31, 2005:Sales and transfers of oil and natural gas produced, net of production costs

$
(8,756
)Development costs during the period


272Accretion of discount before income taxes


2,999Changes in timing, foreign currency translation and other


(11,002
)Sales of reserves in place


(343,349
)Net change

$
(359,836
)


ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.EXCO's management, with the participation of EXCO's principal executive officer and
principal financial officer, evaluated the effectiveness of EXCO's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the
Securities Exchange Act of 1934, as amended, or Exchange Act) as of the end of the period covered by this report. Based on this evaluation, the principal executive officer and principal financial
officer have concluded that EXCO's disclosure controls and procedures were effective as of the Evaluation Date 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 Securities and Exchange Commission's rules and forms and
(ii) accumulated and communicated to EXCO's management as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control over Financial Reporting.EXCO's management is responsible for establishing and
maintaining effective internal control over financial reporting (as defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act). Even an effective
internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only
reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of an internal control system in future periods can change with conditions.

EXCO's
management assessed the effectiveness of EXCO's internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth
by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, inInternal ControlIntegrated Framework.Based on this
assessment, management believes that, as of December 31, 2007, EXCO's internal control over financial reporting is effective based on those criteria.

There
were no changes in EXCO's internal control over financial reporting that occurred during the fiscal quarter ended December 31, 2007 that have materially affected, or are
reasonably likely to materially affect, EXCO's internal control over financial reporting.

141

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ITEM 9B.    OTHER INFORMATION

None.

PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Annual Report on
Form 10-K.

ITEM 11.    EXECUTIVE COMPENSATION

The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Annual Report on
Form 10-K.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Annual Report on
Form 10-K.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Annual Report on
Form 10-K.

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Annual Report on
Form 10-K.

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1)
See Part IIItem 8. Financial Statements and Supplementary Data in this Annual Report on Form 10-K.(a)(2)
None.(a)(3)
See "Index to Exhibits" for a description of our exhibits.(b)
See "Index to Exhibits" for a description of our exhibits.(c)
None.


142

---





SIGNATURE PAGE

Pursuant to the requirements of Section 13 or 15(d) 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.

|Date: February 28, 2008 |  | EXCO RESOURCES, INC.
(Registrant)
|----------------------- |  | ---------------------------------
|                        |  | By:                              

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on
the date indicated.

|Date: February 28, 2008 |  |  | /s/DOUGLAS H. MILLERDouglas H. Miller
Director, Chairman and Chief Executive Officer       
|----------------------- |  |  | -------------------------------------------------------------------------------------------
|                        |  |  | /s/STEPHEN F. SMITHStephen F. Smith
Director, Vice Chairman and President                  
|                        |  |  | /s/J. DOUGLAS RAMSEYJ. Douglas Ramsey
Vice President, Chief Financial Officer and Treasurer
|                        |  |  | /s/MARK E. WILSONMark E. Wilson
Vice President, Chief Accounting Officer and Controller    
|                        |  |  | /s/JEFFREY D. BENJAMINJeffrey D. Benjamin
Director                                         
|                        |  |  | /s/VINCENT J. CEBULAVincent J. Cebula
Director                                             

143

---



| |  |  | /s/B. JAMES FORDB. James Ford
Director            
| |  |  | --------------------------------------------------
| |  |  | /s/ROBERT H. NIEHAUSRobert H. Niehaus
Director    
| |  |  | /s/BOONE PICKENSBoone Pickens
Director            
| |  |  | /s/JEFFREY S. SEROTAJeffrey S. Serota
Director    
| |  |  | /s/RAJATH SHOURIERajath Shourie
Director          
| |  |  | /s/ROBERT L. STILLWELLRobert L. Stillwell
Director

144

---



SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED  PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE  NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

Not applicable.

145

---





Index to Exhibits

|Exhibit Number |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                                                                                                                                                
|-------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1            |  | Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO's Current
Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.                                                                                                                                                      
|2.2            |  | First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco,
 LLC, filed as an Exhibit to EXCO's Current Report on Form 8- K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.                                                                                      
|2.3            |  | Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO's
Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.                                                                                        
|2.4            |  | Purchase and Sale Agreement by and among EXCO Resources, Inc., as Purchaser, Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation and Kerr-McGee Oil & Gas
Onshore LP, as Seller, dated February 1, 2007, filed as an Exhibit to EXCO's Annual Report on Form 10-K filed on March 19, 2007 and incorporated by reference herein.                                                                                                     
|2.5            |  | First Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement by and among Anadarko Petroleum Corporation, Anadarko Gathering Company, EXCO Partners Operating
Partnership, LP (successor by merger to Vernon Holdings, LLC) and Vernon Gathering, LLC, dated March 30, 2007, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated
by reference herein.      
|2.6            |  | First Amendment Letter Agreement by and among EXCO Resources, Inc., Southern G Holdings, LLC, Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee
Oil & Gas Onshore LP, dated April 13, 2007, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                                               
|2.7            |  | Second Amendment to Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P Company LP, Howell Petroleum Corporation, Kerr-McGee
Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                     
|2.8            |  | Third Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P
Company LP, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8,
2007 and incorporated by reference herein.

146

---



|2.9  |  | Membership Interest Purchase and Sale Agreement, dated May 8, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Crimson Exploration Inc. and Crimson Exploration Operating, Inc.,
 filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                               
|---- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.10 |  | Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search, Incorporated, as sellers, filed
as an Exhibit to EXCO's Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.                     
|2.11 |  | First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and Energy Search,
Incorporated, as sellers, filed as an exhibit to EXCO's Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.
|3.1  |  | Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 8, 2006 and filed on February 14, 2006 and
incorporated by reference herein.                                                                                                                                          
|3.2  |  | Amended and Restated Bylaws 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.                                                                                                                                                                  
|3.3  |  | Statement of Designation of Series A-1 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on
April 2, 2007 and incorporated by reference herein.                                                                                                                           
|3.4  |  | Statement of Designation of Series A-2 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on
April 2, 2007 and incorporated by reference herein.                                                                                                                           
|3.5  |  | Statement of Designation of Series B 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2,
 2007 and incorporated by reference herein.                                                                                                                            
|3.6  |  | Statement of Designation of Series C 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2,
 2007 and incorporated by reference herein.                                                                                                                            
|3.7  |  | Statement of Designation of Series A-1 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by
reference herein.                                                                                                                                                          
|3.8  |  | Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by
reference herein.                                                                                                                                                          
|4.1  |  | Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the
Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.                                                      

147

---



|4.2  |  | First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004, filed
as an Exhibit to EXCO's Registration Statement on Form S-4 filed March 25, 2004 and incorporated by reference herein.                             
|---- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.3  |  | Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed
March 31, 2005 and incorporated by reference herein.                                                                                           
|4.4  |  | Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K filed on
February 21, 2006 and incorporated by reference herein.                                                                                                 
|4.5  |  | Form of 71/4% Global Note Due 2011, filed as an Exhibit to EXCO's Pre-effective Amendment No. 1 to its Registration Statement on Form S-4 filed April 20, 2004 and incorporated by
reference herein.                                                                                                                                                       
|4.6  |  | Specimen Stock Certificate for EXCO's common stock, filed as an Exhibit to EXCO's Amendment No. 2 to the Form S-1 (File No. 333- 129935) filed on January 27, 2006 and incorporated by reference
herein.                                                                                                                                                   
|4.7  |  | Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to
EXCO's Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.                                  
|4.8  |  | Fifth Supplemental Indenture, dated as of May 2, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on
Form 8-K, dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                    
|4.9  |  | Sixth Supplemental Indenture, dated as of February 12, 2008, by and among EXCO Resources, Inc., EXCO Services, Inc. and Wilmington Trust Company, as Trustee, filed herewith.                                                                                                                                                                              
|4.10 |  | First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO's Amendment
No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.            
|4.11 |  | Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid
Preferred Stock, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
|4.12 |  | Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO's Form 8-K dated
March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.                                                              
|10.1 |  | Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the
Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.                                    

148

---



|10.2  |  | First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004, filed
as an Exhibit to EXCO's Registration Statement on Form S-4 filed March 25, 2004 and incorporated by reference herein.                                                                                                                               
|----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.3  |  | Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an Exhibit to EXCO's Annual Report
on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.                                                                                                                                                              
|10.4  |  | Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on Form 8-K/A-Amendment
No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.                                                                                                                                                     
|10.5  |  | Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to
EXCO's Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.                                                                                                                                    
|10.6  |  | Form of 71/4% Global Note Due 2011, filed as an Exhibit to EXCO's Pre-effective Amendment No. 1 to its Registration Statement on Form S-4 filed April 20, 2004 and incorporated by
reference herein.                                                                                                                                                                                                                                                         
|10.7  |  | Amended and Restated Credit Agreement, dated as of March 17, 2006, among EXCO Resource, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as
Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Manager, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated March 17, 2006 and filed on March 23, 2006 and incorporated by reference
herein.
|10.8  |  | 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.*                                                                                                                                                                                                                                                  
|10.9  |  | Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 14, 2007 and filed on
November 16, 2007 and incorporated by reference herein.*                                                                                                                                                                                                 
|10.10 |  | Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 14, 2007 and filed on
November 16, 2007 and incorporated by reference herein.*                                                                                                                                                                                              
|10.11 |  | Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO's Registration Statement on Form S-8 (File No. 333-132551) filed on
March 17, 2006 and incorporated by reference herein.*                                                                                                                                                                                                   
|10.12 |  | Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO's Current
Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.                                                                                                                                           

149

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|10.13 |  | First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco,
 LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.                                                       
|----- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.14 |  | Payment Performance Guaranty, dated July 22, 2006, by and between Progress Fuels Corporation and EXCO Resources, Inc., filed as an exhibit to EXCO's Current Report on Form 8-K, dated July 22, 2006 and
filed on July 24, 2006 and incorporated by reference herein.                                                                                                                                                                  
|10.15 |  | Senior Revolving Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party
thereto, filed as an Exhibit to EXCO's Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.                                            
|10.16 |  | First Amendment to Credit Agreement, dated October 2, 2006, among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an
Exhibit to EXCO's Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.                                                             
|10.17 |  | Amended and Restated Equity Contribution Agreement, dated October 4, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed
as an Exhibit to EXCO's Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.                                                             
|10.18 |  | Senior Term Credit Agreement, dated October 2, 2006, as amended and restated as of October 13, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as
Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO's Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
|10.19 |  | Second Amended and Restated Equity Contribution Agreement, dated October 13, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent,
 filed as an Exhibit to EXCO's Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.                                                   
|10.20 |  | Third Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by
reference herein.*                                                                                                                                                                                                                
|10.21 |  | 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.                                                                                                                                                                                                                
|10.22 |  | Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO's
Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.                                                        

150

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|10.23 |  | First Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement by and among Anadarko Petroleum Corporation, Anadarko Gathering Company, EXCO Partners Operating
Partnership, LP (successor by merger to Vernon Holdings, LLC) and Vernon Gathering, LLC, dated March 30, 2007, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated
by reference herein. 
|----- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.24 |  | Guaranty dated December 22, 2006 by EXCO Resources, Inc. in favor of Anadarko Petroleum Corporation and Anadarko Gathering Company, filed as an Exhibit to EXCO's Pre-Effective Amendment No. 1 to the
Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.                                                                                                                                   
|10.25 |  | Purchase and Sale Agreement by and among EXCO Resources, Inc., Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated
February 1, 2007, filed as an Exhibit to EXCO's Annual Report on Form 10-K filed on March 19, 2007 and incorporated by reference herein.                                                                                                                        
|10.26 |  | First Amendment to Credit Agreement effective as of December 31, 2006 among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the
lenders party thereto, filed as an exhibit to EXCO's Current Report on Form 8-K, dated March 8, 2007 and filed March 13, 2007 and incorporated by reference herein.                                                                                 
|10.27 |  | Preferred Stock Purchase Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on
April 2, 2007 and incorporated by reference herein.                                                                                                                                                                                                            
|10.28 |  | Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on
April 2, 2007 and incorporated by reference herein.*                                                                                                                                                                                                                  
|10.29 |  | Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, ACOF EXCO, L.P., ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares
EXCO 892 Investors, L.P, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.                                                                                                        
|10.30 |  | Amended and Restated Credit Agreement, dated as of March 30, 2007, among EXCO Partners Operating Partnership, LP, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan
Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference
herein.
|10.31 |  | Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the 7.0% Cumulative Convertible Perpetual Preferred Stock and the Hybrid
Preferred Stock, filed as an Exhibit to EXCO's Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.                                                                                                       
|10.32 |  | Registration Rights Agreement, dated March 28, 2007, by and among EXCO Resources, Inc. and the other parties thereto with respect to the Hybrid Preferred Stock, filed as an Exhibit to EXCO's Form 8-K dated
March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.                                                                                                                                                                     

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|10.33 |  | First Amendment to Letter Agreement by and among EXCO Resources, Inc., Southern G Holdings, LLC, Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation,
and Kerr-McGee Oil & Gas Onshore LP, dated April 13, 2007, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                                            
|----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.34 |  | Second Amended and Restated Credit Agreement, dated as of May 2, 2007, among EXCO Resources, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A.,
as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                             
|10.35 |  | Fifth Supplemental Indenture, dated as of May 2, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO's Current Report on
Form 8-K, dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                                                                                                                
|10.36 |  | Second Amendment to Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P Company LP, Howell Petroleum Corporation, Kerr-McGee
Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                     
|10.37 |  | Third Amendment to Purchase and Sale Agreement and Assignment of Partial Interest in the Purchase and Sale Agreement, effective as of February 1, 2007, by and among Anadarko Petroleum Corporation, Anadarko E&P
Company LP, Howell Petroleum Corporation, Kerr-McGee Oil & Gas Onshore LP, EXCO Resources, Inc. and Southern G Holdings, LLC, filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8,
2007 and incorporated by reference herein.
|10.38 |  | Membership Interest Purchase and Sale Agreement, dated May 8, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC, Crimson Exploration Inc. and Crimson Exploration Operating, Inc.,
filed as an Exhibit to EXCO's Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                                                                                             
|10.39 |  | Purchase Agreement, effective August 15, 2007, between OCM GW Holdings, LLC and EXCO Resources, Inc., filed as an Exhibit to EXCO's Current Report on Form 8-K, dated August 15, 2007 and filed on
August 21, 2007 and incorporated by reference herein.                                                                                                                                                                                                               
|10.40 |  | Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search, Incorporated, as sellers, filed
as an Exhibit to EXCO's Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.                                                                                                               
|10.41 |  | Sixth Supplemental Indenture, dated as of February 12, 2008, by and among EXCO Resources, Inc., EXCO Services, Inc. and Wilmington Trust Company, as Trustee, filed herewith.                                                                                                                                                                                                                                                                                          
|10.42 |  | Counterpart Agreement, dated February 4, 2008, to that Certain Second Amended and Restated Credit Agreement, dated May 2, 2007, among EXCO Resources, Inc., as Borrower, and certain subsidiaries of Borrower
and the lender parties thereto, filed herewith.                                                                                                                                                                                                          

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|10.43 |  | First Amendment to Second Amended and Restated Credit Agreement, dated as of February 20, 2008, by and among EXCO Resources, Inc., as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined
herein, and JP Morgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.            
|----- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.44 |  | First Amendment to Amended and Restated Credit Agreement, dated as of February 20, 2008, by and among EXCO Partners Operating Partnership, LP, as Borrower, certain of its subsidiaries, as Guarantors, the Lenders
defined therein and JP Morgan Chase Bank, N.A., as Administrative Agent, filed as an exhibit to EXCO's Current Report on Form 8-K, dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.
|10.45 |  | First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and Energy Search,
Incorporated, as sellers, filed as an exhibit to EXCO's Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.                                                                      
|14.1  |  | Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed
January 6, 2006 and incorporated by reference herein.                                                                                                                                                                                            
|14.2  |  | Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed
January 6, 2006 and incorporated by reference herein.                                                                                                                                                                                               
|14.3  |  | Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 8, 2006 and
filed on November 9, 2006 and incorporated by reference herein.                                                                                                                                                                            
|21.1  |  | Subsidiaries of the registrant, filed herewith.                                                                                                                                                                                                                                                                                                                                                                                                    
|23.1  |  | Consent of KPMG LLP, filed herewith.                                                                                                                                                                                                                                                                                                                                                                                                               
|23.2  |  | Consent of PricewaterhouseCoopers LLP, filed herewith.                                                                                                                                                                                                                                                                                                                                                                                             
|23.3  |  | Consent of PricewaterhouseCoopers LLP, filed herewith.                                                                                                                                                                                                                                                                                                                                                                                             
|23.4  |  | Consent of Lee Keeling and Associates, Inc., filed herewith.                                                                                                                                                                                                                                                                                                                                                                                       
|31.1  |  | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.                                                                                                                                                                                                                                                                                                        
|31.2  |  | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.                                                                                                                                                                                                                                                                                                        
|31.3  |  | Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting Officer of EXCO Resources, Inc., filed herewith.                                                                                                                                                                                                                                                                                                       
|32.1  |  | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.                                                                                                                                                                                                                                                                            
|99.1  |  | Audit Committee Charter, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.                                                                                                                                                                                                                                                                                                                      

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