UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





FORM 10-K/A

Amendment No. 2





(Mark One)



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

For the Fiscal Year Ended December 31, 2009

OR



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

For the Transition Period
from            to

Commission File Number 0-9204





EXCO
RESOURCES, INC.

(Exact name of Registrant as specified in its charter)







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

Registrants telephone number, including area code:
(214) 368-2084





Securities registered pursuant to Section 12(b) of the Act:



|                               |  |                                          
|------------------------------ |  | -----------------------------------------
|Title of each class            |  | Name of each exchange on which registered
|Common Stock, $0.001 par value |  | New York Stock Exchange                  

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)





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

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   ̈    No  x

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

Indicate by check mark 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.   ̈

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

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



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

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

As of February 12, 2010, the registrant had 212,054,805 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 the registrants common stock held by non-affiliates was $1,803,590,000.

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 2010 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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Explanatory Note

EXCO Resources, Inc. is filing this Amendment No. 2 on Form 10-K/A (this Amendment) to its Annual Report on Form 10-K for the fiscal year ended December 31, 2009, originally filed
with the Securities and Exchange Commission (the Commission) on February 24, 2010, and amended by Amendment No. 1 on Form 10-K/A filed with the Commission on March 3, 2010 (the 2009 Form 10-K), for the purpose
of addressing comments received from the staff of the Commission relating to the 2009 Form 10-K.

This Amendment revises the 2009 Form 10-K as
follows:

Item 1. Business.



| |  |  | Adds additional information clarifying who selects and receives the reports of our third-party engineering firms.
| | - |  | -----------------------------------------------------------------------------------------------------------------



| |  |  | Updates the information presented in the table captioned Revenues, production and prices to add separate disclosure for certain fields.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Adds language clarifying our methodology for reserve life calculation.
| | - |  | ----------------------------------------------------------------------



| |  |  | Adds additional information regarding the qualifications of the technical person primarily responsible for overseeing the preparation of our reserve
estimates.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Adds disclosure regarding capital costs incurred as footnote (2) to the proved undeveloped reserve reconciliation table.
| | - |  | ------------------------------------------------------------------------------------------------------------------------

Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.



| |  |  | Adds disclosure of the impact of our 2009 divestiture and joint venture transactions under Overview and history.
| | - |  | ------------------------------------------------------------------------------------------------------------------



| |  |  | Inserts a table containing production costs by geographic area in the Oil and natural gas operating costs section.
| | - |  | --------------------------------------------------------------------------------------------------------------------

Item 8. Exhibits, Financial Statement Schedules.



| |  |  | Includes revised Exhibit 99.1 to clarify the price used in making the reserves estimation.
| | - |  | ------------------------------------------------------------------------------------------



| |  |  | Includes revised Exhibit 99.2 to clarify the price used in making the reserves estimation, to remove certain cross references and to add additional
assurances regarding methods and procedures used to prepare the report.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In addition, in connection with filing this
Amendment and pursuant to the rules of the Commission, the companys Chief Executive Officer and Chief Financial Officer have reissued their certifications pursuant to section 302 of the Sarbanes-Oxley Act of 2002, attached as Exhibits 31.1 and
31.2 to this Amendment. Because no financial statements are contained within this Amendment, we are not including certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.



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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. and its consolidated subsidiaries.

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 29.

EXCO Resources, a Texas corporation incorporated in October 1955, is an independent oil and natural gas company engaged in the
exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in key North American oil and natural gas areas including East Texas, North Louisiana, Appalachia
and the Permian. In addition to our oil and natural gas producing operations, we own a 50% interest in a midstream joint venture in the East Texas/North Louisiana area. As of December 31, 2009, our Proved Reserves were approximately 1.0 Tcfe,
of which 96.5% were natural gas and 67.1% were Proved Developed Reserves. As of December 31, 2009, the PV-10 and the Standardized Measure of our Proved Reserves was $747.7 million (see Summary of geographic areas of
operations for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the year ended December 31, 2009, we produced 128.2 Bcfe of oil and natural gas. Based on December 2009 average daily production of
224.0 Mmcfe per day, this translates to a reserve life of approximately 11.7 years. We used annualized December 2009 production, rather than actual 2009 production, to calculate our reserve life as of December 31, 2009 due to the
significant reduction in production resulting from divestitures of proved producing reserves during 2009.

Our business strategy

Historically, we used acquisitions of producing properties with additional development drilling and workover opportunities
and vertical drilling of development wells in established producing areas as our vehicle for growth. As a result of our acquisitions, we have accumulated an inventory of drilling locations and acreage holdings with significant potential in the
Haynesville/Bossier and Marcellus shale resource plays. This shale potential has allowed us to shift our focus to exploit these shales primarily through horizontal drilling. Future acquisitions are likely to be focused on increasing our shale
resource holdings in the East Texas/North Louisiana and Appalachian areas. We will continue to develop certain vertical drilling opportunities in East Texas, North Louisiana, Appalachia and Permian as economic conditions permit.

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



| |  |  | Develop our shale resource plays
| | - |  | --------------------------------

We hold significant acreage positions in prominent shale plays in the United States. In East Texas and North Louisiana, we own approximately 53,900 net acres in the Haynesville/Bossier shale plays. During
2008, we conducted our initial technical evaluations and drilling of test wells in the Haynesville shale. In the fourth quarter of 2008, we drilled and completed our first horizontal well in the play. In 2009, we spud 43 operated horizontal wells
and entered into a joint venture with affiliates of BG Group plc, or BG Group, to jointly develop this area. In addition to our operated drilling, we participated in 20 Haynesville horizontal wells operated by others.



1



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Our operational focus has yielded significant improvements in drilling and completion
efficiencies in our Haynesville program. Our initial horizontal wells in the program required 72 days from spud to rig release. The amount of time to drill these wells has continued to improve and our most recent wells have averaged 37 days from
spud to rig release, a 50% reduction over a one-year period. By utilizing dedicated fracture stimulation fleets, the consistency in and efficiency of our fracturing operations has improved. We continue to work very closely with our midstream
operations to plan the drilling and completion timing of our new wells, which allows us to flow new completions to sales promptly after fracture stimulation.

In our Appalachia region, we hold approximately 343,000 net acres in the Marcellus and Huron shale resource plays. Our principal activities to date have been focused on technical evaluations of our
acreage holdings, expansion of our technical staff, evaluation of test wells and our acreage position. Our significant held-by-production position allows us to dictate our continued enhancement of the pace of development in the Marcellus and Huron
shales. We have commenced with a horizontal drilling program and plan to run one horizontal drilling rig during 2010 while continuing our technical evaluations in this large geographic area.



| |  |  | Pursue joint venture opportunities
| | - |  | ----------------------------------

The shale resource plays are capital intensive and require significant expenditures for drilling, completing, treating and pipeline take-away capacity. In our Haynesville/Bossier shale play, we entered
into joint venture transactions with BG Group to jointly develop the upstream assets and expand our midstream infrastructure. The Marcellus and Huron shale areas cover a geographic area which is significantly larger than the Haynesville/Bossier
shale area. We intend to seek joint venture partners in these areas to enhance our financial flexibility while developing these assets at an accelerated pace.



| |  |  | Expand our midstream assets
| | - |  | ---------------------------

We jointly own a midstream company in our East Texas/North Louisiana operating area with BG Group. These assets enhance our ability to promptly hook-up our wells for delivery of our production to markets.
We are presently completing construction of a 36-inch diameter 29-mile header system in DeSoto Parish, Louisiana and expanding our other gathering systems in East Texas and North Louisiana to facilitate the rapid production growth resulting from our
Haynesville shale drilling program. In Appalachia, we intend to pursue similar midstream expansions as part of our operating strategy. These expansions will also provide opportunities to transport third party gas and generate incremental gathering
and transportation fee income.



| |  |  | Exploit our multi-year development inventory
| | - |  | --------------------------------------------

Our prior strategy of acquiring producing properties created a portfolio with a multi-year inventory of shale and conventional drilling locations and exploitation projects. This inventory consists of
step-out drilling, infill drilling, exploratory drilling, workovers and recompletions. In 2009, we drilled and completed 41 horizontal wells with a 100% drilling success rate. Despite reducing our vertical drilling program in 2009 from prior years
due to low commodity prices, we still participated in the drilling and completion of 62 vertical wells with a 96.8% success rate. As of December 31, 2009, we have identified 11,856 drilling locations and 1,497 exploitation projects across our
portfolio.



| |  |  | Maintain financial flexibility
| | - |  | ------------------------------

We employ the use of debt and equity, along with a comprehensive derivative financial instrument program, to support our business 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



2



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structure. Our derivative financial instruments contributed $478.5 million of cash settlements which offset low commodity prices during 2009. During 2009, our joint venture strategy and
divestiture program resulted in a reduction of debt from $3.0 billion at the beginning of 2009 to $1.2 billion by the end of 2009 (prior to receipt of $53.8 million of acreage reimbursements from our joint venture partner subsequent to
December 31, 2009).



| |  |  | Actively manage our portfolio and associated costs
| | - |  | --------------------------------------------------

We periodically review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of
properties with higher operating costs, properties that are not within our core geographic operating areas and properties that are not strategic. We also seek to opportunistically divest properties in areas in which acquisitions and investment
economics no longer meet our objectives. During 2009, we completed asset divestitures, excluding the joint venture transactions with BG Group, totaling approximately $1.1 billion of proceeds. The divestiture program resulted in our exiting a number
of areas, including the Mid-Continent operating area and our operations in the state of Ohio.



| |  |  | Seek acquisitions that meet our strategic and financial objectives in our core operating areas
| | - |  | ----------------------------------------------------------------------------------------------

Historically, we have maintained a disciplined acquisition process to identify and acquire properties in our core operating areas that
have established production histories and value enhancement potential through development drilling and exploitation projects. Our shale resource plays have created a shift in our acquisition focus from producing properties to opportunistic acreage
acquisitions with additional shale potential. Acreage acquisitions differ from our prior strategy of acquiring producing properties as the acreage does not result in immediate production and cash flows or provide an incremental borrowing base
increase under our credit agreements. As a result, our acreage acquisition strategy will be dependent on our available borrowing base.



| |  |  | Identify and exploit upside opportunities on our acquired properties
| | - |  | --------------------------------------------------------------------

Our acquisitions and their resulting shale upside have led to significant reserve addition opportunities above those identified at the
date of acquisition. In our East Texas/North Louisiana area, we plan to aggressively drill horizontal wells, implement down spacing of wells, and recomplete existing wells to enhance our production and reserve position. In Appalachia, our focus will
be directed toward unconventional drilling and exploitation of the Marcellus shale resource play. We continue to exploit our Permian assets, which have resulted in higher oil production than originally expected.

Our strengths

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



| |  |  | High quality asset base in attractive regions
| | - |  | ---------------------------------------------

We own, and plan to maintain, a geographically diversified reserve base. Our principal operations are in the East Texas/North Louisiana, Appalachia and Permian areas. Our properties are generally
characterized by:



| |  |  | long reserve lives;
| | - |  | -------------------



| |  |  | exploration opportunities;
| | - |  | --------------------------



| |  |  | a multi-year inventory of development drilling and exploitation projects;
| | - |  | -------------------------------------------------------------------------



| |  |  | high drilling success rates;
| | - |  | ----------------------------



| |  |  | a high natural gas concentration; and
| | - |  | -------------------------------------



| |  |  | significant unproved reserves and resources.
| | - |  | --------------------------------------------



3



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| |  |  | Skilled technical personnel with supplemental support and expertise from our joint venture partner
| | - |  | --------------------------------------------------------------------------------------------------

Our acquisitions and hiring programs have provided us with skilled multi-disciplined technical and operational personnel who have allowed
us to rapidly ramp up our horizontal drilling program. In addition, our access to BG Groups personnel in the East Texas/North Louisiana area supplement our execution strategy.



| |  |  | Shale resource plays
| | - |  | --------------------

Our Haynesville, Bossier, Marcellus and Huron shale resource plays present significant opportunities to grow our reserves with low finding and development costs. Since the majority of the acreage in these
areas is held-by-production, we are not forced to commit large amounts of capital over a short period of time to avoid lease expirations.



| |  |  | Experienced management team with significant employee ownership
| | - |  | ---------------------------------------------------------------

Our management team has led both public and private oil and natural gas companies over the past 20 years and has an average of over
26 years of industry experience in exploring, acquiring, developing and exploiting oil and natural gas properties. Our management team first purchased a significant ownership interest in us in December 1997, and since then we have achieved
substantial growth in reserves and production. Since the beginning of 1998, we have increased our Proved Reserves from approximately 4.7 Bcfe to approximately 1.0 Tcfe for December 2009, and our average daily production increased from less than
1 Mmcfe per day in 1997 to 224.0 Mmcfe per day for December 31, 2009. As of February 10, 2010, our named executives (excluding our outside directors) own approximately 4.6% of our issued and outstanding common stock and exercisable stock
options and our outside directors and/or their affiliated investment funds own approximately 28.1% of our issued and outstanding common stock and exercisable stock options, which aligns their objectives with those of our shareholders.



| |  |  | Operational control
| | - |  | -------------------

We operate a significant portion of our properties, coupled with significant held-by-production acreage, which permits us to manage our operating costs and better control capital expenditures as well as
the timing of development and exploitation activities. As of December 31, 2009, we operated 7,416 gross wells which represented approximately 97.0% of our Proved Reserves.

Plans for 2010

Our efforts in 2009 were primarily focused on ramping up
our drilling activities in the Haynesville shale, de-leveraging our balance sheet and executing our divestiture program to allow for increased attention on exploitation of our shale play assets. Commodity prices were substantially lower in 2009
compared with 2008 and presented significant challenges to economically develop our portfolio. However, the impacts of these lower commodity prices were substantially mitigated by our derivative financial instruments program.

The closing of our upstream and midstream joint venture transactions with BG Group, coupled with our successful divestiture program,
provided us with cash to execute our horizontal drilling program in East Texas/North Louisiana, strategically add to our acreage position and reduce our debt by $1.8 billion. In addition to the cash received from BG Group in connection with the
upstream joint venture transaction, BG Group also agreed to fund $400.0 million of capital development attributable to our 50% interest in the venture, or the BG Carry, with BG Group paying 75% of our share of drilling and completion costs in the
Haynesville/Bossier shales until the $400.0 million funding is satisfied. The BG Carry applies only to drilling and completion activities below the Cotton Valley formation, particularly focusing on the Haynesville/Bossier shales. Other expenditures
are shared equally between EXCO and BG Group.



4



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Our plans for 2010 are focused on the Haynesville/Bossier and Marcellus shales. Budgeted
capital expenditures for 2010 total $471.4 million, of which $409.4 million, or 86.8%, is allocated to our East Texas/North Louisiana and Appalachia regions. In East Texas and North Louisiana, capital expenditures in the area of mutual interest with
BG Group, or BG AMI, are expected to total $740.8 million, with EXCOs share being approximately $165.3 million, which reflects the favorable impact of $205.1 million to be funded pursuant to the BG Carry. In Appalachia, our planned capital
expenditures total $154.2 million.

The 2010 capital budget includes $39.1 million for midstream activities, which includes a
$7.8 million contribution to TGGT Holdings, LLC, or TGGT. TGGT is the newly formed midstream joint venture owned equally by EXCO and BG Group. TGGT owns the midstream assets located within the BG AMI in East Texas and North Louisiana. The TGGT
capital budget for 2010 is $101.0 million, $50.5 million net to EXCOs interest. This budget will be mostly funded by internal TGGT cash flow. In addition, the management of TGGT is evaluating several expansion projects which, if approved, will
require additional capital contributions.

We expect commodity prices, particularly for natural gas, to be volatile and this
volatility may have an impact on our drilling activities. We have consistently used derivative financial instruments as a strategy to mitigate commodity price volatility and we expect to continue to enter into derivative financial instruments as
opportunities arise.

Significant activities during 2009

Haynesville shale

In the fourth quarter of 2008, we completed our
first horizontal well in the Haynesville shale. In 2009, we significantly expanded our activities in this area, both internally during the first and second quarters and jointly with BG Group beginning in the third quarter, to become a significant
operator in the play. We spud 43 operated horizontal wells in 2009 and completed and turned to sales 25 wells. We are presently operating 13 drilling rigs in the area. In DeSoto Parish, Louisiana, where we have focused our 2009 drilling, our average
initial production rate per well has averaged 22.8 Mmcf per day. The addition of BG Group as a strategic partner will allow us to accelerate drilling in the area in 2010 and beyond. Another strategic component in the Haynesville area is our
ownership interest in TGGT. The integration with TGGT provides us with timely well connections and priority pipeline space to deliver our production to market.

Marcellus shale

Our efforts in 2009 in the Marcellus shale were
focused on testing and evaluating our shale holdings to determine the best areas and techniques for development. This consisted of drilling and coring vertical test wells, analyzing cores and logs, testing stimulation methods and solving future
marketing, logistics and regulatory issues associated with this shale play. As a result of these efforts, we have shifted our focus to horizontal well drilling primarily in central Pennsylvania, where we are beginning a horizontal drilling program.
We are also planning expansion of our midstream assets in the area to accommodate the expected future natural gas production from both EXCO and third party development.



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Joint ventures and divestiture program

A summary of our joint venture and divestiture activities during 2009 is presented on the following table. Proceeds from the transactions
were used to reduce our debt and fund our capital program.



|                                      |  |             |           | 
|------------------------------------- |  | ----------- | --------- | 
|(in thousands)                        |  | Proceeds(1) |          
|Operating division                    |  |             |           | 
|East Texas/North Louisiana            |  |             |           | 
|BG Upstream Transaction               |  | $           | 713,779   | 
|BG Midstream Transaction              |  |             | 269,237   | 
|East Texas Transaction                |  |             | 154,299   | 
|Other East Texas/North Louisiana      |  |             | 22,327    | 
|Mid-Continent                         |  |             |           | 
|Mid-Continent Transaction             |  |             | 197,730   | 
|Sheridan Transaction(2)               |  |             | 531,351   | 
|Other Mid-Continent                   |  |             | 5,482     | 
|Appalachia                            |  |             |           | 
|EnerVest Transaction(2)(3)            |  |             | 129,737   | 
|Permian                               |  |             | 40,042    | 
|                                      |  |             |           | 
|Total joint ventures and divestitures |  | $           | 2,063,984 | 
|                                      |  |             |           | 



|(1) | Net of selling expenses.
|--- | ------------------------



|(2) | Subject to final closing adjustments.
|--- | -------------------------------------



|(3) | Pending receipt of an additional $13.1 million of consents.
|--- | -----------------------------------------------------------

On August 11, 2009, we closed a sale of properties located in East Texas, or the East Texas Transaction, with Encore Operating, LP, or Encore. Pursuant to the East Texas Transaction, we sold all of
our interests in certain oil and natural gas properties located in our Overton Field and Gladewater area of East Texas. We received $154.3 million in cash, after final closing adjustments.

On August 11, 2009, we closed a sale of properties located in Texas and Oklahoma, or the Mid-Continent Transaction, with Encore.
Pursuant to the Mid-Continent Transaction, we sold all of our interests in certain oil and natural gas properties located in our Mid-Continent operating area. We received $197.7 million in cash, after final closing adjustments.

On August 14, 2009, we closed a sale and joint development transaction with BG Group for the sale of an undivided 50% of our
interest in the BG AMI, which included most of our oil and natural gas assets in East Texas and North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), or the BG Upstream Transaction. The BG Upstream
Transaction includes agreements for the joint development and operation of our Haynesville and Bossier shales as well as the shallow Cotton Valley and other formations located in the BG AMI. We received $713.8 million in cash, after final closing
adjustments necessary to reflect the January 1, 2009 effective date. Pursuant to this transaction, BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling
and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, BG Groups funding of the $400.0 million commitment will be satisfied solely through
drilling of deep right wells as defined in the agreement. As of December 31, 2009, the remaining balance of the BG Carry was approximately $367.7 million.

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



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pipeline in East Texas and a gathering system in North Louisiana and Talco Midstream Assets, Ltd., or Talco, which owns gathering assets in East Texas and North Louisiana, to TGGT. BG Group
contributed $269.2 million in cash, after final closing adjustments, to TGGT and we received those funds from TGGT as a special distribution at closing. EXCO Operating Company, LP, or EXCO Operating, now owns 50% of TGGT and the affiliate of BG
Group owns 50% of TGGT. The effective date of this transaction was also January 1, 2009.

The total cash proceeds of
$983.0 million from the BG Upstream Transaction and the BG Midstream Transaction were used to repay EXCO Operatings $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, create an evergreen escrow funding account
to develop the Haynesville operations, and provide a working capital contribution to TGGT, with the remainder applied to the outstanding balances under EXCO Operatings credit agreement.

On November 10, 2009, we closed the sale of our remaining assets in our Mid-Continent operating area to Sheridan Holding Company I,
LLC, or the Sheridan Transaction, for $531.4 million, subject to final closing adjustments. The sale was effective as of October 1, 2009.

On November 24, 2009, we closed the sale of certain Ohio and Northwestern Pennsylvania producing assets to EV Energy Partners, L.P., along with certain institutional partnerships managed by EnerVest,
Ltd., or the EnerVest Transaction, for $129.7 million, subject to final closing adjustments. In connection with the closing, the parties agreed to hold back approximately $13.1 million of the properties pending the receipt of required consents from
third parties necessary to transfer such properties. The sale was effective as of September 1, 2009.

During the year, we
also closed sales of other non-strategic assets across all of our operating areas, resulting in net cash proceeds of approximately $67.9 million after final closing adjustments.

Acreage acquisitions

As part of our ongoing shale-focused strategy,
we acquired acreage within the BG AMI in the Haynesville/Bossier shale play throughout 2009. A substantial amount of this acreage was acquired in the fourth quarter, where we completed acquisitions of undeveloped acreage and other assets for
approximately $251.5 million. Pursuant to terms contained within the agreement in the BG Upstream Transaction, we offered BG Group 50% of these acquisitions under terms identical to our acquisition agreements. BG Group has 60 days to elect to
participate for their share of acquisitions. BG has elected to acquire their 50% interest in all cases in which the election period has been completed.

In our Appalachia region, we completed acreage acquisitions totaling $6.6 million in 2009.

Debt reduction

During 2009, we reduced our consolidated debt to $1.2 billion as of December 31, 2009 from $3.0 billion as of December 31, 2008.
The reductions were the result of our successful joint venture transactions with BG Group and our divestiture program. The joint ventures and divestitures also affected the borrowing bases in our two revolving credit agreements. A summary of our
outstanding long-term debt as of December 31, 2009 and 2008 is as follows:



|                                                               |  |              |           |  |      |   |           | 
|-------------------------------------------------------------- |  | ------------ | --------- |  | ---- | - | --------- | 
|                                                               |  | December 31, |          
|(in thousands)                                                 |  | 2009         |           |  | 2008 |  
|EXCO Resources Credit Agreement                                |  | $            | 81,486    |  |      | $ | 1,048,951 | 
|EXCO Operating Credit Agreement                                |  |              | 666,078   |  |      |   | 1,218,485 | 
|Term Credit Agreement                                          |  |              |          |  |      |   | 300,000   | 
|71/4% Senior Notes due January 15, 2011                        |  |              | 444,720   |  |      |   | 444,720   | 
|Unamortized premium on 71/4% Senior Notes due January 15, 2011 |  |              | 3,993     |  |      |   | 7,582     | 
|                                                               |  |              |           |  |      |   |           | 
|Total debt                                                     |  | $            | 1,196,277 |  |      | $ | 3,019,738 | 
|                                                               |  |              |           |  |      |   |           | 



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As of December 31, 2009, we had cash and cash equivalents of $68.4 million and $58.9
million of restricted cash. The restricted cash is principally comprised of our share of an evergreen escrow account with BG Group which is used to fund our share of operations and development within the BG AMI.

A summary of each of our revolving credit agreements, senior notes and other debt is presented below.

EXCO Resources credit agreement.    The EXCO Resources credit agreement, as amended, or the EXCO Resources
Credit Agreement, matures on March 30, 2012 and had a borrowing base of $450.0 million as of December 31, 2009.

EXCO Operating credit agreement.The EXCO Operating credit agreement, as amended, or the EXCO
Operating Credit Agreement, matures on March 30, 2012 and had a borrowing base of $850.0 million as of December 31, 2009.

71/4% senior notes due January 15, 2011.EXCO has
issued 7 1/4% senior notes due January 15, 2011, or the Senior Notes, totaling $444.7 million as of December 31, 2009. Interest is payable semi-annually on January 15 and July 15 of each year. We presently have sufficient
borrowing capacity under the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement to pay the Senior Notes.

Term Credit Agreement.In connection with the closings of the BG Upstream Transaction and the BG Midstream Transaction, the Term Credit Agreement was paid in
full on August 14, 2009. The Term Credit Agreement was due and payable on January 15, 2010. As a result of the early payment of the Term Credit Agreement, EXCO Operating avoided payment of a $9.0 million duration fee that would have been
due on September 15, 2009.

Summary of geographic areas of operations

The following tables set forth summary operating information attributable to our principal geographic areas of operation:



|                           |  |                                |        |  |                                   |   |       |                                           |  |  |                       |  |  |  |         | 
|-------------------------- |  | ------------------------------ | ------ |  | --------------------------------- | - | ----- | ----------------------------------------- |  |  | --------------------- |  |  |  | ------- | 
|Areas                      |  | TotalProvedReserves(Bcfe)(1)   |        |  | PV-10(in 
millions)(1)(2)         |   |       | AverageDecemberdaily netproduction(Mmcfe) |  |  | Reservelife(years)(3) | 
|East Texas/North Louisiana |  |                                | 630.0  |  |                                   | $ | 562.7 |                                           |  |  | 168.0                 |  |  |  | 10.3    | 
|Appalachia                 |  |                                | 264.8  |  |                                   |   | 107.3 |                                           |  |  | 38.0                  |  |  |  | 19.1    | 
|Permian and other          |  |                                | 64.0   |  |                                   |   | 77.7  |                                           |  |  | 18.0                  |  |  |  | 9.7     | 
|                           |  |                                |        |  |                                   |   |       |                                           |  |  |                       |  |  |  |         | 
|Total                      |  |                                | 958.8  |  |                                   | $ | 747.7 |                                           |  |  | 224.0                 |  |  |  | 11.7    | 
|                           |  |                                |        |  |                                   |   |       |                                           |  |  |                       |  |  |  |         | 
|                           |  |                                |        | 
|Areas                      |  | Identifieddrillinglocations(4) |        |  | Identifiedexploitationprojects(5) |   |       | Total grossacreage                        |  |  | Total netacreage(6)   | 
|East Texas/North Louisiana |  |                                | 3,798  |  |                                   |   | 930   |                                           |  |  | 266,047               |  |  |  | 155,945 | 
|Appalachia                 |  |                                | 7,592  |  |                                   |   | 537   |                                           |  |  | 726,499               |  |  |  | 654,168 | 
|Permian and other          |  |                                | 466    |  |                                   |   | 30    |                                           |  |  | 190,059               |  |  |  | 137,420 | 
|                           |  |                                |        |  |                                   |   |       |                                           |  |  |                       |  |  |  |         | 
|Total                      |  |                                | 11,856 |  |                                   |   | 1,497 |                                           |  |  | 1,182,605             |  |  |  | 947,533 | 
|                           |  |                                |        |  |                                   |   |       |                                           |  |  |                       |  |  |  |         | 



|(1) | The total Proved Reserves and PV-10 for non-shale properties, excluding future plugging and abandonment costs, of the Proved Reserves, as used in this
table, were prepared by Lee Keeling and Associates, Inc., or Lee Keeling, an independent petroleum engineering firm located in Tulsa, Oklahoma. The total Proved Reserves and PV-10 for our shale properties, excluding future plugging and
abandonment costs, as used in the table, were prepared by Haas Petroleum Engineering Services, Inc., or Haas Engineering, an
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



8



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| | independent petroleum engineering firm located in Dallas, Texas. For each area set forth in the table, the Proved Reserves were extracted from the reports from Lee Keeling and Haas Engineering by
our internal engineers. The estimated future plugging and abandonment costs necessary to compute PV-10 were computed internally.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | The PV-10 data used in this table is based on the simple average spot prices for the trailing twelve month period using the first day of each month beginning on
January 1, 2009 and ended on December 1, 2009, of $3.87 per Mmbtu for natural gas and $61.18 per Bbl for oil, in each case adjusted for geographical and historical differentials. Market prices for oil and natural gas are volatile. See
Item 1A. Risk factorsRisks relating to our business. We believe that PV-10 before income taxes, while not a financial measure in accordance with generally accepted accounting principles, or 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. The
total Standardized Measure, a measure recognized under GAAP, for our Proved Reserves as of December 31, 2009 was $747.4 million. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in
accordance with Accounting Standards Codification Topic 932, Extractive ActivitiesOil and Gas, or ASC 932. The 32.2% decrease in the natural gas price at December 31, 2009 compared with December 31, 2008 resulted in
significantly lower future net revenues and future net cash flows. Our existing net operating loss carry-forwards combined with reduced cash flows eliminated estimated future taxable income. The amount of estimated future plugging and abandonment
costs, the PV-10 of these costs and the Standardized Measure were determined by us. We do not designate our derivative financial instruments as hedges and accordingly, do not include the impact of derivative financial instruments when computing the
Standardized Measure. The following table provides a reconciliation of our PV-10 to our Standardized Measure as of December 31, 2009.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                                                 |  |                 |       |  |      |   |         |      |  |   |          |  
|------------------------------------------------ |  | --------------- | ----- |  | ---- | - | ------- | ---- |  | - | -------- | -
|                                                 |  | At December 31, |      
|(in millions)                                    |  | 2009            |       |  | 2008 |   |         | 2007 | 
|PV-10                                            |  | $               | 747.7 |  |      | $ | 2,473.5 |      |  | $ | 3,945.9  |  
|Future income taxes                              |  |                 |      |  |      |   | (649.8  | )    |  |   | (1,857.5 | )
|Discount of future income taxes at 10% per annum |  |                 |      |  |      |   | 412.6   |      |  |   | 1,030.5  |  
|                                                 |  |                 |       |  |      |   |         |      |  |   |          |  
|Standardized Measure                             |  | $               | 747.7 |  |      | $ | 2,236.3 |      |  | $ | 3,118.9  |  
|                                                 |  |                 |       |  |      |   |         |      |  |   |          |  



|(3) | For purposes of this table, the reserve life is calculated by dividing the Proved Reserves (on an Mmcfe basis) by the annualized daily production volumes for December
2009.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | Identified drilling locations represent total gross drilling locations identified and scheduled by our management as an estimation of our multi-year drilling activities
on existing acreage. Of the total locations shown in the table, 1,726 are classified as proved. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas
prices, costs, drilling results and other factors. See Item 1A. Risk factorsRisks relating to our business.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(5) | Identified exploitation projects represent total gross exploitation projects, such as workovers, recompletions, and other non-drilling activities, identified and
scheduled by our management as an estimation of our multi-year exploitation projects on existing acreage. Of the total exploitation projects shown in the table, 874 are classified as proved. Our actual exploitation projects may change depending on
the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs and other factors. See Item 1A. Risk factorsRisks relating to our business.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(6) | Includes 38,638, 95,851 and 25,557 net acres with leases expiring in 2010, 2011 and 2012, respectively. Net acreage at December 31, 2009 reflects a reduction of
7,341 acres that BG Group elected to acquire after December 31, 2009, pursuant to the BG AMI.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



9



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Our development and exploitation project areas

LOGO

East Texas/North Louisiana

The East Texas/North Louisiana area is comprised of the Cotton Valley Sand trend, which covers portions of the East Texas Basin and the Northern Louisiana Salt Basin, and the Haynesville shale play that
rapidly developed in northwest Louisiana and East Texas beginning in 2008. EXCO operates or participates in over 1,300 total wells in the area and has significant operations base and infrastructure in East Texas and North Louisiana. We are targeting
tight gas sand reservoirs along the Cotton Valley Sand trend at depths of approximately 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 are mostly focused on infill development drilling and extension of field limits. The Haynesville/Bossier shale plays lie beneath the Cotton Valley. Our
Haynesville shale targets are approximately 12,000 feet true vertical depth and developed with horizontal wells that are typically approximately 16,500 feet measured depth. Based on our 2009 results we have realized in the shale play, the majority
of our focus in this area will be on horizontal shale development drilling.

Haynesville/Bossier shale

In the Haynesville/Bossier shale resource play in the East Texas/Northwest Louisiana area we hold approximately 53,900 net acres. The core
area of the Haynesville shale is located in Desoto and Caddo Parishes in Louisiana and Harrison and Panola Counties in Texas. A large percentage of our core area acreage is held by our existing Cotton Valley, Hosston and Travis Peak production.
During the fourth quarter of 2009, we acquired 14,700 net acres in several transactions, all located in the core area of the shale play. This additional acreage is complementary to our existing acreage, operations and pipeline infrastructure and
provides significant additional development potential in the play.

Our development program in the Haynesville shale play has
transitioned from a vertical testing and data acquisition program to a full horizontal development drilling program. In early 2009 we were running 4 operated horizontal rigs in the play and we exited 2009 with 12 operated horizontal rigs. In 2009,
we spud 43 operated horizontal wells and by year end had 25 of those wells completed and flowing to sales. Our first horizontal well, the Oden 30H #6 in DeSoto Parish, Louisiana has performed exceptionally well, having produced 3.2 Bcf of natural
gas during its first year of production. EXCO operated wells in the DeSoto Parish have averaged initial



10



---

production rates of approximately 23 Mmcf per day. We also participated in 12 outside operated horizontal Haynesville wells that were completed and turned to sales in 2009. At year end 2009, we
had 12 operated horizontal rigs drilling. We are adding two additional horizontal drilling rigs in the first quarter of 2010, which will bring our operated rig count to 14. We plan to drill 102 operated horizontal wells and participate in 23
non-operated horizontal wells in 2010. At year end 2009, we had Proved Reserves of 153.8 Bcfe and 38 gross producing wells in the Haynesville shale. As of February 12, 2010, our operated Haynesville shale production was approximately 318.2 Mmcf
per day gross (85.0 Mmcf per day net). We expect significant production and reserve growth with our Haynesville shale development program in 2010 and beyond.

The Bossier shale section overlies the Haynesville shale. In 2009, we initiated a Bossier shale testing program. We have acquired core in the Bossier shale in different wells and have rock mechanics
testing and other reservoir engineering studies ongoing. We have completed testing of the Bossier shale across our acreage by utilizing the vertical Haynesville test wells drilled during 2008. The Bossier shale has up to five times the thickness of
the Haynesville shale in the DeSoto Parish area, and may hold significant reserve potential. Based on the test results acquired to date in these vertical wells, we are now drilling our first Bossier horizontal test and expect to complete it in the
first quarter of 2010. We are planning a total of seven Bossier horizontal tests across our acreage in East Texas and North Louisiana in our 2010 development plan. These seven Bossier horizontal tests are included in the total of 102 horizontals
shale wells planned for the year.

We have a strong commitment to technical evaluations to improve our understanding of these
shale plays, and have made appropriate investments to reduce risks. We are members of a major shale consortium, reservoir engineering consortium and several other engineering and geoscience study projects. We are acquiring 2-D seismic data over a
regional area, are currently shooting a 168 square mile 3-D seismic survey and have initiated a 20 section microseismic fracture stimulation monitoring project.

Vernon/Kelleys Fields

The Vernon Field, located in Jackson Parish,
Louisiana, is our largest producing field, accounting for approximately 27.4% of our company production at year end 2009. The field produces from the Lower Cotton Valley and Bossier Sand formations at depths ranging from 12,000 to 15,000 feet. At
year end 2009, we had Proved Reserves of 316.3 Bcfe and 402 gross producing wells. A focus on maintaining base production levels and lowering our operating expenses is a priority. We gather and treat our own natural gas and have access to numerous
transmission lines in the area. The Kelleys Field is located north of the Vernon Field. In 2009, we drilled and completed seven gross wells in the two fields. We have plans to drill seven wells in 2010.

East Texas/North Louisiana Cotton Valley Area

Within our Cotton Valley Area, we are active in Harrison, Panola, Rusk, Upshur and Gregg Counties in Texas, primarily across four fieldsDanville, Waskom, Oak Hill and Minden. We are also active in
Caddo and DeSoto Parishes Louisiana, primarily in four fieldsHolly, Kingston, Caspiana and Longwood. At year end 2009, we had Proved Reserves in the Cotton Valley and shallower horizons of 157.1 Bcfe and 903 gross producing wells. We are
primarily focused on developing Cotton Valley sands at depths ranging from approximately 10,400 to 11,000 feet and the Travis Peak and Hosston Sands at approximately 7,800 to 10,000 feet. Our natural gas is gathered through gathering lines operated
by TGGT. We drilled and completed 19 wells in 2009 across the Cotton Valley area. Our plans for 2010 include a horizontal testing program in the Cotton Valley including six tests across our acreage to evaluate the feasibility of a larger scale
horizontal program for 2011 and beyond. We are also planning to conduct 28 recompletions in the area, primarily targeting the Hosston interval.

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.



11



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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 traditionally been derived from relatively shallow, low porosity and permeability sand and shale formations at depths of 1,000 to 8,000
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 over 200,000 producing wells
and more than 5,000 operators with most being relatively small, private enterprises. Our operations in the area have included maintaining our existing production base from our shallow wells. We believe that the number of wells and operators presents
a significant consolidation opportunity. We also believe the Marcellus shale development presents a significant growth opportunity for us.

Marcellus Shale Resource Play

During 2009, we focused on testing and evaluating our Marcellus fairway acreage, which we define as being geologically over-pressured. Our net acreage in the play totals approximately 343,000 acres, all
of which is located in Pennsylvania and West Virginia. Of our total acreage, approximately 186,000 acres are located in the over-pressured fairway. Approximately 70% of our Marcellus shale fairway acreage is held by shallow production. Testing of
the Marcellus shale has been conducted on 6 vertical wells and 2 horizontal wells. In the fourth quarter, we began the early stages of development drilling of the Marcellus shale play in central Pennsylvania with the spudding of a horizontal well.
We continue to hire technical personnel to support the development of this play in five distinct team areas covering our entire Marcellus shale fairway acreage position.

Pennsylvania Area

The Pennsylvania Area encompasses 23
of the counties in the state. At December 31, 2009 we had Proved Reserves of 153.2 Bcfe and 3,776 gross producing wells. Drilling, completion and production activities target the Marcellus shale and the Upper Devonian Venango, Bradford and Elk
sandstone groups at depths of 1,800 to 8,100 feet. We plan to use one operated horizontal drilling rig to drill and complete 11 gross (11.0 net) horizontal wells. We also plan to drill and complete 5 gross (5.0 net) vertical wells targeting the
Marcellus shale and 6 gross (6.0 net) wells in 2010 targeting the shallower Upper Devonian reservoirs.

West Virginia Area

The West Virginia Area includes 29 counties stretching from the northern to the southern areas of the state. At December 31, 2009 we
had Proved Reserves of 104.7 Bcfe and 2,273 gross producing wells. Drilling, completion and production activities target the Marcellus shale and the multiple, laterally stratified reservoirs of the Mississippian and Devonian formations found at
depths ranging from 1,500 to 8,100 feet. During 2010, we currently plan to drill 1 gross (1.0 net) operated vertical well and participate in 4 gross (0.6 net) horizontal wells operated by others targeting the Marcellus Shale.

Permian

The
Permian Basin, located in West Texas and the adjoining area of southeastern New Mexico, is best known as a mature oil focused basin exploited with waterflood and other enhanced oil recovery techniques. Our activities are focused on conventional oil
and natural gas properties. With the use of 3-D seismic, we are targeting prolific 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 have a total working interest of 97% in the property. At December 31, 2009, we had Proved Reserves of 57.7 Bcfe and 281 gross producing wells. Production is primarily from the
Canyon Sand from depths of 6,700 to 7,900 feet. We currently plan to use one operated, vertical rig to drill 36 wells in 2010.



12



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Our oil and natural gas reserves

Changes in our Proved Reserves for the year ended December 31, 2009 were impacted by the following significant factors and events:



| |  |  | significant additions of new Proved Reserves arising from our drilling of horizontal wells in the Haynesville shale. After the impact of the BG
Upstream Transaction discussed below, we have 153.8 Bcfe of Proved Reserves in the Haynesville shale play as of December 31, 2009 compared with 14.1 Bcfe at December 31, 2008;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our BG Upstream Transaction resulted in the sale of an undivided 50% of our oil land natural gas assets in East Texas/North Louisiana, with the
exception of our Vernon Field in Jackson Parish, Louisiana. The BG Upstream Transaction also included an undivided 50% of our Haynesville/Bossier shale play and the BG Carry, which will reduce development costs by $400.0 million;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our 2009 divestiture activities, including the BG Upstream Transaction and included sales resulting in an exit from our Mid-Continent and Ohio regions,
reduced Proved Reserves by approximately 790.4 Bcfe; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a 32.2% decrease in the price of natural gas used in determining Proved Reserves at December 31, 2009 compared with December 31, 2008.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------

The following table summarizes Proved Reserves at December 31, 2009, 2008 and 2007. This information
was prepared in accordance with the rules and regulations of the Securities and Exchange Commission, or the SEC.



|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|------------------------------------- |  | --------------- | ----- |  | ---- | - | ------- | ---- |  | - | ------- | 
|                                      |  | At December 31, |      
|                                      |  | 2009            |       |  | 2008 |   |         | 2007 | 
|Oil (Mmbbls)                          |  |                 |       |  |      |   |         |      |  |   |         | 
|Developed                             |  |                 | 3.5   |  |      |   | 14.8    |      |  |   | 15.2    | 
|Undeveloped                           |  |                 | 2.0   |  |      |   | 6.0     |      |  |   | 5.7     | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Total                                 |  |                 | 5.5   |  |      |   | 20.8    |      |  |   | 20.9    | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Natural Gas (Bcf)                     |  |                 |       |  |      |   |         |      |  |   |         | 
|Developed                             |  |                 | 622.2 |  |      |   | 1,354.8 |      |  |   | 1,228.8 | 
|Undeveloped                           |  |                 | 303.6 |  |      |   | 460.3   |      |  |   | 510.9   | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Total                                 |  |                 | 925.8 |  |      |   | 1,815.1 |      |  |   | 1,739.7 | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Equivalent reserves (Bcfe)            |  |                 |       |  |      |   |         |      |  |   |         | 
|Developed                             |  |                 | 643.2 |  |      |   | 1,443.6 |      |  |   | 1,320.0 | 
|Undeveloped                           |  |                 | 315.6 |  |      |   | 496.3   |      |  |   | 545.1   | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Total                                 |  |                 | 958.8 |  |      |   | 1,939.9 |      |  |   | 1,865.1 | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|PV-10 (in millions)(1)                |  |                 |       |  |      |   |         |      |  |   |         | 
|Developed                             |  | $               | 649.8 |  |      | $ | 2,375.7 |      |  | $ | 3,369.2 | 
|Undeveloped                           |  |                 | 97.9  |  |      |   | 97.8    |      |  |   | 576.7   | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Total                                 |  | $               | 747.7 |  |      | $ | 2,473.5 |      |  | $ | 3,945.9 | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 
|Standardized Measure (in millions)(2) |  | $               | 747.7 |  |      | $ | 2,236.3 |      |  | $ | 3,118.9 | 
|                                      |  |                 |       |  |      |   |         |      |  |   |         | 



|(1) | The PV-10 data does not include the effects of income taxes or derivative financial instruments, and is based on the following average and spot prices, in each case
adjusted for historical differentials.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



13



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|(2) | There is no difference in Standardized Measure and PV-10 as of December 31, 2009 as the impacts of lower natural gas prices, net cash flows and net operating loss
carry-forwards eliminated estimated future income taxes.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                  |  |                           |      |  |              |   |       | 
|----------------- |  | ------------------------- | ---- |  | ------------ | - | ----- | 
|                  |  | Average and spot price(a) |     
|Date              |  | Natural gas(per Mmbtu)    |      |  | Oil(per Bbl) |  
|December 31, 2009 |  | $                         | 3.87 |  |              | $ | 61.18 | 
|December 31, 2008 |  |                           | 5.71 |  |              |   | 44.60 | 
|December 31, 2007 |  |                           | 6.80 |  |              |   | 95.92 | 



| | (a) | The prices for 2009 are the average spot prices for the trailing twelve month period per Mmbtu at Henry Hub and per Bbl at Cushing, Oklahoma, using the first day of
each month beginning on January 1, 2009 and ended December 1, 2009. The prices for 2008 and 2007 represent the December 31 spot price per Mmbtu at Henry Hub and per Bbl at Cushing, Oklahoma in each respective year.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

We believe that PV-10 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 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 ASC 932. The following table provides a reconciliation of our PV-10 to our Standardized Measure:



|                                                 |  |   |       | 
|------------------------------------------------ |  | - | ----- | 
|(in millions)                                    |  |   |      
|PV-10                                            |  | $ | 747.7 | 
|Future income taxes                              |  |   |      | 
|Discount of future income taxes at 10% per annum |  |   |      | 
|                                                 |  |   |       | 
|Standardized Measure                             |  | $ | 747.7 | 
|                                                 |  |   |       | 

Management has established, and is responsible for, internal controls designed to provide reasonable
assurance that the estimates of Proved Reserves are computed and reported in accordance with rules and regulations promulgated by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal
controls include documented process workflows, qualified professional engineering and geological personnel with specific reservoir experience and investment in on-going education with emphasis on emerging technologies. These emerging technologies
are of particular importance as they relate to our shale plays. We also retain outside independent engineering firms to prepare estimates of our Proved Reserves. Our Vice President of Engineering oversees Lee Keeling and Haas Engineering in
connection with the preparation of estimates of our Proved Reserves. Our Vice President of Engineering is a registered Professional Engineer and has served in various leadership roles with the Gas Research Institute, the Society of Petroleum
Engineers and the Society of Women Engineers over her 32 years in the oil and gas industry. She is a graduate of Pennsylvania State University (1978) with a degree in Petroleum and Natural Gas Engineering. During her career, our Vice President
of Engineering has been involved in oil and natural gas reserves analysis and estimation for both major oil companies and independents. Our internal audit function routinely tests our processes and controls and estimated Proved Reserve computations.
Senior management reviews and approves our reserve estimates, whether prepared internally or by third parties. Our Chief Operating Officer and our Vice President of Engineering, with input from other members of senior management, are responsible for
the selection of our third-party engineering firms and receive the reports generated by such firms. The third-party engineering reports are provided to our audit committee, which meets periodically with the engineering firms to review and
discuss the procedures for determining the estimates of our oil and natural gas reserves.

The estimates of Proved Reserves
and future net cash flow attributable to our interests, presented as of December 31, 2009, 2008 and 2007 have been prepared by Lee Keeling, our external engineers for our non-shale



14



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properties, and Haas Engineering our external engineers for our shale properties for 2009. Lee Keeling and Haas Engineering are independent petroleum engineering firms that perform a variety of
reserve engineering and valuation assessments for public and private companies, financial institutions and institutional investors. Lee Keeling has performed these services for over 50 years and Haas Engineering was founded in 1980. We selected Haas
Engineering to prepare our estimates of Proved Reserves for our shale properties based upon their specific experience in performing services to industry peers with shale operations. Our internal technical employees responsible for reserve estimates
and interaction with our independent engineers include corporate officers with petroleum and other engineering degrees, professional certifications and industry experience similar to those of our independent engineering firms. The estimates of
future plugging and abandonment costs necessary to compute PV-10 and Standardized Measure were computed internally. 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
on various assumptions, including definitions and economic assumptions required by the SEC, including the use of constant oil and natural gas pricing, use of current and constant operating costs and future capital costs. We also make assumptions
relating to availability of funds and timing of capital expenditures for development of our proved undeveloped reserves. The production profiles in the Haynesville shale are in their early stages. As a result, the assumptions used for our
Haynesville well and reservoir characteristics and performance are subject to further refinement as more production history is accumulated. 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 (unaudited) of the notes to our consolidated financial statements for additional
information regarding our oil and natural gas reserves and our Standardized Measure.

Lee Keeling and Haas Engineering 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 our Proved
Reserves and future net cash flows attributable to our interests, Lee Keeling and Haas Engineering did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and
natural 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 the
examination something came to the attention of Lee Keeling or Haas Engineering which brought into question the validity or sufficiency of any such information or data, Lee Keeling or Haas Engineering 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 and Haas Engineering determined that our estimates of Proved Reserves conform to the guidelines of the SEC,
including the criteria of reasonable certainty, as it pertains to expectations about the recoverability of Proved Reserves in future years, under existing economic and operating conditions, consistent with the definition in
Rule 4-10(a)(24) of SEC Regulation S-X.



15



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Managements discussion and analysis of oil and natural gas reserves

The following discussion and analysis of our proved oil and natural gas reserves and changes in our Proved Reserves is intended to provide
additional guidance on the operational activities, transactions, economic and other factors which significantly impacted the determination of our estimate of Proved Reserves as of December 31, 2009 and changes in our Proved Reserves during
2009. This discussion and analysis should be read in conjunction with our supplemental oil and gas disclosures relating to oil and natural gas producing activities included in Note 21. Supplemental information relating to oil and natural gas
producing activities (unaudited) of the notes to our consolidated financial statements and the uncertainties inherent in the estimation of oil and natural gas reserves discussed under risk factors included elsewhere in this Annual Report
on Form 10-K. The following table summarizes the significant changes in our Proved Reserves from January 1, 2009 to December 31, 2009.



|                                                     |  |           |         |   |                  |  |           |                             |  |  |           |  
|---------------------------------------------------- |  | --------- | ------- | - | ---------------- |  | --------- | --------------------------- |  |  | --------- | -
|(in thousands)                                       |  | Oil(Bbls) |         |   | Natural gas(Mcf) |  |           | Equivalentnatural gas(Mcfe) | 
|Proved developed                                     |  |           | 3,505   |   |                  |  | 622,160   |                             |  |  | 643,190   |  
|Proved undeveloped                                   |  |           | 2,013   |   |                  |  | 303,568   |                             |  |  | 315,646   |  
|                                                     |  |           |         |   |                  |  |           |                             |  |  |           |  
|Total                                                |  |           | 5,518   |   |                  |  | 925,728   |                             |  |  | 958,836   |  
|                                                     |  |           |         |   |                  |  |           |                             |  |  |           |  
|The changes in reserves for the year are as follows: |  |           |         |   |                  |  |           |                             |  |  |           |  
|January 1, 2009                                      |  |           | 20,801  |   |                  |  | 1,815,138 |                             |  |  | 1,939,944 |  
|Purchase of reserves in place                        |  |           |        |   |                  |  | 8,065     |                             |  |  | 8,065     |  
|Extensions and discoveries                           |  |           | 202     |   |                  |  | 240,844   |                             |  |  | 242,056   |  
|Revisions of previous estimates:                     |  |           |         |   |                  |  |           |                             |  |  |           |  
|Changes in price                                     |  |           | (1,482  | ) |                  |  | (249,948  | )                           |  |  | (258,840  | )
|Changes in performance                               |  |           | 124     |   |                  |  | (54,613   | )                           |  |  | (53,869   | )
|Sales of reserves in place                           |  |           | (12,556 | ) |                  |  | (715,023  | )                           |  |  | (790,359  | )
|Production                                           |  |           | (1,571  | ) |                  |  | (118,735  | )                           |  |  | (128,161  | )
|                                                     |  |           |         |   |                  |  |           |                             |  |  |           |  
|December 31, 2009                                    |  |           | 5,518   |   |                  |  | 925,728   |                             |  |  | 958,836   |  
|                                                     |  |           |         |   |                  |  |           |                             |  |  |           |  

Current year oil and natural gas production

Total oil and natural gas production in 2009 was 128.2 Bcfe, which includes approximately 14.3 Bcfe in production from 2009 extensions and
discoveries that were not reflected in our beginning of the year Proved Reserves.

Sales of reserves in place

During 2009, we implemented a program to divest certain non-strategic oil and natural gas assets and to seek a joint venture partner to
facilitate more rapid development of our shale resources in East Texas/North Louisiana. These divestitures, including the BG Upstream Transaction significantly reduced our Proved Reserves. A total of 790.4 Bcfe were sold in these transactions,
representing approximately 40% of our beginning of the year total Proved Reserves.The divestiture program, which included an exit from several operating areas, including our Mid-Continent region and operations in the state of Ohio, provided
substantial liquidity to fund our Haynesville development program and Marcellus testing program. The BG Upstream Transaction provided additional liquidity with which to further develop our streamlined asset portfolio.

New discoveries and extensions

EXCO had extensions and discoveries of 242.1 Bcfe of Proved Reserves additions in 2009. Approximately 204.7 Bcfe, or 84.6%, of the extensions and discoveries, were from our Haynesville shale play efforts.
The majority of EXCOs Haynesville shale development has been concentrated in 89 contiguous sections in DeSoto Parish, Louisiana, where our drilling results have been the most successful. We have booked an average of two and one-half proved
undeveloped offsetting locations adjacent to each producing horizontal well drilled in the



16



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Haynesville shale play. EXCOs Proved Undeveloped Reserves, or PUD Reserves, represent 32.9% of our total Proved Reserves with the Haynesville shale representing about 38.1% of our total PUD
Reserves at year end.

Revisions of previous estimates

Revisions in 2009 include negative revisions due to prices and other economic factors of 258.8 Bcfe. Net negative revisions resulting from performance issues totaled 53.9 Bcfe, primarily due to decreases
of 65.0 Bcfe in our Appalachia division, which were partially offset by positive revisions in East Texas/North Louisiana and Permian of 11.1 Bcfe. The primary factor in the revisions due to prices was the use at December 31, 2009 of the simple
average of the trailing twelve month spot price (using the price on the first day of the month) for natural gas pursuant to the new SEC rules. Such average gas price of $3.87 per Mmbtu represented a 32.2% decrease from the December 31, 2008
spot natural gas price of $5.71 per Mmbtu.

Proved undeveloped reserves

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2009:



|                                                                  |  |       |          |  
|----------------------------------------------------------------- |  | ----- | -------- | -
|                                                                  |  | Mmcfe |         
|Proved undeveloped reserves at beginning of year                  |  |       | 496,325  |  
|Purchases of proved undeveloped reserves in place                 |  |       | 7,431    |  
|Sales of proved undeveloped reserves in place during year         |  |       | (191,419 | )
|New discoveries and extensions(1)                                 |  |       | 167,858  |  
|Undeveloped reserves transferred to developed(2)                  |  |       | (21,619  | )
|Revisions of previous estimates or proved undeveloped reserves(3) |  |       | (142,930 | )
|                                                                  |  |       |          |  
|Proved undeveloped reserves at end of year                        |  |       | 315,646  |  
|                                                                  |  |       |          |  



|(1) | Substantially all of the discoveries and extensions of proved undeveloped reserves in 2009 occurred in our East Texas/North Louisiana region, primarily in our
Haynesville shale play.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Capital cost incurred to convert these proved undeveloped reserves to proved developed reserves were $64.9 million.
|--- | -------------------------------------------------------------------------------------------------------------------



|(3) | Negative revisions in our proved undeveloped reserves resulted from pricing and costs (94.4%) and from performance and other factors (5.6%) with over 75% of the
revisions occurring in our East Texas/North Louisiana region.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

During 2009, we incurred a total of $299.8
million in various development and exploration activities which resulted in total discoveries and extensions of approximately 242.1 Bcfe. Most of these additions were in the Haynesville shale play in East Texas/North Louisiana in areas in which
minimal proved undeveloped reserves were attributed as of the beginning of the year, but which became proved during the year.

Impacts
of 2009 changes in reserves on depletion rate and statements of operations

For the year ended December 31, 2009,
a combination of factors resulted in significant impact on our full cost pool and our depreciation, depletion and amortization rate for the year.

Prices and costs

Prices for oil and natural gas used in determining Proved
Reserves at December 31, 2009 using the new SEC rules based on the simple average of spot prices on the first day of the trailing twelve months beginning January 1, 2009 and ending on December 1, 2009, were down 32.2% for natural gas
and up 37.2% for oil when



17



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compared with the year-end December 31, 2008 spot prices. The overall impact of prices and costs resulted in a decrease in our reserves by approximately 287.1 Bcfe, primarily resulting from
the decrease in the natural gas prices. Our oil reserves at December 31, 2009 represent only 3.5% of our total reserves, therefore the increase in oil prices did not have a significant impact on our overall reserves.

Between December 31, 2008 and March 31, 2009, the spot price for natural gas fell from $5.71 to $3.63 per Mmbtu, a $2.08
decrease, or 36.4%. As a result of this decrease, we incurred a ceiling test write-down of $1.3 billion for the quarter ended March 31, 2009. This ceiling write-down reduced the amortizable full cost pool and the depletion rate at
March 31, 2009 by 37.5% to approximately $1.30 per Mcfe. No other ceiling test write-downs were incurred in 2009.

2009 divestitures
and related gains on sales

As previously discussed, we had divestitures, including our BG Upstream Transaction, of Proved
Reserves totaling approximately 790.4 Bcfe. On four of these sales transactions, aggregating 622.8 Bcfe, we recognized gains since reflecting the sales proceeds as a reduction in the full cost pool would have resulted in a significant alteration to
the full cost pool. Divestitures in 2009 did not have a significant impact on our depletion rate after the first quarter ceiling test write-down. Our depletion rate for the last three quarters of 2009 averaged $1.32 per Mcfe.

BG Upstream TransactionBG Carry

The impact from the BG Carry on our depletion rate began during the fourth quarter of 2009, where our depletion rate for the quarter decreased to $1.23 per Mcfe. Continued application of the remaining
balance of $367.7 million of the BG Carry in 2010 and 2011 will reduce our capital requirements in the Haynesville/Bossier shale play exploitation and development and should continue to have a favorable impact on our overall full cost pool
amortization rate.

Our production, prices and expenses

The following table summarizes revenues, 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.



|                                                       |  |                            |         |  |                            |   |           |                            |  |   |         | 
|------------------------------------------------------ |  | -------------------------- | ------- |  | -------------------------- | - | --------- | -------------------------- |  | - | ------- | 
|(in thousands, except production and per unit amounts) |  | Year endedDecember 31,2009 |         |  | Year endedDecember 31,2008 |   |           | Year endedDecember 31,2007 | 
|Revenues, production and prices:                       |  |                            |         |  |                            |   |           |                            |  |   |         | 
|Oil:                                                   |  |                            |         |  |                            |   |           |                            |  |   |         | 
|Revenue(1)                                             |  | $                          | 84,397  |  |                            | $ | 216,727   |                            |  | $ | 117,073 | 
|Production sold (Mbbl)(2)                              |  |                            | 1,571   |  |                            |   | 2,236     |                            |  |   | 1,645   | 
|Average sales price per Bbl(1)                         |  | $                          | 53.72   |  |                            | $ | 96.93     |                            |  | $ | 71.17   | 
|Natural gas:                                           |  |                            |         |  |                            |   |           |                            |  |   |         | 
|Revenue(1)                                             |  | $                          | 466,108 |  |                            | $ | 1,188,099 |                            |  | $ | 758,714 | 
|Production sold (Mmcf)(2)                              |  |                            | 118,736 |  |                            |   | 131,159   |                            |  |   | 111,419 | 
|Average sales price per Mcf(1)                         |  | $                          | 3.93    |  |                            | $ | 9.06      |                            |  | $ | 6.81    | 
|Costs and expenses:                                    |  |                            |         |  |                            |   |           |                            |  |   |         | 
|Average production cost per Mcfe                       |  | $                          | 1.08    |  |                            | $ | 1.11      |                            |  | $ | 0.95    | 
|General and administrative expense per Mcfe            |  | $                          | 0.77    |  |                            | $ | 0.61      |                            |  | $ | 0.53    | 
|Depreciation, depletion and amortization per Mcfe      |  | $                          | 1.72    |  |                            | $ | 3.18      |                            |  | $ | 3.10    | 



|(1) | Excludes the effects of derivative cash settlements and derivative financial instruments.
|--- | -----------------------------------------------------------------------------------------



|(2) | Includes the following significant fields representing 15% or more of our total Proved Reserves at end of each year:
|--- | --------------------------------------------------------------------------------------------------------------------



18



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|                                   |  |                            |        |  |                            |   |        |                             |  |   |        | 
|---------------------------------- |  | -------------------------- | ------ |  | -------------------------- | - | ------ | --------------------------- |  | - | ------ | 
|                                   |  | Year endedDecember 31,2009 |        |  | Year endedDecember 31,2008 |   |        | Year endedDecember 
31,2007 | 
|Vernon Field:                      |  |                            |        |  |                            |   |        |                             |  |   |        | 
|Oil production sold (Mbbls)        |  |                            | 4      |  |                            |   | 7      |                             |  |   | 12     | 
|Natural gas production sold (Mmcf) |  |                            | 35,146 |  |                            |   | 43,519 |                             |  |   | 39,039 | 
|Average price per Bbl(1)           |  | $                          | 58.95  |  |                            | $ | 105.64 |                             |  | $ | 73.78  | 
|Average price per Mcf(1)           |  | $                          | 3.57   |  |                            | $ | 8.45   |                             |  | $ | 6.42   | 
|Average production cost per Mcfe   |  | $                          | 0.83   |  |                            | $ | 0.62   |                             |  | $ | 0.34   | 
|Haynesville Shale:                 |  |                            |        |  |                            |   |        |                             |  |   |        | 
|Natural gas production sold (Mmcf) |  |                            | 14,917 |  |                            |   | *      |                             |  |   | *      | 
|Average price per Mcf(1)           |  | $                          | 3.21   |  |                            |   | *      |                             |  |   | *      | 
|Average production cost per Mcfe   |  | $                          | 0.10   |  |                            |   | *      |                             |  |   | *      | 



|* | Less than 15% of total Proved Reserves.
|- | ---------------------------------------

Our
interest in productive wells

The following table quantifies 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 completions. Gross wells refer to the total number of physical wells
in which we hold a working interest, 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 by totaling the
percentage interests we hold in all our gross wells.



|                           |  |                      |     |  |           |  |       |       |  |  |       |  |  |     |       |  |       |  |         |  |  |  |         | 
|-------------------------- |  | -------------------- | --- |  | --------- |  | ----- | ----- |  |  | ----- |  |  | --- | ----- |  | ----- |  | ------- |  |  |  | ------- | 
|                           |  | At December 31, 2009 |    
|                           |  | Gross wells(1)       |     |  | Net wells | 
|Areas                      |  | Oil                  |     |  | Gas       |  |       | Total |  |  | Oil   |  |  | Gas |       |  | Total | 
|East Texas/North Louisiana |  |                      | 62  |  |           |  | 1,264 |       |  |  | 1,326 |  |  |     | 30.6  |  |       |  | 707.8   |  |  |  | 738.4   | 
|Appalachia                 |  |                      | 365 |  |           |  | 5,793 |       |  |  | 6,158 |  |  |     | 359.2 |  |       |  | 5,234.2 |  |  |  | 5,593.4 | 
|Permian and other          |  |                      | 270 |  |           |  | 89    |       |  |  | 359   |  |  |     | 242.0 |  |       |  | 50.5    |  |  |  | 292.5   | 
|                           |  |                      |     |  |           |  |       |       |  |  |       |  |  |     |       |  |       |  |         |  |  |  |         | 
|Total                      |  |                      | 697 |  |           |  | 7,146 |       |  |  | 7,843 |  |  |     | 631.8 |  |       |  | 5,992.5 |  |  |  | 6,624.3 | 
|                           |  |                      |     |  |           |  |       |       |  |  |       |  |  |     |       |  |       |  |         |  |  |  |         | 



|(1) | As of December 31, 2009, we held interests in 23 gross wells with multiple completions.
|--- | ---------------------------------------------------------------------------------------

As of December 31, 2009, we were the operator of 7,416 gross (6,524.7 net) wells, which represented approximately 97.0% of our
Proved Reserves as of December 31, 2009.

Our drilling activities

In 2009, we shifted our drilling emphasis toward horizontal drilling in shale plays. Prior to 2009, our drilling emphasis was vertical
development projects. 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, commodity prices, the estimated
recoverable reserves attributable to each well and accessibility to the well site.



19



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The following tables summarize our approximate gross and net interests in the wells we
drilled during the periods indicated and refer to the number of wells completed at any time during the period, regardless of when drilling was initiated. At December 31, 2009, we had 15 gross (6.8 net) wells being drilled and 13 gross (6.6 net)
wells being completed.



|                                |  |                   |     |  |     |  |   |       |  |  |            |  |  |     |       |  |       |  |     |  |  |  |       | 
|------------------------------- |  | ----------------- | --- |  | --- |  | - | ----- |  |  | ---------- |  |  | --- | ----- |  | ----- |  | --- |  |  |  | ----- | 
|                                |  | Development Wells |    
|                                |  | Gross             |     |  | Net | 
|                                |  | Productive        |     |  | Dry |  |   | Total |  |  | Productive |  |  | Dry |       |  | Total | 
|Year ended December 31, 2009    |  |                   | 82  |  |     |  | 1 |       |  |  | 83         |  |  |     | 40.8  |  |       |  | 0.9 |  |  |  | 41.7  | 
|Year ended December 31, 2008    |  |                   | 447 |  |     |  | 4 |       |  |  | 451        |  |  |     | 374.2 |  |       |  | 2.5 |  |  |  | 376.7 | 
|Year ended December 31, 2007    |  |                   | 487 |  |     |  | 7 |       |  |  | 494        |  |  |     | 394.7 |  |       |  | 4.6 |  |  |  | 399.3 | 
|                                | 
|                                |  | Exploratory Wells |    
|                                |  | Gross             |     |  | Net | 
|                                |  | Productive        |     |  | Dry |  |   | Total |  |  | Productive |  |  | Dry |       |  | Total | 
|Year ended December 31, 2009(1) |  |                   | 19  |  |     |  | 1 |       |  |  | 20         |  |  |     | 12.2  |  |       |  | 1.0 |  |  |  | 13.2  | 
|Year ended December 31, 2008    |  |                   | 20  |  |     |  | 4 |       |  |  | 24         |  |  |     | 19.3  |  |       |  | 3.5 |  |  |  | 22.8  | 
|Year ended December 31, 2007    |  |                   | 8   |  |     |  | 4 |       |  |  | 12         |  |  |     | 2.5   |  |       |  | 3.4 |  |  |  | 5.9   | 



|(1) | Our classifications of exploratory wells for 2009 include Haynesville shale wells located outside of DeSoto Parish, Louisiana and all East Texas counties and all
Marcellus shale wells. We also classify our Bossier shale test wells as exploratory projects. Haynesville shale drilling in DeSoto Parish, Louisiana has been classified as development.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Our developed and undeveloped acreage

Developed acreage includes those acres spaced or assignable to producing wells. Undeveloped acreage represents 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, 2009:



|                           |  |                      |         |  |                     |  |         |       |  |  |         |  |  |  |         | 
|-------------------------- |  | -------------------- | ------- |  | ------------------- |  | ------- | ----- |  |  | ------- |  |  |  | ------- | 
|                           |  | At December 31, 2009 |        
|                           |  | Developed acreage    |         |  | Undeveloped acreage | 
|Areas                      |  | Gross                |         |  | Net(1)              |  |         | Gross |  |  | Net(1)  | 
|East Texas/North Louisiana |  |                      | 166,219 |  |                     |  | 88,469  |       |  |  | 99,828  |  |  |  | 67,476  | 
|Appalachia                 |  |                      | 376,705 |  |                     |  | 335,351 |       |  |  | 349,794 |  |  |  | 318,817 | 
|Permian and other          |  |                      | 28,532  |  |                     |  | 18,829  |       |  |  | 161,527 |  |  |  | 118,591 | 
|                           |  |                      |         |  |                     |  |         |       |  |  |         |  |  |  |         | 
|Total                      |  |                      | 571,456 |  |                     |  | 442,649 |       |  |  | 611,149 |  |  |  | 504,884 | 
|                           |  |                      |         |  |                     |  |         |       |  |  |         |  |  |  |         | 



|(1) | Net acreage at December 31, 2009 reflects a reduction of 7,341 acres that BG Group elected to acquire after December 31, 2009, pursuant to the BG AMI.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------

The primary terms of our oil and natural gas leases expire at various dates. Much 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 38,638, 95,851 and 25,557 net acres with leases expiring in 2010, 2011
and 2012, 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, as well as other non-producing formations, in a given oil or natural gas field without the necessity of
purchasing additional leases or producing properties.



20



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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, properties that are not within our core geographic operating areas and properties that are not strategic. We also seek to opportunistically divest properties in areas in which acquisitions and investment
economics no longer meet our objectives.

Equity investment in midstream operations

On August 14, 2009, we closed the sale to an affiliate of BG Group of a 50% interest in TGGT, which now holds most of our previously
owned East Texas/North Louisiana midstream assets. Pursuant to the contribution agreement, we contributed TGG, which owns an intrastate pipeline in East Texas and a gathering system in North Louisiana and Talco, which owns gathering assets in East
Texas/North Louisiana, to TGGT. BG Group contributed $269.2 million in cash to TGGT and we received those funds from TGGT as a special distribution at closing. EXCO Operating now owns 50% of TGGT and the affiliate of BG Group owns 50% of TGGT. The
effective date of this transaction was January 1, 2009. We adopted the equity method of accounting for our interest in TGGT upon its formation. Prior to August 14, 2009, we treated our midstream operations as a separate segment of our
business.

TGGTs midstream operations are principally designed to facilitate delivery of natural gas produced in the
East Texas/North Louisiana region to markets. Revenues are derived from sales of natural gas purchased for resale and fees earned from gathering, transportation, treating and compression of natural gas. TGGT does not own any natural gas processing
facilities.

In 2009, TGGT undertook a major expansion of its TGG system in North Louisiana in order to take advantage of the
increasing opportunities for gathering of Haynesville/Bossier shale natural gas. The first phase of the expansion was the installation of a header system comprised of approximately 29 miles of 36-inch diameter pipe through the Holly field area,
which is south of Shreveport. The header will primarily gather EXCO and BG Group produced natural gas but will also seek opportunities to gather natural gas from other producers in the area. The system provides producers with dehydration and amine
treating facilities and has connections to major third party interstate pipelines. The majority of the system was completed in the fourth quarter of 2009, and the remaining pipe segment is scheduled to be completed in the first quarter of 2010. TGGT
is currently in the process of evaluating additional opportunities associated with the expansion of this 29-mile pipeline system.

The East Texas TGG system, which gathers natural gas, has access to 12 interstate pipeline markets. The TGG system in East Texas has approximately 110 miles of pipeline comprised of 12, 16, and 20-inch
diameter pipe with a current throughput capacity of approximately 390.0 Mmcf per day without compression. With compression, TGG throughput capacity in East Texas is estimated to be approximately 530.0 Mmcf per day.

TGGT also owns and operates Talco, a network of eight natural gas gathering systems comprised of approximately 615 miles of pipeline in
their East Texas/North Louisiana area of operation, which gathers natural gas produced from the Holly/Caspiana field, Longwood/Waskom fields and other fields in East Texas and North Louisiana and transports the natural gas to TGG and larger
gathering systems and intrastate, interstate and local distribution pipelines owned by third parties. Talco gathers natural gas through fixed fee arrangements pursuant to which the fee income represents an agreed rate per unit of throughput. The
revenues earned from these arrangements are directly related to the volume of natural gas that flows through the systems and are not directly dependent on commodity prices.

Other gas gathering systems

A gathering system and treating facility in
the area of our Vernon Field operations, or Vernon Gathering, gathers and transports natural gas from our Vernon Field and, to a lesser extent, natural gas from third-party



21



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producers. The gathering system transports natural gas to our Caney Lake facility where the natural gas is treated and delivered to interstate pipeline systems. During December 2009, average
throughput in Vernon Gathering was approximately 113.0 Mmcf per day.

Our principal customers

For the year ended December 31, 2009, there were no sales to any individual customer which exceeded 10% of our consolidated revenues
or was considered material to our operations. The loss of any significant customer may cause a temporary interruption in sales of, or 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.

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 other services and securing trained personnel. Competition has also been strong in hiring experienced personnel, particularly in petroleum engineering, geoscience,
accounting and financial reporting, tax and land professions. Many of our competitors have financial, technical and personnel resources 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 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, proppant, pipe and personnel, which have delayed development
drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, shortages may occur or how they will affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties and for undeveloped leases and drilling rights, and we
cannot provide assurance that we will be able to compete satisfactorily.

Applicable laws and regulations

General

The oil
and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, which could increase the regulatory
burden and the potential for financial sanctions for noncompliance. 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.



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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:



| |  |  | the location of wells;
| | - |  | ----------------------



| |  |  | the method of drilling and casing wells;
| | - |  | ----------------------------------------



| |  |  | the surface use and restoration of properties upon which wells are drilled;
| | - |  | ---------------------------------------------------------------------------



| |  |  | the plugging and abandoning of wells; and
| | - |  | -----------------------------------------



| |  |  | notice to surface owners and other third parties.
| | - |  | -------------------------------------------------

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 requiring production in a prorated, equitable system. 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, ad valorem 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 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



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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 Minerals Management Service or other appropriate federal or state agencies.

Surface Damage
Acts

In addition, eleven states and some tribal nations have enacted surface damage statutes
(SDAs). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most
also contain bonding requirements and specific expenses for exploration and activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

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 Liquid 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 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 mandates a number of other requirements, including increased penalties for violations of safety standards and qualification 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.



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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. Federal environmental statutes to which
our domestic activities are subject include, but are not limited to:



| |  |  | the Oil Pollution Act of 1990, or OPA;
| | - |  | --------------------------------------



| |  |  | the Clean Water Act, or CWA;
| | - |  | ----------------------------



| |  |  | the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | the Resource Conservation and Recovery Act, or RCRA;
| | - |  | ----------------------------------------------------



| |  |  | the Clean Air Act, or CAA; and
| | - |  | ------------------------------



| |  |  | the Safe Drinking Water Act, or SDWA.
| | - |  | -------------------------------------

Our domestic activities are subject to regulations promulgated under these statutes and 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 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 we undertake certain activities, limit or prohibit other activities because of protected areas or species, impose certain substantial liabilities for
the clean-up of pollution, impose certain reporting requirements, regulate remedial plugging operations to prevent future contamination, and 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 the 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) specified damages, such as loss of use, property
damage and natural resource damages. The scope 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 into waters of the United States, including certain wetlands, of dredged materials, which may apply to various of our construction activities, as well as 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.

CERCLA, as amended, and comparable state Superfund statutes, impose liability that is generally joint and several and that is retroactive 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 or under state law, other specified substances, into the environment. 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 Environmental Protection Agency, or 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



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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 or regulated under 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. 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.

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.

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, in addition to 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 non-hazardous solid waste in our routine operations. It is possible that certain wastes generated by our operations, which are currently exempt from hazardous waste
regulations under RCRA, may in the future be designated as hazardous waste under RCRA or other applicable state statutes and become subject to more rigorous and costly management and disposal requirements.

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The CAA
and analogous state laws require certain new and modified sources of air pollutants to obtain permits prior to commencing construction. Smaller sources may qualify for exemption from permit requirements through qualifications for 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.

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.



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

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

The Environmental Protection Agency has also
taken recent action related to greenhouse gases. On December 7, 2009, the U.S. Environmental Protection Agency, or EPA, issued a notice of its finding and



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determination that emissions of carbon dioxide, methane, and other GHGs may reasonably be anticipated to endanger human health and the environment by, among other things, increasing ground-level
ozone, altering the climate, contributing to a rise in sea levels, and harming water resources, agriculture, wildlife, and ecosystems. Once EPA promulgates regulations controlling GHG emissions, for example, regarding emissions from motor vehicles,
which EPA has indicated may occur in 2010, EPA will be required to begin regulating emissions of GHGs under existing permitting provisions of the federal Clean Air Act. Those permitting provisions could require controls or other measures to reduce
GHG emissions from new or modified sources, and we could incur additional costs to satisfy those permitting requirements. EPA has proposed a Tailoring Rule to regulate the permitting of GHG sources under the Clean Air Acts PSD and
Title V programs. Although it may take EPA several years to adopt and impose regulations limiting stationary source emissions of GHGs, any limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce
emissions of GHGs associated with our operations. On September 22, 2009, EPA finalized a GHG reporting rule that will require large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. Although this
rule does not limit the amount of GHGs that can be emitted, it could require us to incur costs to monitor, recordkeep and report emissions of GHGs associated with our operations.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic
fracturing operations and require reporting and disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock
formations to stimulate natural gas production. Sponsors of bills pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. These bills, if
adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making
it more difficult to perform hydraulic fracturing and increasing our costs of compliance.

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.

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:



| |  |  | customary royalty and overriding royalty interests;
| | - |  | ---------------------------------------------------



| |  |  | liens incident to operating agreements; and
| | - |  | -------------------------------------------



| |  |  | liens for current taxes and other burdens and minor encumbrances, easements and restrictions.
| | - |  | ---------------------------------------------------------------------------------------------



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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, 2009, we employed 802 persons. 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 and contractors.

Forward-looking statements

This Annual Report on Form 10-K contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933
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:



| |  |  | our future financial and operating performance and results;
| | - |  | -----------------------------------------------------------



| |  |  | our business strategy;
| | - |  | ----------------------



| |  |  | market prices;
| | - |  | --------------



| |  |  | our future use of derivative financial instruments; and
| | - |  | -------------------------------------------------------



| |  |  | our plans and forecasts.
| | - |  | ------------------------

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

We use the words may, expect, anticipate, estimate, believe, continue, intend, plan, budget and
other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or
state other forward-looking information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause
our actual results or financial condition to materially differ from our expectations in this Annual Report on Form 10-K, including, but not limited to:



| |  |  | fluctuations in prices of oil and natural gas;
| | - |  | ----------------------------------------------



| |  |  | imports of foreign oil and natural gas, including liquefied natural gas;
| | - |  | ------------------------------------------------------------------------



| |  |  | future capital requirements and availability of financing;
| | - |  | ----------------------------------------------------------



| |  |  | continued disruption of credit and capital markets and the ability of financial institutions to honor their commitments, such as the events which
occurred during the third quarter of 2008 and thereafter, for an extended period of time;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | estimates of reserves and economic assumptions used in connection with our acquisitions;
| | - |  | ----------------------------------------------------------------------------------------



| |  |  | geological concentration of our reserves;
| | - |  | -----------------------------------------



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| |  |  | risks associated with drilling and operating wells;
| | - |  | ---------------------------------------------------



| |  |  | exploratory risks, including our Marcellus shale play in Appalachia and the Haynesville/Bossier shale play in East Texas/North Louisiana;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------



| |  |  | risks associated with the operation of natural gas pipelines and gathering systems;
| | - |  | -----------------------------------------------------------------------------------



| |  |  | discovery, acquisition, development and replacement of oil and natural gas reserves;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | cash flow and liquidity;
| | - |  | ------------------------



| |  |  | timing and amount of future production of oil and natural gas;
| | - |  | --------------------------------------------------------------



| |  |  | availability of drilling and production equipment;
| | - |  | --------------------------------------------------



| |  |  | marketing of oil and natural gas;
| | - |  | ---------------------------------



| |  |  | developments in oil-producing and natural gas-producing countries;
| | - |  | ------------------------------------------------------------------



| |  |  | title to our properties;
| | - |  | ------------------------



| |  |  | litigation;
| | - |  | -----------



| |  |  | competition;
| | - |  | ------------



| |  |  | general economic conditions, including costs associated with drilling and operations of our properties;
| | - |  | -------------------------------------------------------------------------------------------------------



| |  |  | environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases;
| | - |  | ---------------------------------------------------------------------------------------------------------------



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



| |  |  | decisions whether or not to enter into derivative financial instruments;
| | - |  | ------------------------------------------------------------------------



| |  |  | potential acts of terrorism;
| | - |  | ----------------------------



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



| |  |  | fluctuations in interest rates; and
| | - |  | -----------------------------------



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

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the
future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, 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 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.



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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.

2-D seismic.Geophysical data that depict the subsurface strata in two
dimensions

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.

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.

Deterministic
estimate.    The method of estimating reserves or resources when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

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

Developed Reserves.    Developed oil and gas reserves are reserves of
any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.

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.



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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.

Economically producible.    As it relates to a resource, a resource which generates revenue that exceeds, or
is reasonably expected to exceed, the costs of the operation.

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 a new field or to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir.

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.

Fracture Stimulation.A stimulation treatment routinely performed involving the injection of
water, sand and chemicals under pressure to stimulate hydrocarbon production in low-permeability reservoirs.

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.

Held-by-production.    A provision in an oil, gas and mineral lease that perpetuates a
companys right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas.

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.

Initial production rate.    Generally, the maximum 24 hour production volume from a well.

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.



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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.

Play.A term applied to a portion of the exploration and production cycle following the identification by
geologists and geophysicists of areas with potential oil and gas reserves.

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 future 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 have been made using constant oil and natural gas
prices and operating and capital 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.

Probabilistic estimate.The method of estimation of reserves
or resources when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

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

Proved Reserves.    Those quantities of oil and gas, which, by analysis of geoscience and engineering data,
can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of
the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous
with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.



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In the absence of data on fluid contacts, proved quantities in a reservoir are limited by
the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has
defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and
reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically
through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more
favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the
project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the
ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based
upon future conditions.

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.

Reasonable certainty.    If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic
methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes
due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant
than to decrease.

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 the annualized average daily production volumes for December 2009.

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.

Resources.    All quantities of petroleum naturally occurring on or within the Earths crust, discovered
and undiscovered (recoverable and unrecoverable), plus those quantities already produced. It also includes all types of petroleum whether currently considered conventional or unconventional.

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.

Shale.Fine-grained sedimentary rock
composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Spud.    To start the well drilling process.



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Standardized Measure of discounted future net cash flows or the Standardized
Measure.    Under the Standardized Measure, future cash flows for the year ended December 31, 2009 are estimated by applying the simple average spot prices for the trailing twelve month period using the first day of each
month beginning on January 1, 2009 and ended December 1, 2009, adjusted for fixed and determinable escalations, to the estimated future production of year-end Proved Reserves. Spot prices used to compute estimated future cash flows for the
years ended December 31, 2008 and 2007 were based on year-end spot prices for each respective year. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment
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.

Undeveloped Reserves.    Reserves of any category 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 directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic
producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific
circumstances, justify a longer time.

Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir or by other evidence using
reliable technology establishing reasonable certainty.

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 at www.excoresources.com as soon as reasonably
practicable after those reports and other information are electronically filed with or furnished to the SEC.



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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 Form 10-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 exploration, exploitation, development and production of onshore North
American oil and natural gas properties. Our principal operations are conducted in the East Texas/North Louisiana, Appalachia and Permian producing areas. In addition to our oil and natural gas producing operations, we hold a 50% equity interest in
a joint venture which owns gathering systems and pipelines in East Texas/North Louisiana. Our assets in East Texas/North Louisiana, including our equity interest in midstream operations, are owned by our subsidiary, EXCO Operating. Organizationally,
EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operatings debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources debt.

Historically, we used acquisitions and vertical drilling as our vehicle for growth. As a result of our acquisitions, we accumulated an
inventory of drilling locations and acreage holdings with significant potential in the Haynesville/Bossier and Marcellus shale resource plays. This shale potential has allowed us to shift our focus to exploit these shales, primarily through
horizontal drilling. Future acquisitions are likely to be focused on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We will continue to develop certain vertical drilling opportunities in our East
Texas/North Louisiana, Appalachia and Permian areas as industry economic conditions permit.

We currently have two credit
agreements with a combined borrowing base of $1.3 billion, of which $747.6 million was drawn as of December 31, 2009. The EXCO Resources Credit Agreement has a borrowing base of $450.0 million and the EXCO Operating Credit Agreement has a
borrowing base of $850.0 million. We expect to continue to grow by leveraging our management and technical teams experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations,
accumulating undeveloped acreage in shale areas, exploitation projects and entering into joint venture transactions. We employ the use of debt along with a comprehensive derivative financial instrument program to mitigate commodity price volatility
to support our strategy.

As of December 31, 2009, the PV-10 and the Standardized Measure of our Proved Reserves was
approximately $747.7 million (see Item 1. Summary of geographic areas of operations for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the year ended December 31, 2009, we produced 128.2 Bcfe of oil and
natural gas. Based on our December 2009 average daily production of 224.0 Mmcfe, this translates to a reserve life of approximately 11.7 years. We used annualized December 2009 production, rather than actual 2009 production, to calculate
our reserve life as of December 31, 2009 due to the significant reduction in production resulting from divestitures of proved producing reserves during 2009

In 2009, we drilled 103 wells and completed 101 gross (53.0 net) wells with 98.1% drilling success rate. Our 2009 development, exploitation and other oil and natural gas property capital expenditures
totaled $299.8 million. In addition, we leased $106.0 million of undeveloped acreage primarily in the Haynesville/Bossier shale resource play in East Texas/North Louisiana. Midstream capital expenditures, prior to the formation of TGGT, were $53.1
million and corporate capital expenditures totaled an additional $52.5 million. In addition, we



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completed $233.6 million of acquisitions, which were mostly undeveloped acreage in the Haynesville shale resource play.

During 2009, we also completed sales of certain non-strategic assets pursuant to a previously announced divestiture program and entered into joint venture transactions with BG Group, resulting in net cash
proceeds of approximately $2.1 billion after closing adjustments.

The following table summarizes our 2009 divestitures and
joint venture transactions:



|                                      |  |              |           | 
|------------------------------------- |  | ------------ | --------- | 
|(in thousands)                        |  | Proceeds (1) |          
|Operating division                    |  |              |           | 
|East Texas/North Louisiana            |  |              |           | 
|BG Upstream Transaction               |  | $            | 713,779   | 
|BG Midstream Transaction              |  |              | 269,237   | 
|East Texas Transaction                |  |              | 154,299   | 
|Other East Texas/North Louisiana      |  |              | 22,327    | 
|                                      | 
|Mid-Continent                         |  |              |           | 
|Mid-Continent Transaction             |  |              | 197,730   | 
|Sheridan Transaction(2)               |  |              | 531,351   | 
|Other Mid-Continent                   |  |              | 5,482     | 
|                                      | 
|Appalachia                            |  |              |           | 
|EnerVest Transaction(2)(3)            |  |              | 129,737   | 
|Permian                               |  |              | 40,042    | 
|                                      |  |              |           | 
|Total joint ventures and divestitures |  | $            | 2,063,984 | 
|                                      |  |              |           | 



|(1) | Net of selling expenses.
|--- | ------------------------



|(2) | Subject to final closing adjustments.
|--- | -------------------------------------



|(3) | Pending receipt of an additional $13.1 million of consents.
|--- | -----------------------------------------------------------

Our plans for 2010 are focused on the Haynesville/Bossier and Marcellus shales. Our budgeted capital expenditures total $471.4 million, of which $409.4 million is allocated to our East Texas/North
Louisiana and Appalachia regions. In East Texas and North Louisiana, our capital expenditures in the BG AMI are expected to total $740.8 million, with EXCOs share being only $165.3 million, which reflects the favorable impact of the BG Carry.
In Appalachia, our planned capital expenditures total $154.2 million.

The 2010 capital budget includes $39.1 million for
midstream activities, including a $7.8 million equity contribution to TGGT. TGGT is the newly formed midstream joint venture owned equally by EXCO and BG Group. TGGT owns the midstream assets located within the BG AMI in East Texas and North
Louisiana. The TGGT capital budget for 2010 is $101.0 million, $50.5 million net to EXCOs interest. This budget will be mostly funded by internal TGGT cash flow. The management of TGGT is also evaluating several expansion projects which, if
approved, will require additional capital contributions.

Like all oil and natural gas production companies, we face the
challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to identify and develop additional reserves and add additional reserves
through acquisitions. As of December 31, 2009, 96.5% of our estimated Proved Reserves were natural gas. Consequently, our results of operations are particularly impacted by natural gas markets.

The impact of our 2009 divestitures and joint ventures with BG Group resulted in significant reductions to our Proved Reserves,
production volumes, revenue and operating expenses. While the reductions will have a near-term impact on our results of operations, we believe the benefits from the liquidity provided by these



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transactions and the BG Carry will allow us to accelerate development of our reserves and resources including our shale development and will more than compensate for these reductions.

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:



| |  |  | the quality and quantity of available data;
| | - |  | -------------------------------------------



| |  |  | the interpretation of that data;
| | - |  | --------------------------------



| |  |  | the accuracy of various mandated economic assumptions; and
| | - |  | ----------------------------------------------------------



| |  |  | the technical qualifications, experience and judgment of the persons preparing the estimates.
| | - |  | ---------------------------------------------------------------------------------------------

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. The assumptions used for our
Haynesville well and reservoir characteristics and performance are subject to further refinement as more production history is accumulated.

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 according to the requirements in the SECs Release No. 33-8995 Modernization of Oil and Gas Reporting, or Release No. 33-8995. Actual future prices and costs may be materially
higher or lower than the prices and costs used in the preparation 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, making 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 those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given
date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that



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renewal is reasonably certain, regardless of whether the estimates is a deterministic estimate or probabilistic estimate. The project to extract the hydrocarbons must have commenced, or the
operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir
considered as proved includes both the area identified by drilling and limited by fluid contacts, if any, and adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil and gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration
unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher
portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when successful
testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology
establishes the reasonable certainty of the engineering analysis on which the project or program was based, and the project has been approved for development by all necessary parties and entities, including governmental entities.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Existing economic
conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an
unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Business combinations

For the periods covered by this Annual Report on Form 10-K, we use FASB ASC Subtopic 805-10 for Business Combinations to record our acquisitions of oil and natural gas properties or entities which we
acquire beginning January 1, 2009. ASC 805-10 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 ASC 805-10
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 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.



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Share-based payments

We account for share-based payments to employees using the methodology prescribed in FASB ASC Topic 718 for CompensationStock Compensation Topic. At December 31, 2009, our employees and
directors held options under EXCOs 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 16,454,294 shares of EXCO common stock at prices ranging from $6.33 per share to $38.01 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 $2.28 per share to $14.27 per share. ASC Topic 718 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 2009 was $24.1 million, of which $5.1 million
was capitalized as part of our oil and natural gas properties. In 2008 and 2007, a total of $20.0 million and $15.0 million, respectively, of share-based compensation was incurred, of which $4.0 million and $2.4 million, respectively, was
capitalized.

Accounting for oil and natural gas properties

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

We use the full cost method of accounting, which involves capitalizing all
acquisition, exploration, exploitation and development costs 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 a quarterly basis to assess possible impairment or the need to transfer unproved costs to proved properties as a result of extension or
discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease
and well equipment and exploration and development costs incurred plus costs of acquired proved and unproved leaseholds.

During April 2008 we initiated leasing projects to acquire shale drilling rights in both our Appalachia and East Texas/North Louisiana
operating areas. In accordance with our policy and FASB ASC Subtopic 835-20 for Capitalization of Interest, we began capitalizing interest on unproved properties.

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 quantity 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.

Under the full cost method of accounting, sales,
dispositions and other oil and natural gas property retirements are generally accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the relationship between
capitalized costs and Proved Reserves. During 2009, our BG Upstream Transaction, Mid-Continent Transaction, East Texas Transaction and Sheridan Transaction resulted in significant alterations to our full cost depletion pool and we determined that
gain recognition was appropriate for these transactions. Gain or loss recognition on divestiture or abandonment of oil and natural gas properties where disposition would result in a significant alteration of the depletion rate requires allocation of
a portion of the amortizable full cost pool based on the relative estimated fair value of the disposed oil and natural gas properties to the estimated fair value of total Proved Reserves. As discussed under Estimates of Proved Reserves,
estimating oil and natural gas reserves involves numerous assumptions.



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Prior to our December 31, 2009 adoption of Release No. 33-8995, at the end of each
quarterly period the unamortized cost of oil and natural gas properties, net of related deferred income taxes, was limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our Proved Reserves using period-end
prices, discounted at 10%, and adjusted for related income tax effects (ceiling test). In the event our capitalized costs exceeded the ceiling limitation at the end of the reporting period, we subsequently evaluated the limitation for price changes
occurring after the balance sheet date to assess impairment. Beginning December 31, 2009, Release No. 33-8995 requires that the full cost ceiling be computed as the sum of the estimated future net revenues from Proved Reserves using the
average, first-day-of-the-month price during the previous 12-month period, discounted at 10% and adjusted for related income tax effects. The new rule no longer allows a company to subsequently evaluate the limitation for subsequent prices changes.
Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the
impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling
test results.

For the year 2007, we sought and received exemptions from the Securities and Exchange Commission, or the SEC,
in July 2007 to exclude three significant proved oil and natural gas property acquisitions which closed in late 2006 and during the first half of 2007 from our ceiling test computation for a period of 12 months from the closing date of each
acquisition. There were no ceiling test exemptions in effect for any acquisitions for the years ended December 31, 2009 and 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

A
change in control transaction involving an equity buyout on October 3, 2005, required the application of the purchase method of accounting pursuant to ASC 805-10 and goodwill of $220.0 million was recognized. Additional goodwill of
$250.1 million was recognized from our 2006 acquisitions.

The BG Upstream Transaction, the East Texas Transaction, the
Mid-Continent Transaction and the Sheridan Transaction each caused significant alterations to our depletion rate and we therefore evaluated the goodwill associated with these properties. As a result of our analysis, we eliminated $177.6 million of
goodwill by reducing the gains associated with these transactions. In addition, the BG Midstream Transaction triggered the write off of $11.4 million of goodwill against the associated gain and the transfer of $11.4 million of goodwill to the TGGT
investment.

As of December 31, 2009, our consolidated goodwill totals $269.7 million. Not all of our goodwill is
currently deductible for income tax purposes. Furthermore, in accordance with FASB ASC Topic 350-Intangibles Goodwill and Other, 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. We use a combination of valuation
techniques, including discounted cash flow projections and market comparable analyses to evaluate our goodwill for possible impairment. 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. As of December 31, 2009, we did not have any impairment of our goodwill.



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Asset retirement obligations

We follow FASB ASC Subtopic 410-20 for Asset Retirement Obligations to account for legal obligations associated with the retirement of
long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated 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 FASB ASC Topic 740 for Income Taxes. 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.

Recent accounting pronouncements

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

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

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

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural
gas reporting requirements for oil and natural gas producing companies. On January 16, 2010, the Financial Accounting Standards Board, or the FASB, issued Update No. 2010-03Extractive ActivitiesOil and Gas (Topic 932): Oil and
Gas Reserve Estimation and Disclosures, or Update No. 2010-03, to align the oil and gas reserve estimation and disclosure requirements of the Codification with Release No. 33-8995.



42



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The effective date of the new accounting and disclosure requirements is for annual reports
filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date.

Among other things, Release No. 33-8995 and the Update No. 2010-03:



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



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



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



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



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



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

The impact of the
adoption of this statement can be seen in our disclosures in Item 1. Business. The change in the calculation of pricing resulted in prices of $3.87 per Mmbtu for Henry Hub and $61.18 per Bbl for Cushing, Oklahoma instead of the
December 31, 2009 spot price of $5.79 per Mmbtu for Henry Hub and $79.36 per Bbl for Cushing, Oklahoma.



43



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Our results of operations

A summary of key financial data for 2009, 2008 and 2007 related to our results of operations for the years then ended is presented below.



|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|---------------------------------------------------------------------------------- |  | -------------------------- | -------- | --------- | -------------------------- | - | ---------- | -------------------------- |  | - | ------------------- | - |  | - | --------- | - |  | - | ---------- | -
|(dollars in thousands, except per unit price)                                      |  | Year endedDecember 31,2009 |          |           | Year endedDecember 31,2008 |   |            | Year endedDecember 31,2007 |  |   | Year to year change |  
|                                                                                   |  |                            |          | 2009-2008 |                            |   | 2008-2007  |                           
|Production:                                                                        |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Oil (Mbbls)                                                                        |  |                            | 1,571    |           |                            |   | 2,236      |                            |  |   | 1,645               |   |  |   | (665      | ) |  |   | 591        |  
|Natural gas (Mmcf)                                                                 |  |                            | 118,736  |           |                            |   | 131,159    |                            |  |   | 111,419             |   |  |   | (12,423   | ) |  |   | 19,740     |  
|Total production (Mmcfe)(1)                                                        |  |                            | 128,162  |           |                            |   | 144,575    |                            |  |   | 121,289             |   |  |   | (16,413   | ) |  |   | 23,286     |  
|Oil and natural gas revenues before derivative financial instrument activities:    |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Oil                                                                                |  | $                          | 84,397   |           |                            | $ | 216,727    |                            |  | $ | 117,073             |   |  | $ | (132,330  | ) |  | $ | 99,654     |  
|Natural gas                                                                        |  |                            | 466,108  |           |                            |   | 1,188,099  |                            |  |   | 758,714             |   |  |   | (721,991  | ) |  |   | 429,385    |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Total oil and natural gas                                                          |  | $                          | 550,505  |           |                            | $ | 1,404,826  |                            |  | $ | 875,787             |   |  | $ | (854,321  | ) |  | $ | 529,039    |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Midstream operations:(2)                                                           |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Midstream revenues (before intersegment eliminations)                              |  | $                          | 76,478   |           |                            | $ | 147,636    |                            |  | $ | 45,763              |   |  | $ | (71,158   | ) |  | $ | 101,873    |  
|Midstream operating expenses (before intersegment eliminations)                    |  |                            | 56,372   |           |                            |   | 112,705    |                            |  |   | 22,276              |   |  |   | (56,333   | ) |  |   | 90,429     |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Midstream operating profit (before intersegment eliminations)                      |  |                            | 20,106   |           |                            |   | 34,931     |                            |  |   | 23,487              |   |  |   | (14,825   | ) |  |   | 11,444     |  
|Intersegment eliminations                                                          |  |                            | (20,356  | )         |                            |   | (32,296    | )                          |  |   | (20,959             | ) |  |   | 11,940    |   |  |   | (11,337    | )
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Midstream operating profit (after intersegment eliminations)                       |  | $                          | (250     | )         |                            | $ | 2,635      |                            |  | $ | 2,528               |   |  | $ | (2,885    | ) |  | $ | 107        |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Oil and natural gas derivative financial instruments:                              |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Cash settlements on derivative financial instruments                               |  | $                          | 478,463  |           |                            | $ | (109,300   | )                          |  | $ | 108,413             |   |  | $ | 587,763   |   |  | $ | (217,713   | )
|Non-cash change in fair value of derivative financial instruments                  |  |                            | (246,438 | )         |                            |   | 493,689    |                            |  |   | (81,606             | ) |  |   | (740,127  | ) |  |   | 575,295    |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Total derivative financial instrument activities                                   |  | $                          | 232,025  |           |                            | $ | 384,389    |                            |  | $ | 26,807              |   |  | $ | (152,364  | ) |  | $ | 357,582    |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Average sales price (before cash settlements of derivative financial instruments): |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Oil (Bbl)                                                                          |  | $                          | 53.72    |           |                            | $ | 96.93      |                            |  | $ | 71.17               |   |  | $ | (43.21    | ) |  | $ | 25.76      |  
|Natural gas (per Mcf)                                                              |  |                            | 3.93     |           |                            |   | 9.06       |                            |  |   | 6.81                |   |  |   | (5.13     | ) |  |   | 2.25       |  
|Natural gas equivalent (per Mcfe)                                                  |  |                            | 4.30     |           |                            |   | 9.72       |                            |  |   | 7.22                |   |  |   | (5.42     | ) |  |   | 2.50       |  
|Costs and expenses:                                                                |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Oil and natural gas operating costs(3)                                             |  | $                          | 138,659  |           |                            | $ | 161,172    |                            |  | $ | 115,719             |   |  | $ | (22,513   | ) |  | $ | 45,453     |  
|Production and ad valorem taxes                                                    |  |                            | 38,970   |           |                            |   | 76,899     |                            |  |   | 53,280              |   |  |   | (37,929   | ) |  |   | 23,619     |  
|Gathering and transportation                                                       |  |                            | 18,960   |           |                            |   | 14,206     |                            |  |   | 10,210              |   |  |   | 4,754     |   |  |   | 3,996      |  
|Depletion                                                                          |  |                            | 196,515  |           |                            |   | 435,595    |                            |  |   | 357,902             |   |  |   | (239,080  | ) |  |   | 77,693     |  
|Depreciation and amortization                                                      |  |                            | 24,923   |           |                            |   | 24,719     |                            |  |   | 17,518              |   |  |   | 204       |   |  |   | 7,201      |  
|General and administrative(4)                                                      |  |                            | 99,177   |           |                            |   | 87,568     |                            |  |   | 64,670              |   |  |   | 11,609    |   |  |   | 22,898     |  
|Interest expense, including impacts of interest rate swaps                         |  |                            | 147,161  |           |                            |   | 161,638    |                            |  |   | 181,350             |   |  |   | (14,477   | ) |  |   | (19,712    | )
|Costs and expenses (per Mcfe):                                                     |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Oil and natural gas operating costs                                                |  | $                          | 1.08     |           |                            | $ | 1.11       |                            |  | $ | 0.95                |   |  | $ | (0.03     | ) |  | $ | 0.16       |  
|Production and ad valorem taxes                                                    |  |                            | 0.30     |           |                            |   | 0.53       |                            |  |   | 0.44                |   |  |   | (0.23     | ) |  |   | 0.09       |  
|Gathering and transportation                                                       |  |                            | 0.15     |           |                            |   | 0.10       |                            |  |   | 0.08                |   |  |   | 0.05      |   |  |   | 0.02       |  
|Depletion                                                                          |  |                            | 1.53     |           |                            |   | 3.01       |                            |  |   | 2.95                |   |  |   | (1.48     | ) |  |   | 0.06       |  
|Depreciation and amortization                                                      |  |                            | 0.19     |           |                            |   | 0.17       |                            |  |   | 0.15                |   |  |   | 0.02      |   |  |   | 0.02       |  
|General and administrative                                                         |  |                            | 0.77     |           |                            |   | 0.61       |                            |  |   | 0.53                |   |  |   | 0.16      |   |  |   | 0.08       |  
|Net income (loss)                                                                  |  | $                          | (496,804 | )         |                            | $ | (1,733,471 | )                          |  | $ | 49,656              |   |  | $ | 1,236,667 |   |  | $ | (1,783,127 | )
|Preferred Stock dividends                                                          |  |                            |         |           |                            |   | (76,997    | )                          |  |   | (132,968            | ) |  |   | 76,997    |   |  |   | 55,971     |  
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  
|Income (loss) available to common shareholders                                     |  | $                          | (496,804 | )         |                            | $ | (1,810,468 | )                          |  | $ | (83,312             | ) |  | $ | 1,313,664 |   |  | $ | (1,727,156 | )
|                                                                                   |  |                            |          |           |                            |   |            |                            |  |   |                     |   |  |   |           |   |  |   |            |  



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



|(2) | Upon closing the BG Midstream Transaction on August 14, 2009, our midstream operations no longer met the criteria to be designated as a separate business segment.
Our 50% interest in TGGT is accounted for using the equity method of accounting. Effective August 14, 2009, all operating activity, including intersegment eliminations, for the Vernon Field midstream assets is reported as a component in
Gathering and transportation expense.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



44



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|(3) | Share-based compensation, pursuant to FASB ASC Topic 718, included in oil and natural gas operating costs, is $2.8 million, $4.2 million and $3.6 million for the years
ended December 31, 2009, 2008 and 2007, respectively.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | Share-based compensation, pursuant to FASB ASC Topic 718, included in general and administrative expenses is $16.2 million, $11.8 million and $9.0 million for
the years ended December 31, 2009, 2008 and 2007, respectively. See Note 2. Summary of significant accounting policiesStock options in the notes to our consolidated financial statements included in this Annual Report on
Form 10-K.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The following is a discussion of our financial condition and results of operations for the
years ended December 31, 2009, 2008 and 2007.

The comparability of our results of operations for 2009, 2008 and 2007 is
impacted by:



| |  |  | the BG Upstream Transaction;
| | - |  | ----------------------------



| |  |  | 2009 divestures;
| | - |  | ----------------



| |  |  | other dispositions of oil and natural gas properties;
| | - |  | -----------------------------------------------------



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



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



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



| |  |  | changes in Proved Reserves and production volumes, including the impact of the 2009 SEC rules, and their impact on depletion;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



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



| |  |  | gains on sales of assets in 2009;
| | - |  | ---------------------------------



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



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



| |  |  | significant acquisitions of producing oil and natural gas properties acquired in 2007 and 2008.
| | - |  | -----------------------------------------------------------------------------------------------

General

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



| |  |  | the level of domestic production and economic activity, particularly the recent worldwide economic recession which continues to affect oil and natural
gas prices and demand;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | the availability of imported oil and natural gas;
| | - |  | -------------------------------------------------



| |  |  | actions taken by foreign oil producing nations;
| | - |  | -----------------------------------------------



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



| |  |  | the cost and availability of other competitive fuels;
| | - |  | -----------------------------------------------------



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



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



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



45



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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 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 or natural gas we produce. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The
majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the
principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and
refiners near the areas of our producing properties.

We sell the majority of our natural gas under individually negotiated
gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers include utilities, natural gas
marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily,
reflecting changing market conditions.

For the year ended December 31, 2009, there were no sales to any individual
customer which exceeded 10% of our consolidated revenues or were considered material to our operations. For the year ended December 31, 2008, sales to a natural gas marketing company, Crosstex Gulf Coast Marketing, and to a regulated natural
gas utility company, Atmos Energy Marketing L.L.C. and its affiliates, accounted for approximately 12.0% and 11.2%, respectively, of total consolidated revenues. For the year 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 approximately 18.9% and 11.4%, respectively, of total consolidated 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 of the oil and natural gas we produce. If our oil and natural gas can be marketed,
we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and
natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

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

Summary

For the
years ended December 31, 2009, 2008 and 2007, we had net losses available to common shareholders of $496.8 million, $1.8 billion and $83.3 million, respectively.

During 2009, we closed divestiture and joint venture transactions totaling approximately $2.1 billion. Upon closing these transactions, we no longer operate in the Mid-Continent, Rockies and Ohio regions.
Our current primary focus is the exploration and exploitation of the Haynesville/Bossier shales in East Texas/North Louisiana and the Marcellus shale in Appalachia.



46



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Our results of operations for 2009 were impacted by the BG Upstream Transaction, the BG
Midstream Transaction, the East Texas Transaction, the Mid-Continent Transaction, the Sheridan Transaction and the EnerVest Transaction. The impacts of these transactions include the following:



| |  |  | we recognized gains from our joint venture transactions with BG Group, the East Texas Transaction, the Mid-Continent Transaction and the Sheridan
Transaction in 2009 of $691.9 million.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | production, revenues, operating expenses and related severance and ad valorem taxes for 2009 reflect the significant joint ventures and divestitures
with BG Group, Encore, and Sheridan, as well as other smaller sales completed during 2009. The significant divestitures and joint ventures occurred during the third and fourth quarters of 2009. The combination of these transactions had significant
impacts on our operating statistics. Our average daily production volumes for December 2009, the first month in which we had operations which excluded these transactions, was 224.0 Mmcfe per day, which would result in annualized production of 81.8
Bcfe compared with reported 2009 production of 128.2 Bcfe and 2008 production of 144.6 Bcfe; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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

In addition, the impact of acquisitions, fluctuations in oil and natural gas prices, ceiling test write-downs and derivative financial
instruments are significant to our results of operations. Acquisitions of producing oil and natural gas properties in 2008 and 2007 significantly increased our production, revenues and operating costs. There were large fluctuations in oil and
natural gas prices during 2008 and 2009. In 2008, we received average oil prices of $96.93 per Bbl compared to $53.72 per Bbl in 2009 and in 2008 average natural gas prices of $9.06 per Mcfe compared to $3.93 per Mcfe in 2009. As a result of the
decrease in natural gas prices from the end of 2008 and into 2009, we recognized write-downs to our full cost pool of $2.8 billion in 2008 and $1.3 billion in 2009. There were no write-downs required in 2007. In addition, we do not designate our
derivative financial instruments as hedges. Therefore, we mark the non-cash 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 2009, 2008 and 2007, the impacts of derivative financial instruments, including cash settlements or receipts with our counterparties and the non-cash mark-to-market impacts, totaled net gains of $232.0 million,
$384.4 million and $26.8 million for 2009, 2008 and 2007, respectively.

Oil and natural gas revenues, production and prices

The following table presents our revenues, production and prices by major producing areas for the years ended
December 31, 2009, 2008, 2007:



|                           |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |         |   |  |   |        |   |  |   |         |  
|-------------------------- |  | ----------------------- | ------- |  | ------------------- | - | ------ | ----------- |  | - | --------------------- |  |  | ------------------ | ------- |  | ----- | - | ------ | --------------------- |  | - | ------------------ |  |  | ----- | ------- | - |  | - | ------ | - |  | - | ------- | -
|                           |  | Year ended December 31, |         |  | Year to year change |  
|                           |  | 2009                    |         |  | 2008                |   |        | 2009 - 2008 | 
|(in thousands)             |  | Leaseoperatingexpense   |         |  | Workoversand other  |   |        | Total       |  |   | Leaseoperatingexpense |  |  | Workoversand other |         |  | Total |   |        | Leaseoperatingexpense |  |   | Workoversand other |  |  | Total |        
|Producing region:          |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |         |   |  |   |        |   |  |   |         |  
|East Texas/North Louisiana |  | $                       | 65,827  |  |                     | $ | 10,220 |             |  | $ | 76,047                |  |  | $                  | 74,720  |  |       | $ | 11,950 |                       |  | $ | 86,670             |  |  | $     | (8,893  | ) |  | $ | (1,730 | ) |  | $ | (10,623 | )
|Appalachia                 |  |                         | 29,244  |  |                     |   | 1,455  |             |  |   | 30,699                |  |  |                    | 29,548  |  |       |   | 2,056  |                       |  |   | 31,604             |  |  |       | (304    | ) |  |   | (601   | ) |  |   | (905    | )
|Permian and other          |  |                         | 10,091  |  |                     |   | 1,521  |             |  |   | 11,612                |  |  |                    | 10,916  |  |       |   | 1,941  |                       |  |   | 12,857             |  |  |       | (825    | ) |  |   | (420   | ) |  |   | (1,245  | )
|Mid-Continent              |  |                         | 19,541  |  |                     |   | 760    |             |  |   | 20,301                |  |  |                    | 28,987  |  |       |   | 1,054  |                       |  |   | 30,041             |  |  |       | (9,446  | ) |  |   | (294   | ) |  |   | (9,740  | )
|                           |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |         |   |  |   |        |   |  |   |         |  
|Total                      |  | $                       | 124,703 |  |                     | $ | 13,956 |             |  | $ | 138,659               |  |  | $                  | 144,171 |  |       | $ | 17,001 |                       |  | $ | 161,172            |  |  | $     | (19,468 | ) |  | $ | (3,045 | ) |  | $ | (22,513 | )
|                           |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |         |   |  |   |        |   |  |   |         |  



47



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|                           |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |        |   |  |   |       |   |  |   |        |  
|-------------------------- |  | ----------------------- | ------- |  | ------------------- | - | ------ | ----------- |  | - | --------------------- |  |  | ------------------ | ------- |  | ----- | - | ------ | --------------------- |  | - | ------------------ |  |  | ----- | ------ | - |  | - | ----- | - |  | - | ------ | -
|                           |  | Year ended December 31, |         |  | Year to year change |  
|                           |  | 2009                    |         |  | 2008                |   |        | 2009 - 2008 | 
|(per Mcfe)                 |  | Leaseoperatingexpense   |         |  | Workoversand other  |   |        | Total       |  |   | Leaseoperatingexpense |  |  | Workoversand other |         |  | Total |   |        | Leaseoperatingexpense |  |   | Workoversand other |  |  | Total |       
|Producing region:          |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |        |   |  |   |       |   |  |   |        |  
|East Texas/North Louisiana |  | $                       | 0.80    |  |                     | $ | 0.12   |             |  | $ | 0.92                  |  |  | $                  | 0.85    |  |       | $ | 0.14   |                       |  | $ | 0.99               |  |  | $     | (0.05  | ) |  | $ | (0.02 | ) |  | $ | (0.07  | )
|Appalachia                 |  |                         | 1.52    |  |                     |   | 0.08   |             |  |   | 1.60                  |  |  |                    | 1.41    |  |       |   | 0.10   |                       |  |   | 1.51               |  |  |       | 0.11   |   |  |   | (0.02 | ) |  |   | 0.09   |  
|Permian and other          |  |                         | 1.14    |  |                     |   | 0.17   |             |  |   | 1.31                  |  |  |                    | 0.92    |  |       |   | 0.16   |                       |  |   | 1.08               |  |  |       | 0.22   |   |  |   | 0.01  |   |  |   | 0.23   |  
|Mid-Continent              |  |                         | 1.08    |  |                     |   | 0.04   |             |  |   | 1.12                  |  |  |                    | 1.20    |  |       |   | 0.04   |                       |  |   | 1.24               |  |  |       | (0.12  | ) |  |   | (0.00 | ) |  |   | (0.12  | )
|Operating costs            |  |                         | 0.97    |  |                     |   | 0.11   |             |  |   | 1.08                  |  |  |                    | 0.99    |  |       |   | 0.12   |                       |  |   | 1.11               |  |  |       | (0.02  | ) |  |   | (0.01 | ) |  |   | (0.03  | )
|                           |  |                        
|                           |  | Year ended December 31, |         |  | Year to year change |  
|                           |  | 2008                    |         |  | 2007                |   |        | 2008 - 2007 | 
|(in thousands)             |  | Leaseoperatingexpense   |         |  | Workoversand other  |   |        | Total       |  |   | Leaseoperatingexpense |  |  | Workoversand other |         |  | Total |   |        | Leaseoperatingexpense |  |   | Workoversand other |  |  | Total |       
|Producing region:          |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |        |   |  |   |       |   |  |   |        |  
|East Texas/North Louisiana |  | $                       | 74,720  |  |                     | $ | 11,950 |             |  | $ | 86,670                |  |  | $                  | 54,529  |  |       | $ | 6,501  |                       |  | $ | 61,030             |  |  | $     | 20,191 |   |  | $ | 5,449 |   |  | $ | 25,640 |  
|Appalachia                 |  |                         | 29,548  |  |                     |   | 2,056  |             |  |   | 31,604                |  |  |                    | 18,878  |  |       |   | 1,860  |                       |  |   | 20,738             |  |  |       | 10,670 |   |  |   | 196   |   |  |   | 10,866 |  
|Permian and other          |  |                         | 10,916  |  |                     |   | 1,941  |             |  |   | 12,857                |  |  |                    | 9,197   |  |       |   | 2,351  |                       |  |   | 11,548             |  |  |       | 1,719  |   |  |   | (410  | ) |  |   | 1,309  |  
|Mid-Continent              |  |                         | 28,987  |  |                     |   | 1,054  |             |  |   | 30,041                |  |  |                    | 21,398  |  |       |   | 1,005  |                       |  |   | 22,403             |  |  |       | 7,589  |   |  |   | 49    |   |  |   | 7,638  |  
|                           |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |        |   |  |   |       |   |  |   |        |  
|Total                      |  | $                       | 144,171 |  |                     | $ | 17,001 |             |  | $ | 161,172               |  |  | $                  | 104,002 |  |       | $ | 11,717 |                       |  | $ | 115,719            |  |  | $     | 40,169 |   |  | $ | 5,284 |   |  | $ | 45,453 |  
|                           |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |        |   |  |   |       |   |  |   |        |  
|                           |  |                        
|                           |  | Year ended December 31, |         |  | Year to year change |  
|                           |  | 2008                    |         |  | 2007                |   |        | 2008 - 2007 | 
|(per Mcfe)                 |  | Leaseoperatingexpense   |         |  | Workoversand other  |   |        | Total       |  |   | Leaseoperatingexpense |  |  | Workoversand other |         |  | Total |   |        | Leaseoperatingexpense |  |   | Workoversand other |  |  | Total |       
|Producing region:          |  |                         |         |  |                     |   |        |             |  |   |                       |  |  |                    |         |  |       |   |        |                       |  |   |                    |  |  |       |        |   |  |   |       |   |  |   |        |  
|East Texas/North Louisiana |  | $                       | 0.85    |  |                     | $ | 0.14   |             |  | $ | 0.99                  |  |  | $                  | 0.70    |  |       | $ | 0.08   |                       |  | $ | 0.78               |  |  | $     | 0.15   |   |  | $ | 0.06  |   |  | $ | 0.21   |  
|Appalachia                 |  |                         | 1.41    |  |                     |   | 0.10   |             |  |   | 1.51                  |  |  |                    | 1.21    |  |       |   | 0.12   |                       |  |   | 1.33               |  |  |       | 0.20   |   |  |   | (0.02 | ) |  |   | 0.18   |  
|Permian and other          |  |                         | 0.92    |  |                     |   | 0.16   |             |  |   | 1.08                  |  |  |                    | 1.14    |  |       |   | 0.29   |                       |  |   | 1.43               |  |  |       | (0.22  | ) |  |   | (0.13 | ) |  |   | (0.35  | )
|Mid-Continent              |  |                         | 1.20    |  |                     |   | 0.04   |             |  |   | 1.24                  |  |  |                    | 1.11    |  |       |   | 0.05   |                       |  |   | 1.16               |  |  |       | 0.09   |   |  |   | (0.01 | ) |  |   | 0.08   |  
|Operating costs            |  |                         | 0.99    |  |                     |   | 0.12   |             |  |   | 1.11                  |  |  |                    | 0.85    |  |       |   | 0.10   |                       |  |   | 0.95               |  |  |       | 0.14   |   |  |   | 0.02  |   |  |   | 0.16   |  

Total oil and natural
gas revenues for 2009 were $550.5 million compared with $1.4 billion for 2008 and $875.8 million for 2007. For 2009, natural gas represented 84.7% of our oil and natural gas revenues and 92.6% of equivalent production. For 2008,
natural gas represented 84.6% of our oil and natural gas revenues and 90.7% of equivalent production and for 2007, natural gas represented 86.6% of our oil and natural gas revenues and 91.9% of equivalent production.

Our equivalent production volumes for 2009 were 128.2 Bcfe compared with 144.6 Bcfe for 2008, a decrease of 11.4% due primarily to our
2009 divestitures, including the BG Upstream Transaction, which were partially offset by increased production volumes from Haynesville drilling results.

Production in our East Texas/North Louisiana region for 2009 was 82.1 Bcfe compared with 87.5 Bcfe in 2008. Divestures in 2009 impacting our East Texas/North Louisiana region included our East Texas
Transaction and the BG Upstream Transaction. Our East Texas/North Louisiana production was also impacted as a result of production declines in our Vernon Field due to suspension of vertical drilling operations in the area. These decreases were
almost offset, however, by increased production in our Haynesville area, which we began actively drilling in late 2008, and the addition of the Danville Field in East Texas, which we acquired in July 2008.



48



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Our Mid-Continent region was sold in 2009. Our production in Appalachia in 2009 of 19.2 Bcfe
compared with 20.9 Bcfe in 2008, was the result of normal declines impacted by suspension of drilling operations and the EnverVest Transaction. Our production declines in Permian were a result of normal declines, suspension of drilling operations
and the divesture of our Vinegarone Field.

Our equivalent production volumes for 2008 were 144.6 Bcfe compared with 121.3
Bcfe for 2007, an increase of 19.2%, due to our 2008 Appalachian Acquisition and the Danville Acquisition, combined with full year 2008 production impacts from the 2007 Vernon Acquisition and the Southern Gas Acquisition. The Appalachian Acquisition
and the Danville Acquisition contributed 7.7 Bcfe of production to our 2008 total volumes. Production increases of approximately 10.2 Bcfe in 2008 include the impact of a full year production from the Vernon Acquisition and the Southern Gas
Acquisition compared with a partial year in 2007.

For 2009, our average price received for natural gas was $3.93 per Mcf
compared with $9.06 per Mcf in 2008 and $6.81 per Mcf in 2007. The 2009 average price received for oil was $53.72 per Bbl compared to $96.93 per Bbl for 2008. The average price per Bbl for 2007 was $71.17. 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. The decline from the 2008 prices to the 2009 prices was a result of a commodity price decline that
started at end of the third quarter of 2008 and continued through 2009. Assuming our 2009 production levels, a change of $0.10 per Mcf of natural gas sold would result in an annual increase or decrease in revenues and cash flow of approximately
$11.9 million and a change of $1.00 per Bbl of oil sold would result in an annual increase or decrease in revenues and cash flow of approximately $1.6 million without considering the effects of derivative financial instruments.

In 2008, our revenues (before the impact of derivative financial instruments) increased to $1.4 billion from $875.8 million for
2007. The total increase of $529.0 million was attributable to an increase of $236.0 million from increased volumes primarily due to 2008 and 2007 acquisitions along with an increase in our realized price per Mcfe, which increased revenue
by $293.0 million.

During 2008 we closed the Appalachian Acquisition, which included shallow natural gas properties
located primarily in our central Pennsylvania operating area and the Danville Acquisition, which included producing oil and natural gas properties, acreage and other assets in Gregg, Rusk and Upshur counties of Texas. The Appalachian Acquisition and
the Danville Acquisition increased our production in our Appalachia and East Texas/North Louisiana areas by 4.6 Bcfe and 3.1 Bcfe, respectively, during 2008. In addition, the impact of a full year of production in 2008 compared with a partial year
in 2007 from the Vernon Acquisition increased volumes in East Texas/North Louisiana by 4.4 Bcfe. Volumes in the Mid-Continent area from the Southern Gas Acquisition increased by 5.7 Bcfe during 2008.

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 Colorado. 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 Vernon Acquisition and the Southern Gas Acquisition significantly increased our production in the East
Texas/North Louisiana and Mid-Continent areas during 2007.



49



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Midstream revenues

Until our adoption of the equity method of accounting in connection with the BG Midstream Transaction in August 2009, our midstream revenues were principally derived from three of our wholly-owned
subsidiaries: TGG, which owns an intrastate pipeline in East Texas and a gathering system in North Louisiana, Talco, which owns gathering systems in East Texas and North Louisiana and Vernon Gathering. Revenues in our midstream segment were derived
from sales of natural gas purchased for resale and fees earned from gathering, transportation, treating and compression of natural gas. We do not own any natural gas processing facilities.

On August 14, 2009, we closed the BG Midstream Transaction. TGGT now holds our East Texas/North Louisiana midstream assets,
exclusive of the Vernon Field midstream assets. TGGT is accounted for using the equity method of accounting. The net operations of Vernon Gathering are now reflected in Gathering and transportation on our Condensed Consolidated
Statements of Operations.

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

For the
year ended December 31, 2009, midstream revenues were $76.5 million compared with $147.6 million for year ended December 31, 2008. The decrease in sales for 2009 is due to the combination of lower prices received in 2009 from the sales of
natural gas we purchased for resale, lower condensate prices and the adoption of the equity method of accounting for TGGTs operations on August 14, 2009.

For the year ended December 31, 2008, midstream revenues were $147.6 million, a 222.6% increase over the year ended December 31, 2007 midstream revenues of $45.8 million. Increases in the sales
of natural gas account for 80.9% of the increase in the midstream revenues and are primarily attributable to the New Waskom Acquisition and gathering assets acquired in the Danville Acquisition. These assets, which were not owned in 2007, contained
several contracts whereby we purchase and resell natural gas produced by third-parties. The remaining increase in revenues was attributable to increases in drip sales and gathering fees associated with the 2008 acquisitions, as well as increased
throughput on our midstream assets.

Oil and natural gas operating costs

Our oil and natural gas operating costs for 2009, 2008, and 2007 were $138.7 million, $161.2 million and $115.7 million, respectively.
Absolute increases or decreases in total dollar value from year to year are due primarily to operating expenses incurred from our acquisitions or divestitures. Management believes that analyses on a per Mcfe basis provide a more meaningful measure
than the absolute dollar increases since the divestures in 2009 and the acquisitions in 2008 and 2007 significantly impacted the absolute dollar amounts. The following tables summarize direct operating expenses and unit rates per Mcfe for 2009,
2008, and 2007:



|                                          |  |                            |         |           |                            |   |           |                            |  |   |                    |  |  |                    |         |   |  |   |        | 
|----------------------------------------- |  | -------------------------- | ------- | --------- | -------------------------- | - | --------- | -------------------------- |  | - | ------------------ |  |  | ------------------ | ------- | - |  | - | ------ | 
|(in thousands)                            |  | Year
endedDecember 31,2009 |         |           | Year
endedDecember 31,2008 |   |           | Year
endedDecember 31,2007 |  |   | Year
toyear change |  |  | Year
toyear change |        
|                                          |  |                            |         |          
|                                          |  |                            |         | 2009-2008 |                            |   | 2008-2007 |                           
|Lease operating expense                   |  | $                          | 124,703 |           |                            | $ | 144,171   |                            |  | $ | 104,002            |  |  | $                  | (19,468 | ) |  | $ | 40,169 | 
|Workovers                                 |  |                            | 11,125  |           |                            |   | 12,827    |                            |  |   | 8,126              |  |  |                    | (1,702  | ) |  |   | 4,701  | 
|Stock-based compensation (non-cash)       |  |                            | 2,831   |           |                            |   | 4,174     |                            |  |   | 3,591              |  |  |                    | (1,343  | ) |  |   | 583    | 
|                                          |  |                            |         |           |                            |   |           |                            |  |   |                    |  |  |                    |         |   |  |   |        | 
|Total oil and natural gas operating costs |  | $                          | 138,659 |           |                            | $ | 161,172   |                            |  | $ | 115,719            |  |  | $                  | (22,513 | ) |  | $ | 45,453 | 
|                                          |  |                            |         |           |                            |   |           |                            |  |   |                    |  |  |                    |         |   |  |   |        | 



50



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|                                          |  |                          |      |           |                          |   |           |                          |  |   |                   |  |  |                  |       |   |  |   |      | 
|----------------------------------------- |  | ------------------------ | ---- | --------- | ------------------------ | - | --------- | ------------------------ |  | - | ----------------- |  |  | ---------------- | ----- | - |  | - | ---- | 
|                                          |  |                          |      |           |                         
|(per Mcfe)                                |  | YearendedDecember31,2009 |      |           | YearendedDecember31,2008 |   |           | YearendedDecember31,2007 |  |   | Year
toyearchange |  |  | Yeartoyearchange |      
|                                          |  |                          |      |          
|                                          |  |                          |      | 2009-2008 |                          |   | 2008-2007 |                         
|Lease operating expense                   |  | $                        | 0.97 |           |                          | $ | 0.99      |                          |  | $ | 0.85              |  |  | $                | (0.02 | ) |  | $ | 0.14 | 
|Workovers                                 |  |                          | 0.09 |           |                          |   | 0.09      |                          |  |   | 0.07              |  |  |                  |      |   |  |   | 0.02 | 
|Stock-based compensation (non-cash)       |  |                          | 0.02 |           |                          |   | 0.03      |                          |  |   | 0.03              |  |  |                  | (0.01 | ) |  |   |     | 
|                                          |  |                          |      |           |                          |   |           |                          |  |   |                   |  |  |                  |       |   |  |   |      | 
|Total oil and natural gas operating costs |  | $                        | 1.08 |           |                          | $ | 1.11      |                          |  | $ | 0.95              |  |  | $                | (0.03 | ) |  | $ | 0.16 | 
|                                          |  |                          |      |           |                          |   |           |                          |  |   |                   |  |  |                  |       |   |  |   |      | 

On a per Mcfe basis, oil and natural gas operating costs for the year ended December 31, 2009 decreased
by $0.03 per Mcfe from year ended December 31, 2008. Direct lease operating expenses per unit decreased by $0.02 per Mcfe, or 2.0%, for the year ended December 31, 2009, from the year ended December 31, 2008. These decreases are
principally the result of divestitures in 2009 and lower operating costs in our East Texas/North Louisiana area where increasing volumes from Haynesville wells benefit the unit rate. Benefits from the Haynesville results are partially offset by
declining volumes from our base production that tend to increase the unit rate.

On a per Mcfe basis, oil and natural gas
operating expenses for the year ended December 31, 2008 increased $0.16 per Mcfe from year ended December 31, 2007. Direct lease operating expenses increased by $0.14 per Mcfe, or 16.5%, for the year ended December 31, 2008 from the
year ended December 31, 2007. These increases were primarily the result of our acquisitions in 2008 and the general increase in the costs of goods and services used in our oil and natural gas operations, most notably chemicals, labor,
utilities, motor fuel and utility costs. Workover expenses for the year ended December 31, 2008, on a Mcfe basis, increased $0.02 per Mcfe from the year ended December 31, 2007 due primarily to higher costs for rigs and services.

Midstream operating expenses

Our midstream operating expenses before intersegment elimination, which includes the cost of natural gas purchased and then resold, for the year ended December 31, 2009 decreased $56.3 million from
the year ended December 31, 2008. The decrease in midstream operating expenses was primarily attributable to a decline in the prices we paid for the natural gas we purchased for resale along with the August 14, 2009 BG Midstream
Transaction and related adoption of the equity method of accounting for TGGTs operations. These decreases were offset by increases in both operating expenses and gas purchases resulting from the 2008 New Waskom and Danville acquisitions
as well as the expansion of our gathering and transportation facilities in the East Texas/North Louisiana operating area in support of our Haynesville projects.

Our midstream operating expenses before intersegment eliminations for the year ended December 31, 2008 increased $90.4 million, or 406.0%, respectively, from the year ended December 31, 2007.
The increase in midstream operating expenses for the year ended December 31, 2008 was primarily attributable to:



| |  |  | increased cost of purchased gas of approximately $78.3 million due primarily to contracts assumed to purchase natural gas from our March 2008 New
Waskom Acquisition; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | increased operating expenses of approximately $10.2 million related to the March 2008 New Waskom Acquisition and increased Vernon Gathering
operating expenses due to 2008 reflecting twelve months of operating costs and 2007 reflecting only nine months of operating costs.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Gathering and transportation

We report gathering and transportation
costs in accordance with FASB Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation
charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the



51



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transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no
transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments,
contain revenues which are reported under two separate bases. Gathering and transportation expenses totaled $19.0 million for year ended December 31, 2009, compared to $14.2 million for the year ended December 31, 2008 and $10.2 million
for the year ended December 31, 2007.

As a result of the BG Midstream Transaction on August 14, 2009 our gathering
system in Louisiana that supports our Vernon Field operations, which was previously reported within our midstream segment, is now reported net in Gathering and transportation on the Consolidated Statements of Operations.

We have entered into firm transportation agreements with pipeline companies to facilitate sales as we expand our Haynesville volumes. We
expect our gathering and transportation expenses to increase significantly in 2010 and beyond.

Production and ad valorem taxes

Production and ad valorem taxes were $39.0 million, $76.9 million and $53.3 million for 2009, 2008, and
2007, respectively. However, on a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 7.1% of oil and natural gas sales, compared with 5.5% and 6.1% for 2007 and 2006,
respectively. The increase in the percentage of revenue basis is primarily the result of the different taxing jurisdictions in which we operate. Production taxes are set by state and local governments and vary as to the tax rate and the value to
which that rate is applied. In Louisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis. Therefore, the resulting dollar value of production is not sensitive to changes in prices for
natural gas. The rate in Louisiana, whether stated on a per Mcfe basis or as a percentage of revenues, is also complicated by certain severance tax holidays on deep wells. Approval of these holidays is on a well by well basis, and credits are not
recognized until approvals are received. Accordingly, a 50% decline in the average sales price per Mcf in Louisiana would double the effective production tax rate as a percentage of revenue. In our other operating areas, production taxes are
predominantly price dependent. Ad valorem assessments also vary widely.

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

Overall, our production and ad valorem tax rates per Mcfe were $0.30 per Mcfe for 2009, $0.53 per Mcfe for 2008 and $0.44 per Mcfe for
2007. The following tables present our severance and ad valorem taxes on a per Mcfe basis and percentage of revenue basis for our significant producing regions.



|                                            |  |                         |         |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 
|------------------------------------------- |  | ----------------------- | ------- |  | ----------------- |  | ------- | ---------------------------- |  | - | ---------------- |  |  | ----------- | --- | - | ------- | - | ---- | ----------------- |  | - | ---------------------------- |  |  | ---------------- | ------- |  | ----------- | - | ------ |  |  |  | --- | - |  | - | ---- | 
|                                            |  | Year ended December 31, |        
|                                            |  | 2009                    |         |  | 2008              | 
|(dollars in thousands,except per unit rate) |  | Revenue                 |         |  | Production(Mmcfe) |  |         | Productionand advaloremtaxes |  |   | Taxes% ofrevenue |  |  | Taxes$/Mcfe |     |   | Revenue |   |      | Production(Mmcfe) |  |   | Productionand advaloremtaxes |  |  | Taxes% ofrevenue |         |  | Taxes$/Mcfe |  
|Producing region:                           |  |                         |         |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 
|East Texas/North Louisiana                  |  | $                       | 315,710 |  |                   |  | 82,138  |                              |  | $ | 24,162           |  |  |             | 7.7 | % |         | $ | 0.29 |                   |  | $ | 802,579                      |  |  |                  | 87,540  |  |             | $ | 40,227 |  |  |  | 5.0 | % |  | $ | 0.46 | 
|Mid-Continent                               |  |                         | 84,179  |  |                   |  | 18,013  |                              |  |   | 6,588            |  |  |             | 7.8 | % |         |   | 0.37 |                   |  |   | 243,148                      |  |  |                  | 24,239  |  |             |   | 18,415 |  |  |  | 7.6 | % |  |   | 0.76 | 
|Appalachia                                  |  |                         | 91,832  |  |                   |  | 19,184  |                              |  |   | 2,562            |  |  |             | 2.8 | % |         |   | 0.13 |                   |  |   | 209,221                      |  |  |                  | 20,899  |  |             |   | 5,545  |  |  |  | 2.7 | % |  |   | 0.27 | 
|Permian and other                           |  |                         | 58,784  |  |                   |  | 8,827   |                              |  |   | 5,658            |  |  |             | 9.6 | % |         |   | 0.64 |                   |  |   | 149,878                      |  |  |                  | 11,897  |  |             |   | 12,712 |  |  |  | 8.5 | % |  |   | 1.07 | 
|                                            |  |                         |         |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 
|Total                                       |  | $                       | 550,505 |  |                   |  | 128,162 |                              |  | $ | 38,970           |  |  |             | 7.1 | % |         | $ | 0.30 |                   |  | $ | 1,404,826                    |  |  |                  | 144,575 |  |             | $ | 76,899 |  |  |  | 5.5 | % |  | $ | 0.53 | 
|                                            |  |                         |         |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 



52



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|                                             |  |                         |           |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 
|-------------------------------------------- |  | ----------------------- | --------- |  | ----------------- |  | ------- | ---------------------------- |  | - | ---------------- |  |  | ----------- | --- | - | ------- | - | ---- | ----------------- |  | - | ---------------------------- |  |  | ---------------- | ------- |  | ----------- | - | ------ |  |  |  | --- | - |  | - | ---- | 
|                                             | 
|                                             |  | Year ended December 31, |          
|                                             |  | 2008                    |           |  | 2007              | 
|(dollars in thousands,
except per unit rate) |  | Revenue                 |           |  | Production(Mmcfe) |  |         | Productionand advaloremtaxes |  |   | Taxes% ofrevenue |  |  | Taxes$/Mcfe |     |   | Revenue |   |      | Production(Mmcfe) |  |   | Productionand advaloremtaxes |  |  | Taxes% ofrevenue |         |  | Taxes$/Mcfe |  
|Producing region:                            |  |                         |           |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 
|East Texas/North Louisiana                   |  | $                       | 802,579   |  |                   |  | 87,540  |                              |  | $ | 40,227           |  |  |             | 5.0 | % |         | $ | 0.46 |                   |  | $ | 528,947                      |  |  |                  | 78,312  |  |             | $ | 32,375 |  |  |  | 6.1 | % |  | $ | 0.41 | 
|Mid-Continent                                |  |                         | 243,148   |  |                   |  | 24,239  |                              |  |   | 18,415           |  |  |             | 7.6 | % |         |   | 0.76 |                   |  |   | 148,586                      |  |  |                  | 19,271  |  |             |   | 10,469 |  |  |  | 7.0 | % |  |   | 0.54 | 
|Appalachia                                   |  |                         | 209,221   |  |                   |  | 20,899  |                              |  |   | 5,545            |  |  |             | 2.7 | % |         |   | 0.27 |                   |  |   | 121,994                      |  |  |                  | 15,661  |  |             |   | 4,099  |  |  |  | 3.4 | % |  |   | 0.26 | 
|Permian and other                            |  |                         | 149,878   |  |                   |  | 11,897  |                              |  |   | 12,712           |  |  |             | 8.5 | % |         |   | 1.07 |                   |  |   | 76,260                       |  |  |                  | 8,045   |  |             |   | 6,337  |  |  |  | 8.3 | % |  |   | 0.79 | 
|                                             |  |                         |           |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 
|Total                                        |  | $                       | 1,404,826 |  |                   |  | 144,575 |                              |  | $ | 76,899           |  |  |             | 5.5 | % |         | $ | 0.53 |                   |  | $ | 875,787                      |  |  |                  | 121,289 |  |             | $ | 53,280 |  |  |  | 6.1 | % |  | $ | 0.44 | 
|                                             |  |                         |           |  |                   |  |         |                              |  |   |                  |  |  |             |     |   |         |   |      |                   |  |   |                              |  |  |                  |         |  |             |   |        |  |  |  |     |   |  |   |      | 

Depreciation, depletion and amortization

The following table presents our depreciation, depletion and amortization expenses for the years ended December 31, 2009, 2008 and
2007. The depreciation, depletion and amortization rate per Mcfe produced varies significantly for each of the periods presented due to the various divestures, acquisitions and ceiling test write-downs incurred in 2008 and 2009. The 2007 Vernon
Acquisition and the Southern Gas Acquisition, both of which included significant proved developed producing properties, increased the depreciation, depletion and amortization rate to $3.10 per Mcfe in 2007. The Appalachian Acquisition and the
Danville Acquisition, along with a full year of activity related to the 2007 acquisitions, initially increased the depreciation, depletion and amortization rate in 2008; however, these acquisitions were offset by the ceiling test write-downs in
2008. The annual 2008 depreciation, depletion and amortization rate was $3.18 per Mcfe, approximately 2.6% higher than 2007. The depletion rate was further reduced in 2009 by the first quarter 2009 ceiling test write-downs and the divestures during
year, resulting in an annual depreciation, depletion and amortization rate of $1.72 per Mcfe in 2009, approximately 45.9% lower than 2008.



|                                                                    |  |                            |         |  |                            |   |         |                            |  |   |                             |  |  |                             |          |   |  |   |        | 
|------------------------------------------------------------------- |  | -------------------------- | ------- |  | -------------------------- | - | ------- | -------------------------- |  | - | --------------------------- |  |  | --------------------------- | -------- | - |  | - | ------ | 
|(dollars in thousands, except per unit rate)                        |  | Year endedDecember 31,2009 |         |  | Year endedDecember 31,2008 |   |         | Year endedDecember 31,2007 |  |   | Year to yearchange2009-2008 |  |  | Year to yearchange2008-2007 |         
|Depreciation, depletion and amortization costs:                     |  |                            |         |  |                            |   |         |                            |  |   |                             |  |  |                             |          |   |  |   |        | 
|Depletion expense                                                   |  | $                          | 196,515 |  |                            | $ | 435,595 |                            |  | $ | 357,902                     |  |  | $                           | (239,080 | ) |  | $ | 77,693 | 
|Depreciation and amortization expense                               |  | $                          | 24,923  |  |                            | $ | 24,719  |                            |  | $ | 17,518                      |  |  | $                           | 204      |   |  | $ | 7,201  | 
|Depletion calculated rate per Mcfe                                  |  | $                          | 1.53    |  |                            | $ | 3.01    |                            |  | $ | 2.95                        |  |  | $                           | (1.48    | ) |  | $ | 0.06   | 
|Depreciation and amortization calculated rate per Mcfe              |  | $                          | 0.19    |  |                            | $ | 0.17    |                            |  | $ | 0.15                        |  |  | $                           | 0.02     |   |  | $ | 0.02   | 
|Consolidated depreciation, depletion and amortization rate per Mcfe |  | $                          | 1.72    |  |                            | $ | 3.18    |                            |  | $ | 3.10                        |  |  | $                           | (1.46    | ) |  | $ | 0.08   | 

Accretion of discount
on asset retirement obligations increased to $7.1 million in 2009 from $6.7 million in 2008 and $4.9 million in 2007. The increase in 2009 from 2008 and in 2008 from 2007 is due to the combination of significant well additions and related
plugging liabilities in connection with our 2008 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. The impact of our 2009 divestitures on accretion expenses in not significant as the divestitures occurred throughout 2009.

Write-down of oil and natural gas properties

For the year ended
December 31, 2009, we recognized a ceiling test write-down of $1.3 billion. For the year ended December 31, 2008, we recognized ceiling test write-downs of $2.8 billion to our proved oil and natural gas properties. There were no ceiling
test write-downs in 2007.



53



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As discussed above, prior to our December 31, 2009 adoption of Release
No. 33-8995, we were required by the SEC to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The prices used to compute our first
quarter write-down were $3.63 per Mmbtu for natural gas and $49.64 per Bbl of oil as of March 31, 2009. Beginning December 31, 2009, Release No. 33-8995 states that we are required to compute the present value of our proved oil
and natural gas properties using the simple average spot price for the trailing twelve month period using the first day of each month. The average prices used to compute the present value of our properties were $3.87 per Mmbtu for natural gas and
$61.18 per Bbl of oil for 2009. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease natural gas prices at these hubs such as
market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in
Appalachia, where we have typically received a premium to Henry Hub. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance.

General and administrative expenses

The following table presents our general and administrative expenses for the years ended December 31, 2009, 2008 and 2007 and changes for each of the years then ended.



|                                                |  |                            |         |   |                            |   |         |                            |  |   |                             |   |  |                             |        |   |  |   |        |  
|----------------------------------------------- |  | -------------------------- | ------- | - | -------------------------- | - | ------- | -------------------------- |  | - | --------------------------- | - |  | --------------------------- | ------ | - |  | - | ------ | -
|(in thousands, except per unit amounts)         |  | Year endedDecember 31,2009 |         |   | Year endedDecember 31,2008 |   |         | Year endedDecember 31,2007 |  |   | Year to yearchange2009-2008 |   |  | Year to yearchange2008-2007 |       
|General and administrative costs:               |  |                            |         |   |                            |   |         |                            |  |   |                             |   |  |                             |        |   |  |   |        |  
|Gross general and administrative expense        |  | $                          | 137,038 |   |                            | $ | 123,981 |                            |  | $ | 88,778                      |   |  | $                           | 13,057 |   |  | $ | 35,203 |  
|Operator overhead reimbursements                |  |                            | (24,600 | ) |                            |   | (24,902 | )                          |  |   | (18,413                     | ) |  |                             | 302    |   |  |   | (6,489 | )
|Capitalized acquisition and development charges |  |                            | (13,261 | ) |                            |   | (11,511 | )                          |  |   | (5,695                      | ) |  |                             | (1,750 | ) |  |   | (5,816 | )
|                                                |  |                            |         |   |                            |   |         |                            |  |   |                             |   |  |                             |        |   |  |   |        |  
|Net general and administrative expense          |  | $                          | 99,177  |   |                            | $ | 87,568  |                            |  | $ | 64,670                      |   |  | $                           | 11,609 |   |  | $ | 22,898 |  
|                                                |  |                            |         |   |                            |   |         |                            |  |   |                             |   |  |                             |        |   |  |   |        |  
|General and administrative expense per Mcfe     |  | $                          | 0.77    |   |                            | $ | 0.61    |                            |  | $ | 0.53                        |   |  | $                           | 0.16   |   |  | $ | 0.08   |  

Net general and
administrative expenses for the year ended December 31, 2009 were $99.2 million, or $0.77 per Mcfe, compared with $87.6 million, or $0.61 per Mcfe, in 2008, an increase of $11.6 million.

The primary components of the net increase of $11.6 million for the year ended December 31, 2009 were higher personnel costs of
$16.4 million due to additional employees related to expansion of technical staff to exploit our shale resource asset base, $2.6 million in employee relocation and severance costs associated with our divestitures and office closures, $4.4 million in
additional stock compensation expense related primarily to the acceleration of vesting of certain employees impacted by the divestitures and the impact the increase in our stock price had on the valuation of our December 2009 grants compared to the
December 2008 grants and increased rent of $1.6 million resulting from our 2008 expansion.

These increases were offset by the
following items:



| |  |  | decreased legal fees of $4.4 million due to the first quarter 2008 cancellation of a proposed master limited partnership and reduced reserves for
claims;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | decreased franchise and property taxes of $1.5 million due primarily to lower equity as a result of 2008 and 2009 ceiling test write-downs and
recapitalization of our corporate structure;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | decreased information and technology costs of $1.6 million due primarily to prior year costs incurred in connection with additional personnel;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



54



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| |  |  | recovery of $4.6 million of technical service costs from our service agreement with BG Group; and
| | - |  | -------------------------------------------------------------------------------------------------



| |  |  | increased capitalized salary costs of $1.8 million due to the previously discussed expansion of technical personnel.
| | - |  | --------------------------------------------------------------------------------------------------------------------

Net general and administrative expenses for the year ended December 31, 2008 were $87.6 million, or $0.61 per Mcfe, compared
with $64.7 million, or $0.53 per Mcfe, in 2007, an increase of $22.9 million. Significant components of the increase for the year ended December 31, 2008 include the following items:



| |  |  | increased personnel costs of $20.7 million due to increasing our net headcount by 185 employees related primarily to our acquisitions and expanding our
technical and managerial staff to fully exploit our asset base;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | an increase in share-based compensation costs of $2.8 million due primarily to additional headcount;
| | - |  | ----------------------------------------------------------------------------------------------------



| |  |  | increased consulting and contract labor costs of $1.4 million due primarily to acquisitions and information technology-related support;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------



| |  |  | increased information technology related costs of $2.3 million primarily due to the equipment and infrastructure requirements attributable to our
increased headcount;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | increased legal fees of $2.0 million, including $3.7 million attributable to a write-off of our proposed master limited partnership offering, which was
withdrawn in January 2008. The increase associated with this write-off was partially offset by lower external legal fees of approximately $1.7 million during the year ended December 31, 2008 when compared with the prior year;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | increases of $1.1 million in automobile expenses;
| | - |  | -------------------------------------------------



| |  |  | increased occupancy costs of $0.7 million resulting from expansion of corporate facilities;
| | - |  | -------------------------------------------------------------------------------------------



| |  |  | increased franchise tax of $0.6 million due, primarily, to changes in the jurisdictional make-up of our properties; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------



| |  |  | other expenses related to the overall growth of our business.
| | - |  | -------------------------------------------------------------

Partially offsetting the increases in general and administrative expenses were operator overhead recoveries of $24.9 million and
$18.4 million for the years ended December 31, 2008 and 2007, respectively. Additional offsets to general and administrative expenses were capitalized costs of $11.5 million and $5.7 million for the years ended December 31,
2008 and 2007, respectively.

Interest expense

Interest expense for the year ended December 31, 2009 was $147.2 million compared to $161.6 million for the same period in 2008. The decreased interest expense of $14.5 million is a result of
$46.1 million decreased interest costs from our credit agreements due to the combination of significant reductions in outstanding debt beginning in the third quarter of 2009 and lower LIBO rates in 2009 compared to 2008, a $5.0 million decrease
related to our interest rate swaps and a $2.0 million decrease related to a full year of capitalized interest. The decrease was offset by an increase of $9.0 million resulting primarily from the write-off of deferred financing fees related to the
reduction of our debt on the credit agreements and $29.7 million of interest and deferred financing costs related to the Term Credit Agreement, which included a $15.0 million duration fee. We repaid the Term Credit Agreement in August 2009.



55



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Interest expense for the year ended December 31, 2008 was $161.6 million compared to
$181.3 million for the same period in 2007. The decrease of $19.7 million in 2008 when compared to 2007 reflects higher 2008 interest costs for the Term Credit Agreement of $26.9 million and settlements and non-cash changes in the fair value of
interest swaps of $9.9 million which were more than offset by reductions of $50.2 million of prior year write-offs of deferred financing costs arising from early debt terminations, reduced interest on credit agreements of $1.7 million and $3.9
million of capitalized interest in 2008. There was no interest capitalized in 2007.



|                                                                                          |  |                            |         |   |                            |   |         |                            |  |   |                             |  |  |                             |         |   |  |   |         |  
|----------------------------------------------------------------------------------------- |  | -------------------------- | ------- | - | -------------------------- | - | ------- | -------------------------- |  | - | --------------------------- |  |  | --------------------------- | ------- | - |  | - | ------- | -
|(in thousands)                                                                            |  | Year endedDecember 31,2009 |         |   | Year endedDecember 31,2008 |   |         | Year endedDecember 31,2007 |  |   | Year to yearchange2009-2008 |  |  | Year to yearchange2008-2007 |        
|Interest expense:                                                                         |  |                            |         |   |                            |   |         |                            |  |   |                             |  |  |                             |         |   |  |   |         |  
|71/4% senior notes due 2011                                                               |  | $                          | 28,653  |   |                            | $ | 28,874  |                            |  | $ | 28,922                      |  |  | $                           | (221    | ) |  | $ | (48     | )
|EXCO Resources Credit Agreement                                                           |  |                            | 22,778  |   |                            |   | 42,628  |                            |  |   | 29,415                      |  |  |                             | (19,850 | ) |  |   | 13,213  |  
|EXCO Operating Credit Agreement                                                           |  |                            | 26,456  |   |                            |   | 52,717  |                            |  |   | 68,462                      |  |  |                             | (26,261 | ) |  |   | (15,745 | )
|Term Credit Agreement                                                                     |  |                            | 18,833  |   |                            |   | 13,337  |                            |  |   |                            |  |  |                             | 5,496   |   |  |   | 13,337  |  
|Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement |  |                            | 8,632   |   |                            |   | 1,956   |                            |  |   | 1,519                       |  |  |                             | 6,676   |   |  |   | 437     |  
|Amortization of deferred financing costs on EXCO Operating Credit Agreement               |  |                            | 5,362   |   |                            |   | 3,014   |                            |  |   | 2,619                       |  |  |                             | 2,348   |   |  |   | 395     |  
|Amortization of deferred financing costs on Term Credit Agreement                         |  |                            | 37,754  |   |                            |   | 13,598  |                            |  |   |                            |  |  |                             | 24,156  |   |  |   | 13,598  |  
|Amortization and write-off of deferred financing costs on EXCO Operating term loan        |  |                            |        |   |                            |   |        |                            |  |   | 32,100                      |  |  |                             |        |   |  |   | (32,100 | )
|EXCO Operating term loan                                                                  |  |                            |        |   |                            |   |        |                            |  |   | 18,140                      |  |  |                             |        |   |  |   | (18,140 | )
|Capitalized interest                                                                      |  |                            | (5,840  | ) |                            |   | (3,861  | )                          |  |   |                            |  |  |                             | (1,979  | ) |  |   | (3,861  | )
|Interest rate swaps settlements                                                           |  |                            | 12,180  |   |                            |   | (588    | )                          |  |   |                            |  |  |                             | 12,768  |   |  |   | (588    | )
|Fair market value adjustment on interest rate swaps                                       |  |                            | (7,861  | ) |                            |   | 9,878   |                            |  |   |                            |  |  |                             | (17,739 | ) |  |   | 9,878   |  
|Other interest expense                                                                    |  |                            | 214     |   |                            |   | 85      |                            |  |   | 173                         |  |  |                             | 129     |   |  |   | (88     | )
|                                                                                          |  |                            |         |   |                            |   |         |                            |  |   |                             |  |  |                             |         |   |  |   |         |  
|Total interest expense                                                                    |  | $                          | 147,161 |   |                            | $ | 161,638 |                            |  | $ | 181,350                     |  |  | $                           | (14,477 | ) |  | $ | (19,712 | )
|                                                                                          |  |                            |         |   |                            |   |         |                            |  |   |                             |  |  |                             |         |   |  |   |         |  

Derivative financial instruments

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



56



---

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



|                                                                  |  |                            |          |   |                            |   |          |                            |  |   |                             |   |  |                             |          |   |  |   |          |  
|----------------------------------------------------------------- |  | -------------------------- | -------- | - | -------------------------- | - | -------- | -------------------------- |  | - | --------------------------- | - |  | --------------------------- | -------- | - |  | - | -------- | -
|(in thousands)                                                    |  | Year endedDecember 31,2009 |          |   | Year endedDecember 31,2008 |   |          | Year endedDecember 31,2007 |  |   | Year to yearchange2009-2008 |   |  | Year to yearchange2008-2007 |         
|Derivative financial instrument activities:                       |  |                            |          |   |                            |   |          |                            |  |   |                             |   |  |                             |          |   |  |   |          |  
|Cash settlements on derivative financial instruments              |  | $                          | 478,463  |   |                            | $ | (109,300 | )                          |  | $ | 108,413                     |   |  | $                           | 587,763  |   |  | $ | (217,713 | )
|Non-cash change in fair value of derivative financial instruments |  |                            | (246,438 | ) |                            |   | 493,689  |                            |  |   | (81,606                     | ) |  |                             | (740,127 | ) |  |   | 575,295  |  
|                                                                  |  |                            |          |   |                            |   |          |                            |  |   |                             |   |  |                             |          |   |  |   |          |  
|Total derivative financial instrument activities                  |  | $                          | 232,025  |   |                            | $ | 384,389  |                            |  | $ | 26,807                      |   |  | $                           | (152,364 | ) |  | $ | 357,582  |  
|                                                                  |  |                            |          |   |                            |   |          |                            |  |   |                             |   |  |                             |          |   |  |   |          |  

Our non-cash mark-to-market changes in the fair value of our oil and natural gas derivative financial
instruments for the year ended December 31, 2009 resulted in a loss of $246.4 million compared to a gain of $493.7 million and a loss of $81.6 million for the years ended December 31, 2008 and 2007, respectively. The significant
fluctuation was, again, attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future
commodity prices.

The use of derivative financial instruments allows us to limit the impacts of volatile price fluctuations
associated with oil and natural gas. The following table presents our natural gas prices, before the impact of derivative financial instruments where average realized prices per Mcfe ranged from a high of $9.72 during the year end December 31,
2008 to a low of $4.30 during the year ended December 31, 2009 while the impact of cash settlements on derivatives decreased our price volatility from a high of $8.96 per Mcfe during the year ended December 31, 2008 to a low of $8.03 per
Mcfe for the year ended December 31, 2009, respectively.



|                                                               |  |                            |       |  |                            |   |       |                            |  |   |                             |  |  |                             |        |   |  |   |       |  
|-------------------------------------------------------------- |  | -------------------------- | ----- |  | -------------------------- | - | ----- | -------------------------- |  | - | --------------------------- |  |  | --------------------------- | ------ | - |  | - | ----- | -
|                                                               |  | Year endedDecember 31,2009 |       |  | Year endedDecember 31,2008 |   |       | Year endedDecember 31,2007 |  |   | Year to yearchange2009-2008 |  |  | Year to yearchange2008-2007 |       
|Realized pricing:                                              |  |                            |       |  |                            |   |       |                            |  |   |                             |  |  |                             |        |   |  |   |       |  
|Oil per Bbl                                                    |  | $                          | 53.72 |  |                            | $ | 96.93 |                            |  | $ | 71.17                       |  |  | $                           | (43.21 | ) |  | $ | 25.76 |  
|Natural gas per Mcf                                            |  |                            | 3.93  |  |                            |   | 9.06  |                            |  |   | 6.81                        |  |  |                             | (5.13  | ) |  |   | 2.25  |  
|Natural gas equivalent per Mcfe                                |  |                            | 4.30  |  |                            |   | 9.72  |                            |  |   | 7.22                        |  |  |                             | (5.42  | ) |  |   | 2.50  |  
|Effect of cash settlements on derivatives                      |  |                            | 3.73  |  |                            |   | (0.76 | )                          |  |   | 0.89                        |  |  |                             | 4.49   |   |  |   | (1.65 | )
|Net price per Mcfe, including derivative financial instruments |  | $                          | 8.03  |  |                            | $ | 8.96  |                            |  | $ | 8.11                        |  |  | $                           | (0.93  | ) |  | $ | 0.85  |  
|                                                               |  |                            |       |  |                            |   |       |                            |  |   |                             |  |  |                             |        |   |  |   |       |  

Our cash settlements for 2009 increased our other income by $478.5 million, or $3.73 per Mcfe compared
to cash settlements decreasing our other income by $109.3 million, or $0.76 per Mcfe, in 2008. The significant fluctuations between settlements of receipts on our derivative financial instruments demonstrates the aforementioned volatility in prices.

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



57



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In January 2008, we entered into interest rate swaps to mitigate our exposure to
fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBO rates ranging from 2.45% to 2.8%. For the year ended December 31, 2009, we had realized losses from settlements of $12.2 million and $2.0
million of cumulative non-cash unrealized losses attributable to our interest rate swaps. For the year ended December 31, 2008, we had realized gains from settlements of $0.6 million and $9.9 million of non-cash unrealized losses attributable
to our interest rate swaps. Our interest rate derivative financial instruments terminated as of February 14, 2010.

Income taxes

The following table presents a reconciliation of our income tax provision (benefit) for the years ended
December 31, 2009, 2008 and 2007.



|                                                                      |  |                            |          |   |                            |   |          |                            |  |   |        | 
|--------------------------------------------------------------------- |  | -------------------------- | -------- | - | -------------------------- | - | -------- | -------------------------- |  | - | ------ | 
|(in thousands)                                                        |  | Year endedDecember 31,2009 |          |   | Year endedDecember 31,2008 |   |          | Year endedDecember 31,2007 | 
|United States federal income taxes (benefit) at statutory rate of 35% |  | $                          | (177,207 | ) |                            | $ | (695,977 | )                          |  | $ | 38,413 | 
|Increases (reductions) resulting from:                                |  |                            |          |   |                            |   |          |                            |  |   |        | 
|Goodwill                                                              |  |                            | 43,455   |   |                            |   |         |                            |  |   |       | 
|Adjustments to the valuation allowance                                |  |                            | 141,975  |   |                            |   | 526,372  |                            |  |   | 9,336  | 
|Non-deductible compensation                                           |  |                            | 2,808    |   |                            |   | 2,321    |                            |  |   | 3,144  | 
|State tax rate change                                                 |  |                            |         |   |                            |   |         |                            |  |   | 3,078  | 
|State taxes net of federal benefit                                    |  |                            | (20,606  | ) |                            |   | (88,266  | )                          |  |   | 4,423  | 
|Other                                                                 |  |                            | 74       |   |                            |   | 517      |                            |  |   | 1,702  | 
|                                                                      |  |                            |          |   |                            |   |          |                            |  |   |        | 
|Total income tax provision                                            |  | $                          | (9,501   | ) |                            | $ | (255,033 | )                          |  | $ | 60,096 | 
|                                                                      |  |                            |          |   |                            |   |          |                            |  |   |        | 

During 2009, our income tax rate was impacted by the recognition of valuation allowances against deferred
tax assets, which were primarily due to ceiling test write-downs that caused previous book basis and tax basis differences to change from deferred tax liabilities to deferred tax assets and divestitures of properties.

During 2008, our income tax rate was impacted by the establishment of valuation allowances against deferred tax assets, which were
primarily due to ceiling test write-downs that caused previous book basis and tax basis differences to change from deferred tax liabilities to deferred tax assets. Our deferred tax assets were offset by valuation allowances after testing to
determine if the asset would meet a more likely than not criteria for realization pursuant to FASB ASC Topic 740- Income Taxes.

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 presented above.

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 ASC Subtopic 740-10 for Income Taxes on January 1, 2007. As a result of ASC Subtopic
740-10, the Company recognized zero liabilities for unrecognized tax benefits. As of December 31, 2009, 2008 and 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.



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Liquidity, capital resources and capital commitments

Overview

Our
financial strategy is to use a combination of cash flow from operations, bank financing, cash received from joint ventures, proceeds from sales of oil and natural gas properties and the issuance of equity and debt securities to fund our operations,
conduct development and exploitation activities and to fund acquisitions. Prior to 2009, we used acquisitions of producing properties and vertical drilling of development wells in established basins as our primary vehicle for growth. These
acquisitions provided us with substantial acreage with deep rights in shale resource plays, and our recent success using horizontal drilling in the Haynesville shale in East Texas/North Louisiana has created significant growth opportunities in the
area, as well as in the Bossier shale play in East Texas/North Louisiana and the Marcellus shale play in Appalachia. These additional opportunities have resulted in a shift in our focus from an acquisition-oriented strategy to horizontal drilling,
development and exploitation activities. As a result of the BG Upstream Transaction in August 2009, we increased our drilling and leasing activities within the BG AMI. Pursuant to the Joint Development Agreement, or JDA, with BG Group, BG Group also
agreed to fund 75% of our 50% interest in deep drilling projects up to a total of $400.0 million. As a result of this carried amount, our required capital expenditures will be substantially reduced during the carried period, which we project will
extend through 2011. As of December 31, 2009, approximately $367.7 million remains unfunded by BG Group under the carry provisions of the JDA.

Cash flows from operations and unused borrowing capacity under our revolving credit agreements represent the primary source of liquidity to fund our operations and our capital expenditure programs. The
primary factors impacting our cash flow from operations include (i) levels of production from our oil and natural gas properties, (ii) prices we receive for sales of oil and natural gas production, including settlement proceeds or payments
related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs for our general and administrative activities and (v) interest expense and other financing related costs. The
following table presents our liquidity and financial position as of December 31, 2009 and February 12, 2010:



|                                   |  |                  |           |  |                  |   |           | 
|---------------------------------- |  | ---------------- | --------- |  | ---------------- | - | --------- | 
|(in thousands)                     |  | December 31,2009 |           |  | February 12,2010 |  
|Cash(1) .                          |  | $                | 127,316   |  |                  | $ | 142,825   | 
|                                   |  |                 
|Borrowings under credit agreements |  |                  | 747,564   |  |                  |   | 747,564   | 
|Senior Notes(2) .                  |  |                  | 444,720   |  |                  |   | 444,720   | 
|                                   |  |                  |           |  |                  |   |           | 
|Total debt .                       |  |                  | 1,192,284 |  |                  |   | 1,192,284 | 
|                                   |  |                  |           |  |                  |   |           | 
|Net debt                           |  | $                | 1,064,968 |  |                  | $ | 1,049,459 | 
|                                   |  |                  |           |  |                  |   |           | 
|                                   |  |                 
|Consolidated borrowing base        |  | $                | 1,300,000 |  |                  | $ | 1,300,000 | 
|Unused borrowing base(3)           |  | $                | 537,235   |  |                  | $ | 537,235   | 
|Unused borrowing base plus cash(3) |  | $                | 664,551   |  |                  | $ | 680,060   | 



|(1) | Includes restricted cash of $58.9 million at December 31, 2009 and $71.4 million at February 12, 2010.
|--- | ------------------------------------------------------------------------------------------------------



|(2) | Excludes unamortized bond premium of $4.0 million.
|--- | --------------------------------------------------



|(3) | Net of $15.2 million in letters of credit.
|--- | ------------------------------------------



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Consistent with our strategy of acquiring and developing reserves, we have an objective of
maintaining financing flexibility and the use of derivative financial instruments to mitigate price fluctuations Prices for natural gas experienced significant declines beginning in the third quarter of 2008 and remained at low levels throughout
2009. As a result of these low prices, we suspended many of our vertical drilling projects as economics did not meet our internal rate of return objectives. The following table presents a comparison of our existing 2010 capital budget to our 2009
activities.



|                             |  |                         |     |  |                   |   |         |                    |  |   |                             |  |  |   |          |  
|---------------------------- |  | ----------------------- | --- |  | ----------------- | - | ------- | ------------------ |  | - | --------------------------- |  |  | - | -------- | -
|(in thousands, except wells) |  | 2010 plannedgross wells |     |  | 2010capitalbudget |   |         | 2009actualspending |  |   | Year to yearchange2010-2009 | 
|East Texas/North Louisiana   |  |                         | 138 |  |                   | $ | 255,133 |                    |  | $ | 371,065                     |  |  | $ | (115,932 | )
|Appalachia                   |  |                         | 27  |  |                   |   | 154,246 |                    |  |   | 32,173                      |  |  |   | 122,073  |  
|Mid-Continent                |  |                         |    |  |                   |   |        |                    |  |   | 8,282                       |  |  |   | (8,282   | )
|Permian and other            |  |                         | 40  |  |                   |   | 29,163  |                    |  |   | 20,692                      |  |  |   | 8,471    |  
|Midstream                    |  |                         |    |  |                   |   | 7,800   |                    |  |   | 53,122                      |  |  |   | (45,322  | )
|Corporate                    |  |                         |    |  |                   |   | 25,044  |                    |  |   | 26,198                      |  |  |   | (1,154   | )
|                             |  |                         |     |  |                   |   |         |                    |  |   |                             |  |  |   |          |  
|Total                        |  |                         | 205 |  |                   | $ | 471,386 |                    |  | $ | 511,532                     |  |  | $ | (40,146  | )
|                             |  |                         |     |  |                   |   |         |                    |  |   |                             |  |  |   |          |  

In the fourth quarter of 2008, we commenced a program to divest various oil and natural gas assets across
our entire portfolio and engaged several different brokers to assist with these divestitures. This divestiture program, combined with the BG Upstream Transaction and the BG Midstream Transaction, resulted in cash proceeds of approximately $2.1
billion, after customary closing and post-closing adjustments and provided us with substantial liquidity. We used these proceeds to pay down debt on both of our revolving credit facilities and pay off our Term Credit Agreement. As of
December 31, 2009, we had reduced our consolidated outstanding debt to $1.2 billion, a reduction of $1.8 billion from the December 31, 2008 debt levels. However, our oil and natural gas production, results of operations and future
liquidity from operations will be reduced in the near term as a result of asset sales and the reduced interest in properties sold to the BG Group.

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

As of December 31, 2009, the aggregate borrowing bases under our credit agreements, after the October 2009 borrowing base redeterminations, totaled $1.3 billion, of which $747.6 million was drawn. In
addition, we have $444.7 million outstanding under our Senior Notes due on January 11, 2011.

The U.S. House of
Representatives has adopted legislation to control and reduce GHGs. The U.S. Senate is working on similar legislation. Although it is not possible at this time to predict whether or when any such legislation will emerge from Congress, any laws or
regulations that may be adopted to restrict or reduce GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce. The EPA has also taken recent action related to
GHGs that would require large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. Although this rule does not limit the amount of GHGs that can be emitted, it could require us to incur costs to monitor,
recordkeep and report emissions of GHGs associated with our operations.

Recent events affecting liquidity

The capital and credit markets remained constrained and unpredictable throughout 2009. Actions taken by the United States government and
Federal Reserve in 2008 and 2009 through enacted legislation and



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implementation of various programs have had only limited impact in stabilizing the credit markets and promoting liquidity in financial institutions. The impacts of these actions, some of which
have not yet been fully implemented, on our industry and on us, are not determinable at this time, nor can we determine the length of time that credit markets will remain constrained, and the ultimate impact on our ability to access capital is
expected to be equally uncertain.

In addition to the turmoil in the credit markets and related uncertainties, prices for
natural gas suffered a precipitous decline beginning in the third quarter of 2008 and has continued throughout 2009. As of February 12, 2010, the spot prices for oil and natural gas were $74.13 per Bbl and $5.53 per Mmbtu compared with $79.36
per Bbl and $5.79 per Mmbtu as of December 31, 2009. NYMEX future prices for oil and natural gas have also remained depressed throughout 2009, reflecting anticipated decreased domestic and worldwide demand for oil and natural gas as a result of
the global recession and uncertainties about the depth and length of the recession and the timing of a recovery. Each of the aforementioned events could impact our near-term, and perhaps long-term, liquidity and operating revenues resulting in
changes to business plans or operations. As discussed in greater detail under Item 3. Quantitative and Qualitative Disclosures About Market Risk, we use derivative financial instruments to mitigate commodity price fluctuations and
interest rate fluctuations to manage our debt service requirements.

Our proposed capital budget for 2010 reflects targeted
capital expenditures. As in 2009, our 2010 capital program will focus on Haynesville/Bossier shale plays in East Texas/North Louisiana and we will begin to exploit the Marcellus shale play in Appalachia. Our 2009 asset sales and reduced ownership
interest in East Texas/North Louisiana properties arising from the BG Upstream Transaction, will impact our production volumes in future periods. However, the provision in the JDA for the BG Group to fund 75% of our share of drilling and development
costs on new Haynesville and other deep rights wells spud after closing, up to a total of $400.0 million, will allow us to accelerate our development of the Haynesville shale play while continuing to reduce our development cost per Mcf. While our
recent debt reduction combined with the value created by the carried portion of capital expenditures are favorable as they relate to our reliance on available credit, the credit markets remain an area of concern.

Our 71/4% senior notes with a principal balance of $444.7 million mature on January 15, 2011. We believe that our cash flows from operations and amounts
available to us under our credit facilities will provide us with sufficient liquidity to pay-off the
71/4% senior notes at maturity. Alternatively, we
believe current market conditions may provide an opportunity to refinance the Senior Notes if necessary.

Despite the ongoing problems and uncertainties existing in the capital and credit markets and commodity prices, we believe that our
capital resources from existing cash balances, anticipated cash flow from operating activities, reduced capital expenditures and remaining borrowing capacity under our credit agreements will be adequate to meet the cash requirements to fund our
operations, debt service obligations and our 2010 capital expenditure programs As discussed above, our 2009 divestiture program and BG Group joint venture transactions, generated approximately $2.1 billion is cash proceeds, which enabled us to
reduce our bank debt by $1.8 billion during 2009 and will substantially reduce our debt service requirements in 2010. Our future cash flows are subject to a number of variables including production volumes, oil and natural gas prices and drilling
and service costs.

Significant acreage acquisitions may also have an impact on our near term liquidity as these types of
acquisitions may cause an increase in our outstanding debt without any immediate cash flows or increases in our borrowing base in our credit agreements.



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Divestitures and related transactions

During 2009, we implemented our previously announced asset divestiture program to sell certain non-strategic oil and natural gas assets
and pursue a potential joint venture to accelerate development of our considerable acreage holdings in East Texas/North Louisiana in the Haynesville and Bossier shale plays. The following table summarizes the results of our 2009 divestitures and
joint venture transactions:



|                                      |  |             |           | 
|------------------------------------- |  | ----------- | --------- | 
|(in thousands)                        |  | Proceeds(1) |          
|Operating division                    |  |             |           | 
|East Texas/North Louisiana            |  |             |           | 
|BG Upstream Transaction               |  | $           | 713,779   | 
|BG Midstream Transaction              |  |             | 269,237   | 
|East Texas Transaction                |  |             | 154,299   | 
|Other East Texas / North Louisiana    |  |             | 22,327    | 
|                                      | 
|Mid-Continent                         |  |             |           | 
|Mid-Continent Transaction             |  |             | 197,730   | 
|Sheridan Transaction(2)               |  |             | 531,351   | 
|Other Mid-Continent                   |  |             | 5,482     | 
|                                      | 
|Appalachia                            |  |             |           | 
|EnerVest Transaction(2)(3)            |  |             | 129,737   | 
|                                      | 
|Permian                               |  |             | 40,042    | 
|                                      |  |             |           | 
|Total joint ventures and divestitures |  | $           | 2,063,984 | 
|                                      |  |             |           | 



|(1) | Net of selling expenses.
|--- | ------------------------



|(2) | Subject to final closing adjustments.
|--- | -------------------------------------



|(3) | Pending receipt of an additional $13.1 million of consents.
|--- | -----------------------------------------------------------

Encore transactions

On August 11, 2009, we closed on sales of assets
contained within the East Texas Transaction and the Mid-Continent Transaction with Encore for aggregate cash proceeds of approximately $352.0 million, after final closing adjustments. The oil and natural gas properties sold included (i) all of
EXCOs interests in its Gladewater area and Overton field in Gregg, Upshur and Smith counties in East Texas, or the East Texas Properties, and (ii) certain oil and natural gas properties in the Mid-Continent region of Oklahoma, Kansas and
the Texas Panhandle, or the Mid-Continent Sale, collectively the Encore Transactions.

BG Group transactions

On August 14, 2009, we closed on the BG Upstream Transaction and the BG Midstream Transaction representing the sale of an undivided
50% interest in certain oil and natural gas properties in East Texas/North Louisiana and a 50% interest in certain midstream operations, respectively, in East Texas/North Louisiana for aggregate proceeds of approximately $983.0 million, after final
closing adjustments.

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

Other than the BG Group Carry, each party will be responsible for its share of the costs and expenses associated with exploring,
developing and producing the oil and natural gas assets in the AMI. To facilitate funding these costs and expenses and to provide security to each party, BG Group and EXCO have agreed to



62



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fund periodically an escrow account created by the parties with an amount equal to estimates of certain future expenses for the following three month period. In addition to this three month
deposit, EXCO has agreed to fund one additional month of development costs into the escrow account and three additional months of operating expenses into the escrow account.

Sheridan Transaction

On November 10, 2009 we closed on the sale of
most of our remaining oil and natural gas assets located in the Mid-Continent region to Sheridan Holding Company I, LLC for cash proceeds of $531.4 million, subject to final closing adjustments. Proceeds from the sale were primarily used to reduce
balance outstanding under the EXCO Resources Credit Agreement.

EnerVest Transaction

On November 24, 2009, we consummated the sale of certain Ohio and Northwestern Pennsylvania shallow producing oil and natural gas
properties to EV Energy Partners, L.P. and related entities. Total cash proceeds from the sale were $129.7 million, subject to final closing adjustments and receipt of $13.1 million of properties sold subject to receipt of required consents.
Proceeds from the sale were primarily used to reduce the balances outstanding under the EXCO Resources Credit Agreement.

Historical
sources and uses of funds

Cash flows from operations

Our operating cash flows are driven by the quantities of our production of oil and natural gas and the prices received from the sale of
this production and revenue generated from our midstream operating activities. Prices of oil and natural gas have historically been very volatile and can significantly impact the cash from the sale our oil and natural gas production. Use of
derivative financial instruments help mitigate this price volatility. Cash expenses also impact our operating cash flow and consist primarily of oil and natural gas property operating costs, severance and ad valorem taxes, interest on our
indebtedness, general and administrative expenses and taxes on income.

Net cash provided by operating activities was $433.6
million for the year ended December 31, 2009 compared with $975.0 million for the year ended December 31, 2008. The 55.5% decrease is attributable primarily to net cash from decreased production resulting from oil and natural gas property
divestitures in 2009 and from lower average oil and natural gas prices in 2009 compared with average prices for the 2008 year. At December 31, 2009, our cash and cash equivalents balance was $68.4 million and our evergreen escrow account, which
is principally used for Haynesville development operations, was $58.9 million. On February 12, 2010, our cash, cash equivalent and restricted cash balance was $142.8 million.

We began paying quarterly dividends of $0.025 per share on our common stock in the fourth quarter of 2009. During the fourth quarter we
paid two dividends to our common shareholders which totaled $10.6 million.

Investing activities and transactions

In recent years, a significant amount of our growth has been through acquisitions of existing producing and
non-producing oil and natural gas properties and related assets. These acquisitions have been funded to a great extent by borrowings under credit agreements and term loan agreements, as well as issuance of equity. As discussed above, the
deterioration in the U.S. and worldwide credit and equity markets has significantly diminished our ability to fund additional growth in the near term through these capital sources.



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Acquisitions and capital expenditures

The following table presents our capital expenditures and acquisitions for the years ended December 31, 2009, 2008 and 2007.



|                                             |  |                            |         |  |                            |   |           |                            |  |   |           | 
|-------------------------------------------- |  | -------------------------- | ------- |  | -------------------------- | - | --------- | -------------------------- |  | - | --------- | 
|(in thousands)                               |  | Year endedDecember 31,2009 |         |  | Year endedDecember 31,2008 |   |           | Year endedDecember 31,2007 | 
|Capital expenditures:                        |  |                            |         |  |                            |   |           |                            |  |   |           | 
|Oil and natural gas property acquisitions(1) |  | $                          | 233,634 |  |                            | $ | 700,174   |                            |  | $ | 2,343,829 | 
|Midstream acquisitions                       |  |                            |        |  |                            |   | 66,172    |                            |  |   | 119,409   | 
|Lease purchases(1)                           |  |                            | 106,040 |  |                            |   | 187,134   |                            |  |   | 21,415    | 
|Development capital expenditures             |  |                            | 299,837 |  |                            |   | 693,173   |                            |  |   | 446,675   | 
|Midstream capital additions                  |  |                            | 53,122  |  |                            |   | 54,993    |                            |  |   | 16,980    | 
|Corporate and other .                        |  |                            | 52,533  |  |                            |   | 53,834    |                            |  |   | 31,419    | 
|                                             |  |                            |         |  |                            |   |           |                            |  |   |           | 
|Total capital expenditures                   |  | $                          | 745,166 |  |                            | $ | 1,755,480 |                            |  | $ | 2,979,727 | 
|                                             |  |                            |         |  |                            |   |           |                            |  |   |           | 



|(1) | The year ended December 31, 2009 includes $251.5 million of lease purchases and property acquisitions included in the BG AMI. We offered BG Group 50% of those
acquisitions which BG Group will reimburse us upon acceptance of these offers. As of December 31, 2009, BG Group had pending outstanding offers totaling $125.8 million for their 50% share of this acreage. In 2010, BG Group paid $53.8 million to
us for those assets.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Our 2009 acquisitions emphasized undeveloped acreage. Our 2008 and 2007 acquisitions were
principally producing and undeveloped oil and natural gas properties.

During 2008, we completed the acquisitions of oil and
natural gas properties, undeveloped acreage and other oil and natural gas assets totaling $766.3 million. These acquisitions included the Appalachian Acquisition, the New Waskom Acquisition and the Danville Acquisition.

In addition to these acquisitions of producing oil and natural gas properties and midstream assets, during the second and third quarters
of 2008, we conducted two leasing programs of undeveloped acreage in East Texas/North Louisiana and Appalachia to exploit the Haynesville, Marcellus and Huron shales. In Appalachia, our existing shallow production areas and newly acquired leasehold
interests hold deep rights in the Marcellus and Huron shale formations. Similarly, in East Texas/ North Louisiana, our existing production areas and newly acquired leasehold interests hold deep rights in the Haynesville/Bossier shale play. We spent
approximately $64.9 million in the Haynesville/Bossier shale plays in East Texas/North Louisiana and approximately $92.1 million in the Marcellus and Huron shale plays in the Appalachia region of the United States during 2008.

During 2007, we consummated acquisitions of oil and natural gas properties and undeveloped acreage totaling $2.47 billion, including the
Vernon Acquisition and the Southern Gas Acquisition.

2010 Capital budget

Our capital expenditures budget for 2010 will continue to emphasize development of our significant shale resources in the Haynesville
Shale play in East Texas/North Louisiana in conjunction with our joint venture with BG Group and increased emphasis of our significant acreage holdings covering the Marcellus Shale play in Appalachia.

The 2010 capital expenditures emphasize horizontal shale development in East Texas/North Louisiana and in Appalachia. Presently, we have
budgeted approximately $471.4 million for capital expenditures in 2010, of which we are contractually obligated to spend $70.7 million as of December 31, 2009. We expect to utilize our current cash balances, including funds which we have
already placed in our restricted accounts to fund Haynesville development, cash flow generated from operations and available funds under our credit agreements in 2010 to fund capital expenditures and acquisitions, if any. The capital budget for 2010
reflects a 7.8% decrease from 2009 actual capital expenditures, excluding acquisitions of approximately $233.6 million. The 2010 capital budget of $471.4 million is net of approximately $205.1 million of BG Carry covering our interests in certain
drilling and completion costs in East Texas/North Louisiana.



64



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Future cash flows are subject to a number of variables including production volumes,
fluctuations in oil and natural gas prices and our ability to service the debt incurred in connection with our acquisitions. If cash flows decline we may be required to further reduce our capital expenditure budget, which in turn may affect our
production in future periods. Our cash flow from operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures.

Credit agreements and long-term debt

As of February 12, 2010, we have total debt outstanding aggregating $1.2 billion consisting of two credit agreements and Senior Notes of $444.7 million due in January 2011. Terms and
considerations of each of the debt obligations are discussed below. We are presently in discussions with our banking group to consolidate our two credit agreements into one facility.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement,
pursuant to the fifth amendment effective on October 2, 2009, has a borrowing base of $450.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. The
borrowing base is redetermined semi-annually, with EXCO and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of
each year. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO may have in place derivative financial instruments covering no more
than 80% of its forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted
production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The
EXCO Resources Credit Agreement matures on March 30, 2012.

The fifth amendment to the EXCO Resources
Credit Agreement, among other things, modified the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the fifth amendment, EXCO may declare and pay cash dividends on its common stock in an
amount not to exceed $50.0 million in any four consecutive fiscal quarters, provided that as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) EXCO has at least
10% of its borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under EXCOs
71/4% Senior Notes Indenture.

The EXCO Resources Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for
agreements of this type. The interest rate ranges from LIBOR plus 175 basis points, or bps, to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR
plus 75 bps to ABR plus 150 bps depending upon borrowing base usage.

On February 12, 2010, we had $81.5 million of
outstanding indebtedness and $353.3 million of available borrowing capacity under the EXCO Resources Credit Agreement. On February 12, 2010, the one month LIBOR was 0.23%, which would result in an interest rate of approximately 1.98% on
any new indebtedness we may incur under the EXCO Resources Credit Agreement.

As of December 31, 2009, EXCO was in
compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:



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



| |  |  | not permit our ratio of consolidated funded indebtedness (as defined) to consolidated EBITDAX (as defined) to be greater than (i) 4.0 to 1.0 at
the end of any fiscal quarter ending on or after December 31, 2008 up to and including December 31, 2009, (ii) 3.75 to 1.0 at the end of the fiscal quarter ending on
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



65



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| | March 31, 2010 and (iii) 3.50 to 1.0 beginning with the quarter ending June 30, 2010 and each quarter end thereafter; and
| | -------------------------------------------------------------------------------------------------------------------------



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

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

EXCO Operating Credit Agreement

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

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

The EXCO Operating Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for
agreements of this type. The interest rate ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps
depending upon borrowing base usage.

On February 12, 2010, we had $666.1 million of outstanding indebtedness and
$183.9 million available borrowing capacity under the EXCO Operating Credit Agreement. On February 12, 2010, the one month LIBO rate was 0.23%, which would result in an interest rate of approximately 2.48% on any new indebtedness we may incur
under the EXCO Operating Credit Agreement.

As of December 31, 2009, EXCO Operating was in compliance with the financial
covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:



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



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



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

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



66



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Term Credit Agreement

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

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

The unamortized balance of deferred financing costs attributable to the Term Credit Agreement of approximately $9.9 million was written
off and is included in interest expense in the year ended December 31, 2009.

71/4% senior notes due January 15, 2011

As of December 31, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes
at December 31, 2009 was $4.0 million. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.8 million on December 31, 2009.

Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year. Effective
January 15, 2007, we may redeem some or all of the Senior Notes for the redemption price set forth in the Senior Notes. On January 15, 2010, we paid $16.1 million of interest on the Senior Notes. Another interest payment of $16.1 million
will be due on July 15, 2010. We presently have sufficient borrowing capacity under the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement to pay the Senior Notes.

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



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



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



| |  |  | make investments;
| | - |  | -----------------



| |  |  | create liens on our assets;
| | - |  | ---------------------------



| |  |  | enter into sale/leaseback transactions;
| | - |  | ---------------------------------------



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



| |  |  | engage in transactions with our affiliates;
| | - |  | -------------------------------------------



| |  |  | transfer or issue shares of stock of subsidiaries;
| | - |  | --------------------------------------------------



| |  |  | transfer or sell assets; and
| | - |  | ----------------------------



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

Preferred Stock

We paid cash dividends totaling $82.8 million to the holders of our Preferred Stock between January 1, 2008 and July 18, 2008,
the date upon which the Preferred Stock was converted into our common stock. On July 18, 2008, we converted all outstanding shares of our Preferred Stock into a total of approximately 105.2 million



67



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shares of our common stock. The conversion of the Preferred Stock has the effect of increasing the book value of shareholders equity by approximately $2.0 billion. We also paid all accrued
but unpaid dividends in cash totaling approximately $12.8 million to the holders of the converted shares of Preferred Stock as of July 18, 2008. After July 18, 2008, dividends ceased to accrue on the Preferred Stock and all rights of the
holders with respect to the Preferred Stock terminated, except for the right to receive the whole shares of common stock issuable upon conversion, accrued dividends through July 18, 2008 and cash in lieu of any fractional shares. The conversion
of all outstanding shares of Preferred Stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.

Derivative financial instruments

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

Oil and natural gas derivatives

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

Our objective in entering into oil and natural gas derivative contracts is to mitigate the impact of price fluctuations and achieve a more predictable cash flow associated with our acquisition activities
and 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, 2009, we had contracts in place for the volumes and prices
shown below:



|                              |  |                       |        |  |                                       |   |      |                      |  |  |                                     |  |  |   |        | 
|----------------------------- |  | --------------------- | ------ |  | ------------------------------------- | - | ---- | -------------------- |  |  | ----------------------------------- |  |  | - | ------ | 
|(in thousands, except prices) |  | NYMEX gasvolumeMmbtu |        |  | Weightedaveragecontractprice perMmbtu |   |      | NYMEX oilvolumeBbls |  |  | Weightedaveragecontractprice perBbl | 
|Swaps:                        |  |                       |        |  |                                       |   |      |                      |  |  |                                     |  |  |   |        | 
|Q1 2010                       |  |                       | 15,915 |  |                                       | $ | 7.80 |                      |  |  | 110                                 |  |  | $ | 114.96 | 
|Q2 2010                       |  |                       | 16,078 |  |                                       |   | 7.67 |                      |  |  | 111                                 |  |  |   | 114.96 | 
|Q3 2010                       |  |                       | 16,240 |  |                                       |   | 7.67 |                      |  |  | 113                                 |  |  |   | 114.96 | 
|Q4 2010                       |  |                       | 16,240 |  |                                       |   | 7.70 |                      |  |  | 113                                 |  |  |   | 114.96 | 
|2011                          |  |                       | 12,775 |  |                                       |   | 7.48 |                      |  |  | 456                                 |  |  |   | 116.00 | 
|2012                          |  |                       | 5,490  |  |                                       |   | 5.91 |                      |  |  | 92                                  |  |  |   | 109.30 | 
|2013                          |  |                       | 5,475  |  |                                       |   | 5.99 |                      |  |  |                                    |  |  |   |       | 
|2014                          |  |                       |       |  |                                       |   |     |                      |  |  |                                    |  |  |   |       | 

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates
on $700.0 million in principal through February 14, 2010 at LIBO rates ranging from 2.45% to 2.8%. For the year ended December 31, 2009, we had realized losses from settlements of $12.2 million. The fair value of our interest rate
swaps was a liability of $2.0 million as of December 31, 2009.

Off-balance sheet arrangements

None.



68



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Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at December 31, 2009:



|                                                            |  |                        |        |  |                   |   |           |                    |  |   |                     |  |  |       |         |  |  |   |           | 
|----------------------------------------------------------- |  | ---------------------- | ------ |  | ----------------- | - | --------- | ------------------ |  | - | ------------------- |  |  | ----- | ------- |  |  | - | --------- | 
|                                                            |  | Payments due by period |       
|(in thousands)                                              |  | Less thanone year      |        |  | One tothree years |   |           | Three tofive years |  |   | More thanfive years |  |  | Total |        
|Long-term debtSenior Notes(1)                              |  | $                      |       |  |                   | $ | 444,720   |                    |  | $ |                    |  |  | $     |        |  |  | $ | 444,720   | 
|Long-term debtEXCO Resources Credit Agreement(2)           |  |                        |       |  |                   |   | 81,486    |                    |  |   |                    |  |  |       |        |  |  |   | 81,486    | 
|Long-term debtEXCO Operating Credit Agreement(3)           |  |                        |       |  |                   |   | 666,078   |                    |  |   |                    |  |  |       |        |  |  |   | 666,078   | 
|Firm transportation services and other fixed commitments(4) |  |                        | 40,570 |  |                   |   | 69,548    |                    |  |   | 71,666              |  |  |       | 199,515 |  |  |   | 381,299   | 
|Operating leases                                            |  |                        | 7,357  |  |                   |   | 11,461    |                    |  |   | 10,063              |  |  |       | 4,329   |  |  |   | 33,210    | 
|Drilling contracts                                          |  |                        | 51,438 |  |                   |   | 37,655    |                    |  |   |                    |  |  |       |        |  |  |   | 89,093    | 
|                                                            |  |                        |        |  |                   |   |           |                    |  |   |                     |  |  |       |         |  |  |   |           | 
|Total contractual obligations                               |  | $                      | 99,365 |  |                   | $ | 1,310,948 |                    |  | $ | 81,729              |  |  | $     | 203,844 |  |  | $ | 1,695,886 | 
|                                                            |  |                        |        |  |                   |   |           |                    |  |   |                     |  |  |       |         |  |  |   |           | 



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



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



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



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



69



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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
Amendment No. 2 to its annual report to be signed on its behalf by the undersigned, thereunto duly authorized.



|                       |  |                                   |  |                                     
|---------------------- |  | --------------------------------- |  | ------------------------------------
|Date: January 24, 2011 |  | EXCO RESOURCES, INC. (Registrant)
|                       |  |                                  
|                       |  | By:                               |  | /s/    DOUGLAS H. MILLER            
|                       |  |                                   |  | Douglas H. Miller                   
|                       |  |                                   |  | Chairman and Chief Executive Officer





70



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INDEX TO EXHIBITS



|              |  |                                                                                                                                                                                                                                                                                                                                                                                         
|------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                                                                 
|2.1           |  | Asset Purchase Agreement, dated December 7, 2007, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC and Energy Search,
Incorporated, as sellers, filed as an Exhibit to EXCOs Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.                                
|              | 
|2.2           |  | First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and Energy
Search, incorporated, as sellers, filed as an exhibit to EXCOs Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.           
|              | 
|2.3           |  | Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCOs
Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                                                                                  
|              | 
|2.4           |  | Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCOs Quarterly
Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                                                                                        
|              | 
|2.5           |  | Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as
an exhibit to EXCOs Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                                                  
|              | 
|2.6           |  | Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to
EXCOs Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.                                                                                 
|              | 
|2.7           |  | First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production
Company, LLC, as buyer, filed as an exhibit to EXCOs Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                     
|              | 
|2.8           |  | Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production
Company, LLC, as buyer, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.                            
|              | 
|2.9           |  | Purchase and Sale Agreement, dated September 29, 2009, by and between EXCONorth Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P.,
EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCOs Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
|              | 
|2.10          |  | Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to
EXCOs Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.                                                                                                      
|              | 
|3.1           |  | Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCOs Current Report on Form 8-K, dated February 8, 2006 and filed on
February 14, 2006 and incorporated by reference herein.                                                                                                                                                     
|              | 
|3.2           |  | Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCOs Current Report on Form 8-K, dated
August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.                                                                                                                         



71



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|              |  |                                                                                                                                                                                                                                                                                                                               
|------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                       
|3.3           |  | Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCOs Current Report on Form 8-K, dated March 4, 2009 and filed on March 6, 2009 and
incorporated by reference herein.                                                                                                                    
|              | 
|3.4           |  | Statement of Designation of Series A-1 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCOs Form 8-K dated March 28,
2007 and filed on April 2, 2007 and incorporated by reference herein.                                                                            
|              | 
|3.5           |  | Statement of Designation of Series A-2 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCOs Form 8-K dated March 28,
2007 and filed on April 2, 2007 and incorporated by reference herein.                                                                            
|              | 
|3.6           |  | Statement of Designation of Series B 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007
and filed on April 2, 2007 and incorporated by reference herein.                                                                              
|              | 
|3.7           |  | Statement of Designation of Series C 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007
and filed on April 2, 2007 and incorporated by reference herein.                                                                              
|              | 
|3.8           |  | Statement of Designation of Series A-1 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007 and filed on
April 2, 2007 and incorporated by reference herein.                                                                                                           
|              | 
|3.9           |  | Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007 and filed on April 2, 2007
and incorporated by reference herein.                                                                                                           
|              | 
|4.1           |  | Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as an Exhibit to EXCOs Annual
Report on Form 10-K for 2008 filed February 26, 2009 and incorporated by reference herein.                                                       
|              | 
|4.2           |  | First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of
January 27, 2004, filed as an Exhibit to EXCOs Registration Statement on Form S-4 filed March 25, 2004 and incorporated by reference herein.
|              | 
|4.3           |  | Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCOs Annual Report
on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.                                                              
|              | 
|4.4           |  | Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCOs Current Report on
Form 8-K filed on February 21, 2006 and incorporated by reference herein.                                                                    
|              | 
|4.5           |  | Form of 71/4% Global Note Due 2011, filed as an Exhibit to EXCOs Quarterly Report on Form 10-Q, filed on May 6, 2009 and incorporated by reference herein.                                                                                                                                                                   
|              | 
|4.6           |  | Specimen Stock Certificate for EXCOs common stock, filed as an Exhibit to EXCOs Amendment No. 2 to the Form S-1 (File No. 333-129935) filed on January 27, 2006 and
incorporated by reference herein.                                                                                                                       
|              | 
|4.7           |  | Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee,
filed as an Exhibit to EXCOs Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.     



72



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|              |  |                                                                                                                                                                                                                                                                                                                                                
|------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                        
|4.8           |  | Fifth Supplemental Indenture, dated as of May 2, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to
EXCOs Current Report on Form 8-K, dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                        
|              | 
|4.9           |  | Sixth Supplemental Indenture, dated as of February 12, 2008, by and among EXCO Resources, Inc., EXCO Services, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to
EXCOs Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.                                                  
|              | 
|4.10          |  | First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an
Exhibit to EXCOs Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
|              | 
|4.11          |  | Seventh Supplemental Indenture, dated as of June 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed as an
exhibit to EXCOs Quarterly Report on Form 10-Q, filed on August 6, 2008 and incorporated by reference herein.                                               
|              | 
|4.12          |  | Eighth Supplemental Indenture, dated as of December 31, 2008, by and among EXCO Resources, Inc., EXCO Mid-Continent MLP, LLC and Wilmington Trust Company, as Trustee, filed as an
Exhibit to EXCOs Annual Report on Form 10-K for 2008 filed February 26, 2009 and incorporated herein by reference.                                         
|              | 
|10.1          |  | Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as an Exhibit to EXCOs Annual
Report on Form 10-K for 2008 filed February 26, 2009 and incorporated by reference herein.                                                                        
|              | 
|10.2          |  | First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of
January 27, 2004, filed as an Exhibit to EXCOs Registration Statement on Form S- 4 filed March 25, 2004 and incorporated by reference herein.                
|              | 
|10.3          |  | Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an
Exhibit to EXCOs Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.                                                
|              | 
|10.4          |  | Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCOs Current Report on
Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.                                       
|              | 
|10.5          |  | Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as
Trustee, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.                      
|              | 
|10.6          |  | Form of 71/4% Global Note Due 2011, filed as an Exhibit to EXCOs Quarterly Report on Form 10-Q, filed May 6, 2009 and incorporated by reference herein.                                                                                                                                                                                       
|              | 
|10.7          |  | Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and
incorporated by reference herein.*                                                                                                                                    



73



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|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                                                                                                                                            
|10.8          |  | Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated November
14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*                                                                                                                                                                                                       
|              | 
|10.9          |  | Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated November
14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*                                                                                                                                                                                                    
|              | 
|10.10         |  | Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCOs Registration Statement on Form S-8 (File No.
333-132551) filed on March 17, 2006 and incorporated by reference herein.*                                                                                                                                                                                                         
|              | 
|10.11         |  | Third Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007
and incorporated by reference herein.*                                                                                                                                                                                                                                            
|              | 
|10.12         |  | Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCOs Current Report on Form 8-K, dated November 14, 2007 and filed on November 16,
2007 and incorporated by reference herein.                                                                                                                                                                                                                                            
|              | 
|10.13         |  | Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCOs Annual Report on Form 10-K for 2009 filed February
24, 2010 and incorporated by reference herein.                                                                                                                                                                                                                                       
|              | 
|10.14         |  | Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007
and filed on April 2, 2007 and incorporated by reference herein.*                                                                                                                                                                                                                   
|              | 
|10.15         |  | Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, ACOF EXCO, L.P., ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares
EXCO, L.P. and Ares EXCO 892 Investors, L.P, filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.                                                                                                         
|              | 
|10.16         |  | Amended and Restated Credit Agreement, dated as of March 30, 2007, among EXCO Partners Operating Partnership, LP, as Borrower, certain subsidiaries of Borrower, as Guarantors, the
lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger, filed as an Exhibit to EXCOs Form 8-K dated March 28, 2007 and filed on April 2, 2007 and
incorporated by reference herein.
|              | 
|10.17         |  | Second Amended and Restated Credit Agreement, dated as of May 2, 2007, among EXCO Resources, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined
therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger, filed as an Exhibit to EXCOs Form 8-K dated May 2, 2007 and filed on May 8, 2007 and incorporated by
reference herein.                        
|              | 
|10.18         |  | Fifth Supplemental Indenture, dated as of May 2, 2007, by and among EXCO Resources, Inc., Southern G Holdings, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to
EXCOs Current Report on Form 8-K, dated May 2, 2007 and filed on May 8, 2007 and incorporated by reference herein.                                                                                                                                                            
|              | 
|10.19         |  | 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.                                                                                                           



74



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|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                                                                                                                                            
|10.20         |  | Sixth Supplemental Indenture, dated as of February 12, 2008, by and among EXCO Resources, Inc., EXCO Services, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to
EXCOs Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.                                                                                                                                                                      
|              | 
|10.21         |  | Counterpart Agreement, dated February 4, 2008, to that Certain Second Amended and Restated Credit Agreement, dated May 2, 2007, among EXCO Resources, Inc., as Borrower, and certain
subsidiaries of Borrower and the lender parties thereto, filed as an Exhibit to EXCOs Annual Report on Form 10-K for 2007 filed February 29, 2008 and incorporated by reference herein.                                                                                      
|              | 
|10.22         |  | 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.                            
|              | 
|10.23         |  | 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.                
|              | 
|10.24         |  | First Amendment to Asset Purchase Agreement, dated February 20, 2008, between EXCO Appalachia, Inc., as purchaser, and EOG Resources, Inc., EOG Resources Appalachian LLC, and
Energy Search, Incorporated, as sellers, filed as an exhibit to EXCOs Current Report on Form 8-K dated February 20, 2008 and filed on February 26, 2008 and incorporated by reference herein.                                                                                      
|              | 
|10.25         |  | Seventh Supplemental Indenture, dated as of September 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed as
an Exhibit to EXCOs Quarterly Report on Form 10-Q filed on August 6, 2008 and incorporated by reference herein.                                                                                                                                                               
|              | 
|10.26         |  | Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries as guarantors,
and JP Morgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K dated July 14, 2008 and filed on July 16, 2008 and incorporated by reference
herein.                                    
|              | 
|10.27         |  | Second Amendment to Second Amended and Restated Credit Agreement, dated as of July 14, 2008 and effective as of June 30, 2008, among EXCO Resources, Inc., as borrower, and
certain of its subsidiaries, as guarantors, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated July 14, 2008 and filed on July 16, 2008
and incorporated by reference herein.
|              | 
|10.28         |  | Seventh Supplemental Indenture, dated as of June 30, 2008, by and among EXCO Resources, Inc., EXCO-North Coast Energy, Inc. and Wilmington Trust Company, as Trustee, filed as an
exhibit to EXCOs Quarterly Report on Form 10-Q, filed on August 6, 2008 and incorporated by reference herein.                                                                                                                                                                   
|              | 
|10.29         |  | Third Amendment to Amended and Restated Credit Agreement, dated as of December 1, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries, as
guarantors, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated December 1, 2008 and filed on December 5, 2008 and incorporated
by reference herein.                           



75



---

|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|10.30         |  | Senior Unsecured Term Credit Agreement, dated as of December 8, 2008, among EXCO Operating Company, LP, as borrower, and certain of its subsidiaries, as guarantors, and
JPMorgan Chase Bank, N.A. as administrative agent, J.P. Morgan Securities Inc., as sole book runner and lead arranger, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated December 8, 2008
and filed on December 8, 2008 and incorporated by reference herein.
|              | 
|10.31         |  | Third Amendment to Second Amended and Restated Credit Agreement, dated as of February 4, 2009, among EXCO Resources, Inc., as borrower, and certain of its subsidiaries, as
guarantors, and JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated February 4, 2009 and filed on February 5, 2009 and incorporated
by reference herein.                                                
|              | 
|10.32         |  | Eighth Supplemental Indenture, dated as of December 31, 2008, by and among EXCO Resources, Inc., EXCO Mid-Continent MLP, LLC and Wilmington Trust Company, as Trustee, filed as
an Exhibit to EXCOs Annual Report on Form 10-K for 2008 filed February 26, 2009 and incorporated by reference herein.                                                                                                                                                                                   
|              | 
|10.33         |  | Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of April 17, 2009, among EXCO Resources, Inc., as borrower, certain of its subsidiaries, as
guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated April 17, 2009 and filed on April 20, 2009 and incorporated by
reference herein.                                                             
|              | 
|10.34         |  | Fourth Amendment to Amended and Restated Credit Agreement, dated as of April 17, 2009, among EXCO Operating Company, LP, as borrower, certain of its subsidiaries, as
guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated April 17, 2009 and filed on April 20, 2009 and incorporated by
reference herein.                                                              
|              | 
|10.35         |  | Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of October 1, 2009, among EXCO Resources, Inc., as borrower, certain of its subsidiaries, as guarantors,
JPMorgan Chase Bank, N.A., as administrative agent, and the lenders signatories thereto, filed as an exhibit to EXCOs Current Report on Form 8-K, dated September 29, 2009 and filed on October 5, 2009 and incorporated by reference
herein.                                                        
|              | 
|10.36         |  | Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCOs
Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                                                                                                                                                                                   
|              | 
|10.37         |  | Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCOs Quarterly
Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                                                                                                                                                                                         
|              | 
|10.38         |  | Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer,
filed as an exhibit to EXCOs Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                                                                                                                                                   
|              | 
|10.39         |  | Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCOs Current Report on Form 8-K, dated June 4,
2009 and filed on June 10, 2009 and incorporated by reference herein.                                                                                                                                                                                                                                       
|              | 
|10.40         |  | Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to
EXCOs Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.                                                                                                                                                                           



76



---

|              |  |                                                                                                                                                                                                                                                                                                                                                                                           
|------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                                                                                                                   
|10.41         |  | Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to
EXCOs Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.                                                                                   
|              | 
|10.42         |  | Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated August 14, 2009, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated August
11, 2009 and filed on August 17, 2009 and incorporated by reference herein.                                                                                                                                 
|              | 
|10.43         |  | First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production
Company, LLC, as buyer, filed as an Exhibit to EXCOs Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.                                                       
|              | 
|10.44         |  | Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production
Company, LLC, as buyer, filed as an Exhibit to EXCOs Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.                              
|              | 
|10.45         |  | Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO  North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P.,
EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCOs Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
|              | 
|10.46         |  | Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to
EXCOs Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.                                                                                                        
|              | 
|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 as an Exhibit to EXCOs Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated by reference herein.                                                                                                                                                                                                                           
|              | 
|23.1          |  | Consent of KPMG LLP, filed as an Exhibit to EXCOs Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated by reference herein.                                                                                                                                                                                                                                      
|              | 
|23.2          |  | Consent of Lee Keeling and Associates, Inc., filed herewith.                                                                                                                                                                                                                                                                                                                              
|              | 
|23.3          |  | Consent of Haas Petroleum Engineering Services, 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.                                                                                                                                                                                                                                               



77



---

|              |  |                                                                                                                                                                                                                                                                                        
|------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description of Exhibits                                                                                                                                                                                                                                                                
|              | 
|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 as an Exhibit to
EXCOs Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated by reference herein.
|              | 
|99.1          |  | 2009 Reports of Lee Keeling and Associates, Inc., filed herewith.                                                                                                                                                                                                                      
|              | 
|99.2          |  | 2009 Report of Haas Petroleum Engineering Services, Inc., filed herewith.                                                                                                                                                                                                              



|* | These exhibits are management contracts.
|- | ----------------------------------------



78