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Article by DailyStocks_admin    (12-20-11 12:59 AM)

Description

EXCO Resources. Director, 10% Owner FUND GP I, L.P. OAKTREE bought 2000000 shares on 12-14-2011 at $ 9.9

BUSINESS OVERVIEW

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 31.

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 with a focus on shale resource plays. Our principal operations are conducted in key North American oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia, respectively. As of December 31, 2010, our Proved Reserves were approximately 1.5 Tcfe, of which 97.1% were natural gas and 54.8% were Proved Developed Reserves. As of December 31, 2010, the related PV-10 of our Proved Reserves was approximately $1.4 billion, and the Standardized Measure of our Proved Reserves was $1.2 billion (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, 2010, we produced 112.0 Bcfe of oil and natural gas resulting in a Reserve Life of approximately 13.4 years.

On October 29, 2010, our Chairman and Chief Executive Officer, Douglas H. Miller presented a letter to our board of directors indicating an interest in acquiring all of the outstanding shares of our stock not already owned by Mr. Miller for a cash purchase price of $20.50 per share. The proposal does not represent a definitive offer and there is no assurance that a definitive offer will be made or accepted, that any agreement will be executed or that any transaction will be consummated.

Our board of directors established a special committee on November 4, 2010 comprised of two of our independent directors to, among other things, evaluate and determine the Company’s response to the October 29, 2010 proposal. The special committee retained Kirkland & Ellis LLP and Jones Day as its counsel and Barclays Capital, Inc. and Evercore Partners as its financial advisors to assist it in, among other things, evaluating and determining the Company’s response to the proposal. See “Note 19. Acquisition Proposal” of the notes to our consolidated financial statements for further information regarding the proposal.

Our business strategy

Prior to 2009, we used acquisitions of producing properties with vertical development drilling and workover opportunities in established producing areas as our primary vehicle for growth. As a result of those acquisitions, we accumulated an inventory of drilling locations and acreage holdings with significant potential in the Haynesville/Bossier and Marcellus shale resource plays. During 2008, we shifted our focus to exploit these shales primarily through horizontal drilling. Currently, our acquisition strategy is focused on increasing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We continue to develop our conventional Permian assets and certain vertical drilling opportunities in East Texas, North Louisiana and Appalachia as economic conditions permit. Our 2011 development strategy is focused on the Haynesville/Bossier shale area in East Texas/North Louisiana and we have increased our activities in the Marcellus shale, principally in Pennsylvania.

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 two prominent shale plays in the United States. In East Texas and North Louisiana, we currently hold approximately 76,000 net acres in the Haynesville/Bossier shales and in Appalachia we currently hold approximately 140,000 net acres in the Marcellus shale. Our Haynesville operations began in 2008 when we commenced with technical evaluations and drilling of test wells. In 2008, we drilled and completed our first horizontal well in the play. Since we commenced our horizontal drilling program in the Haynesville shale, we have spud 164 operated horizontal wells through December 31, 2010, entered into a joint venture with affiliates of BG Group plc, or BG Group, and in 2010, jointly acquired with BG Group approximately 48,000 net acres (24,000 net to EXCO) in Shelby, Nacogdoches and San Augustine Counties in East Texas, or the Shelby Area. We own working interests in 77 Haynesville horizontal wells operated by others. We continue to work closely with our midstream operations to coordinate drilling and completion timing of our wells, which allows us to flow new completions to sales promptly after fracture stimulation.

In our Appalachia region, we entered into another joint venture with BG Group in June 2010 covering our holdings in the Appalachia basin, including the Marcellus shale resource play. We plan to use a similar process in Marcellus development that was used in the Haynesville shale, with principal activities focused on technical evaluations of our acreage holdings, expansion of our technical staff, evaluation of test wells and a disciplined appraisal drilling program. Our significant held-by-production position allows us to dictate our pace of development in the Marcellus shale. We have commenced a horizontal drilling program with an objective to appraise our existing fields by mid 2011. During 2011, we plan to operate an average of four horizontal drilling rigs in the Marcellus shale. We are currently using two of the rigs to continue appraisal of our acreage and we plan to use two additional rigs to begin development in west central and Northeast Pennsylvania.


• Leverage our joint ventures

The shale resource plays are capital intensive and require significant expenditures for drilling, completing, treating and pipeline take-away capacity. We have entered into joint venture transactions with BG Group in our shale resource areas. These joint ventures allow us to accelerate development and appraisal programs in our upstream business. Because our midstream joint ventures are also with BG Group, our upstream and midstream objectives are aligned.


• Expand our midstream assets

We jointly own midstream companies in our East Texas/North Louisiana and Appalachia operating areas with BG Group. These assets enhance our ability to promptly hook-up our wells for delivery of our production to markets. We completed construction of a 36-inch diameter 27-mile header system in DeSoto Parish, Louisiana in 2010 and are completing construction of facilities in the Shelby Area. In Appalachia, we intend to pursue similar midstream expansions as part of our operating strategy. In addition to ensuring delivery of our production, these expansions provide opportunities to gather 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 infill drilling, exploratory drilling, workovers and recompletions. In 2010, we drilled and completed 205 wells with a 99.0% drilling success rate. Our natural gas vertical drilling program remains suspended due to low commodity prices, except in our Permian region as these wells contain high oil and natural gas liquids content. As of December 31, 2010, we have identified 11,933 drilling locations and 1,107 exploitation projects across our portfolio.

• Maintain financial flexibility

We employ the use of debt and equity, joint ventures with BG Group and 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 structure.

On September 15, 2010, we closed an underwritten offering of $750.0 million aggregate principal amount of 7.5% Senior Notes due 2018, or the 2018 Notes. We received proceeds of approximately $724.1 million from the offering, after deducting an original issue discount of $11.0 million and commissions, offering fees and expenses of $14.9 million. We used a portion of the net proceeds from the offering to redeem all of our outstanding 71/4% Senior Notes due 2011 for $444.7 million, or the 2011 Notes, in accordance with the terms of the indenture under which those notes were issued.

We added derivative financial instruments to our portfolio in 2011 and plan to add to the portfolio as opportunities arise.


• 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. We completed a significant divestiture program in 2009 when we divested significant non-core conventional assets in East Texas and substantially all of our holdings in the state of Ohio and the Mid-Continent region.


• Seek acquisitions that meet our strategic and financial objectives in our core operating areas

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 agreement. As a result, our acreage acquisition strategy will be dependent on our available borrowing base. Acreage acquisitions within the areas covered by our joint ventures with BG Group are offered to BG Group and provide an additional source of funds to pay for these acquisitions.


• 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 appraisal drilling programs in several areas and development drilling in west central and Northeast Pennsylvania. We continue to exploit our Permian assets, which have resulted in higher oil production than originally expected.

Plans for 2011

Our 2011 strategy focuses in three areas. Our Haynesville and Bossier shale plans are characterized by development activities based on our past performance coupled with the maturity of our midstream infrastructure. In the Marcellus shale, our emphasis is centered on increasing the technical understanding of the play and conducting development and appraisal drilling programs. As we gain a more robust understanding of the Marcellus shale play, our midstream strategy will become more clearly defined. The Permian Basin region provides superior returns driven by crude oil and high natural gas liquids content. As a result, we plan to continue our two rig Permian drilling program throughout 2011.

Our business strategy in 2011 also includes significant flexibility due to the high concentration of natural gas associated with our shale plays. At current natural gas price levels of $4.00-$5.00 per Mcf, we plan to balance our drilling programs with selective acquisitions. In a low natural gas price environment, which we presently define as under $4.00 per Mcf, we have flexibility to reduce our drilling program beginning in the third quarter of 2011, as term drilling contracts begin to expire, and shift our focus to acquisition opportunities. In an increasing natural gas price environment, we can accelerate drilling. We expect commodity prices, particularly for natural gas, to remain volatile in 2011 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.

Budgeted capital expenditures for 2011 total $976.2 million, of which $781.8 million, or 80.0%, are allocated to our East Texas/North Louisiana area and $82.8 million, or 8.5%, are allocated to our Appalachia region. In East Texas and North Louisiana, capital expenditures in the East Texas/North Louisiana JV are expected to total $757.0 million compared with 2010 capital expenditures of approximately $224.3 million. The increase between 2011 expected capital expenditures and 2010 reflects the expiration of the East Texas/North Louisiana Carry on drilling costs within the East Texas/North Louisiana JV. We expect the Appalachia Carry will be utilized in 2011. The impact of the Appalachia Carry is reflected in the $82.8 million 2011 capital budget in Appalachia.

We anticipate that the 2011 capital expenditures for TGGT will be funded with internally generated cash flow and borrowings under a new $500.0 million credit facility, of which an affiliate of BG Group is a 50% lender, or the TGGT Credit Agreement, which closed on January 31, 2011. This credit facility will be used to fund TGGT’s continued expansion program. Accordingly, our 2011 capital budget does not contemplate capital contributions to TGGT.

During the fourth quarter of 2010, we entered into two transactions that we expect will significantly expand our presence in the Appalachia region. On December 15, 2010, we funded an escrow account to purchase certain oil and natural gas assets in the Marcellus shale from Chief Oil & Gas LLC, or the Chief Transaction, for approximately $459.4 million, subject to receipt of consents from a third party, post-closing adjustments and completion of title diligence. At the time of acquisition, the acquired properties were producing a net of approximately 16 Mmcf per day from 15 wells and 11 wells were awaiting completion. The Chief Transaction includes approximately 56,000 net acres prospective for the Marcellus shale development. On January 11, 2011, the necessary consents from the third party were received and escrow funds were released. On February 7, 2011, BG Group funded $229.7 million to acquire their 50% share of the Chief Transaction. In addition, we entered into a purchase and sale agreement to purchase additional Marcellus shale prospective acreage and shallow wells that hold the Marcellus deep rights from a private producer for $95.0 million, subject to further due diligence and post-closing adjustments. We anticipate that BG Group will participate in 50% of this acquisition.

Our midstream operations complement our upstream development plans. In 2010, TGGT completed construction of a 36-inch header system and treating facility to facilitate timely delivery of produced volumes from our Haynesville operations in DeSoto Parish, Louisiana. In the fourth quarter of 2010 and into 2011, TGGT’s efforts have been dedicated to construction of facilities in our second core Haynesville area located in the Shelby area in East Texas. Appalachia Midstream is presently evaluating alternatives for gathering and treating of Marcellus volumes.

Significant activities during 2010

Haynesville shale

During 2010, we spud 119 horizontal Haynesville shale wells, primarily in our core DeSoto Parish, Louisiana area. Our 2010 activities were characterized by improving our drilling efficiencies, collaborating with other producers in the area to achieve best-practices, reducing costs and implementing new technologies and processes such as micro-seismic, pad drilling and simultaneous fracture stimulation of wells within a unit. As discussed below, we completed two significant acquisitions with BG Group of prospective acreage in Shelby, Nacogdoches and San Augustine Counties in East Texas, or the Shelby Area. The Shelby Area is our second focus area in the Haynesville/Bossier shale. By December 31, 2010, we were running 21 operated horizontal drilling rigs in our two focus areas and expect to run 22 operated drilling rigs throughout 2011.

On May 14, 2010, we jointly closed with BG Group the purchase of Common Resources, L.L.C., or the Common Transaction, consisting of properties in Shelby, San Augustine and Nacogdoches Counties, Texas in the Haynesville and Bossier shales. The total purchase price paid at closing was approximately $442.1 million ($221.0 million net to EXCO). Our share of the acquisition price was financed with borrowings under our credit agreement, or the EXCO Resources Credit Agreement.

On June 30, 2010, we jointly closed with BG Group the purchase of properties in Shelby, San Augustine and Nacogdoches Counties, Texas in the Haynesville and Bossier shales from Southwestern Energy Company, or the Southwestern Transaction. The purchase price paid at the closing was $357.8 million ($178.9 million net to EXCO). Our share of the acquisition price was financed with borrowings under the EXCO Resources Credit Agreement. The development of these assets is governed by the East Texas/North Louisiana JV. The majority of the assets acquired in the Southwestern Transaction represent additional working interests in properties that EXCO and BG Group acquired in the Common Transaction.

Marcellus shale

During 2010, our key accomplishments in the Marcellus shale include the Appalachia JV, drilling 15 appraisal wells and improvements in drilling days and completion metrics. The appraisal wells have allowed us to rank our acreage in the area and in 2011 we will further confirm the acreage and identify key acquisition targets. Our 2011 plans involve further analyses to increase our technical understanding of the shale play, evaluate seismic data and evolve into an accelerated development program. In December 2010, we entered into the Chief Transaction which closed in January 2011. We have a pending acquisition prospective of Marcellus shale development which we expect to close during the first quarter of 2011.

Appalachia JV

On June 1, 2010, we closed the Appalachia JV, which resulted in the sale of a 50% undivided interest in substantially all of our Appalachian oil and natural gas proved and unproved properties and related assets to BG Group. Using our current estimated post closing adjustments of $45.0 million due to BG Group, the net cash consideration is approximately $790.2 million. We expect the final purchase price adjustments to be completed in 2011. In addition to the cash consideration received at closing, BG Group agreed to fund the Appalachia Carry, which is equal to 75% of our share of deep drilling and completion costs within the Appalachia JV until the carry amount is satisfied up to a total of $150.0 million. As of December 31, 2010, the unused balance of the Appalachia Carry is estimated to be approximately $126.8 million after giving consideration to estimated contractual reductions of $10.6 million to the carry for estimated post closing adjustments. In conjunction with the Appalachia JV, we entered into a joint development agreement with BG Group. The effective date of the transaction was January 1, 2010.

EXCO and BG Group each own a 50% interest in OPCO, which operates the properties located within the Appalachia JV, subject to oversight from a management board having equal representation from EXCO and BG Group. During 2010, we advanced $48.0 million to OPCO to provide working capital for our share of the Appalachia JV operations. We will continue to fund OPCO with advances to develop the Appalachia properties.

In addition to the upstream Appalachia properties, certain midstream assets were transferred to the Appalachia Midstream JV through which both EXCO and BG Group will pursue the construction and expansion of gathering systems, pipeline systems and treating facilities for anticipated future production from the Marcellus shale.

East Texas/North Louisiana

The East Texas/North Louisiana area is comprised of the Haynesville and Bossier shale plays and the Cotton Valley sand trend, which covers portions of the East Texas Basin and the Northern Louisiana Salt Basin. East Texas/North Louisiana is our largest division in terms of production and reserves and our primary targets include the Haynesville and Bossier shales. We also have production from the Cotton Valley, Travis Peak, Pettet and Hosston formations. We continue to seek additional acreage that is complementary to our existing acreage, operations and pipeline infrastructure.

Currently, our emphasis is on exploitation of our acreage in the Haynesville shale play where we hold approximately 76,000 net acres. The Haynesville shale is at depths of 12,000 to 14,000 feet and is being developed with horizontal wells that typically have 4,000 to 5,000-foot laterals resulting in 16,000 to 19,000 feet of total depth.

We continue to produce from tight gas sand reservoirs in the Cotton Valley sand trend at depths of 6,500 to 15,000 feet. Operations in the area are generally characterized by long-life reserves and high drilling success rates.

Haynesville shale

The Haynesville shale play is one of the most active natural gas plays in the United States. Our Haynesville shale acreage is primarily located in DeSoto and Caddo Parishes in Louisiana and in Harrison, Panola, Shelby, San Augustine and Nacogdoches Counties in Texas. A substantial portion of our acreage is held by our existing Haynesville, Cotton Valley, Hosston and Travis Peak production.

Our development program in the Haynesville shale play is concentrated in DeSoto Parish, Louisiana and the recently acquired in the Shelby Area. We are developing our core DeSoto Parish position on 80-acre spacing in a manufacturing mode utilizing multi-well pad development. In the Shelby Area, our efforts are focused on delineating our position, establishing units and holding our acreage. Although we will be developing some units in 2011, we expect to transition the development of the Shelby Area acreage to full manufacturing mode in 2012.

In early 2010, we operated 12 horizontal drilling rigs in the play and we ended 2010 with 21 operated horizontal drilling rigs. In January 2011 we added one rig bringing our total operated horizontal rig count to 22 rigs. We plan to drill approximately 163 operated horizontal wells in 2011 with our 22 rig fleet. From late 2008 to year end 2010, we have spud 164 operated horizontal wells and produced more than 200 Bcf of gross natural gas to sales. At year end 2010, we averaged a gross operated daily shale gas production rate of approximately 722 Mmcf per day. Including non-operated volumes, we exited 2010 with a net Haynesville production rate of 236.8 Mmcf per day.

In DeSoto Parish our development program has made a transformation from a testing and delineation program to a full field development program. In mid 2010 we initiated a manufacturing process with full unit development on 80-acre spacing. In June 2010 we completed our first four well, 80-acre spacing test across 320 acres, and we completed our first eight well, 80-acre spacing test across a full 640 acre unit in October 2010. Our manufacturing process typically involves four drilling rigs per 640 acre unit to simultaneously drill all wells in the unit, followed by two to three fracture stimulation fleets to simultaneously complete all wells in the unit. We believe this approach to full field development maximizes value and recovery of the resource. At year end 2010, we had 12 units in progress for full 80-acre development and plan to target an additional 15 units in 2011. The multi-well pad design minimizes surface impact and provides for a more capital efficient gathering and production system layout than can be achieved with single well locations. In late 2010 we commissioned a 12 mile, 24 inch diameter water distribution line which utilizes effluent water from a local paper mill to support our completion operations. We recently used this line to simultaneously provide the necessary water to three fracture stimulation fleets located in the same section as we completed seven wells.

In 2010, we acquired a significant acreage position in Shelby, San Augustine and Nacogdoches Counties, Texas and we now hold 24,000 net acres in this second core area of the Haynesville shale play. By year end 2010 we had six drilling rigs running in the area and a total of 19 horizontal wells flowing to sales with a total gross production rate of approximately 100 Mmcf per day (34 Mmcf per day net). At the time of the initial acquisition, gross production in this area was 34 Mmcf per day (7 Mmcf per day net). Some of our recent Haynesville shale wells have yielded results comparable to our DeSoto Parish area. In the fourth quarter 2010, we turned seven new wells to sales in this area. Notable highlights for the quarter included completing and turning to sales two wells with initial rates of 23 and 28 Mmcf per day. Our 2011 development plan for this area has a strong focus on evaluation and delineation. By year end 2011 we expect all of our core San Augustine and Nacogdoches acreage to be held by production.

CEO BACKGROUND

Douglas H. Miller became the Chairman of our Board of Directors and our Chief Executive Officer in December 1997. Mr. Miller was Chairman of the Board of Directors and Chief Executive Officer of Coda Energy, Inc., or Coda, an independent oil and natural gas company, from October 1989 until November 1997 and served as a director of Coda from 1987 until November 1997. Mr. Miller has extensive experience and knowledge of the Company, the oil and gas industry and capital markets as well as significant strategic and executive leadership experience. Since he is responsible for, and familiar with, our day-to-day operations and implementation of our overall strategy, his insights into our performance and into the industry are critical to board discussions and to our success. See “—Transactions with Related Persons—Corporate use of personal aircraft” for a description of certain related person transactions involving Mr. Miller.

Stephen F. Smith joined us in June 2004 as Vice Chairman of our Board of Directors and was appointed President and Secretary in October 2005. He served as our Secretary until April 2006. Mr. Smith began serving as our Chief Financial Officer in June 2009. Prior to joining us, Mr. Smith was co-founder and Executive Vice President of Sandefer Oil and Gas, Inc., an independent oil and gas exploration and production company, from January 1980 to June 2004. Mr. Smith was one of our directors from March 1998 to July 2003. Prior to 1980, Mr. Smith was an Audit Partner with Arthur Andersen LLP. Mr. Smith has extensive experience and knowledge of the Company and the oil and gas industry as well as significant accounting, finance and executive leadership experience. Since he is responsible for, and familiar with, our day-to-day operations and financial condition, his insights into our performance and into the industry are critical to board discussions and to our success. See “—Transactions with Related Persons—Subcontractor relationship with Jeff Smith” for a description of a related person transaction involving Mr. Smith’s son.

Jeffrey D. Benjamin became one of our directors in October 2005 and was previously one of our directors from August 1998 through July 2003 and a director of our parent holding company from July 2003 through its merger into us. Since June 2008, Mr. Benjamin has been a Senior Advisor to Cyrus Capital Partners, LP. From September 2002 until June 2008, Mr. Benjamin was a Senior Advisor to Apollo Management, LP. With his history at Apollo Management and Cyrus Capital Partners, Mr. Benjamin has extensive financial, capital markets and strategic experience. Mr. Benjamin is currently a director of Caesars Entertainment Corporation, Chemtura Corporation and Spectrum Group International, Inc. During the past five years, Mr. Benjamin also served on the board of directors of Chiquita Brands International, Inc., Dade Behring Holdings, Inc., Goodman Global, Inc. and Virgin Media Inc. In connection with his service as a director of eight public companies other than EXCO over the past nine years, Mr. Benjamin served on five compensation committees (including two as chairman), five audit committees and five nominating and corporate governance committees (including two as chairman), all of which provide him with important insights into corporate governance, financial reporting and oversight, executive compensation and board functions. In addition, Mr. Benjamin has deep knowledge of the Company and its business, having served on our and our affiliates’ boards since October 2005 and prior to that from 1998 through 2003. Mr. Benjamin holds a Master of Science (MBA) in Management from the Sloan School of Management at MIT, with a concentration in Finance, and has 25 years of investment banking and investment management experience.

Earl E. Ellis became one of our directors in October 2005 and was previously one of our directors from March 1998 through July 2003. Mr. Ellis has served as chairman and chief executive officer of Whole Harvest Foods, formerly Carolina Soy Products, an edible oil product manufacturing company since September 2003. Mr. Ellis has also been a private investor since 2001. He served as a director of Coda from 1992 until 1996. Mr. Ellis served as a managing partner of Benjamin Jacobson & Sons, LLC, specialists on the New York Stock Exchange, or the NYSE. He had been associated with Benjamin Jacobson & Sons, LLC from 1977 to 2001 and was a member of the NYSE for over thirty years. Mr. Ellis’s background and experience provide him with extensive investment, capital markets and executive leadership experience, familiarity with our industry and important insights into corporate governance, financial reporting and oversight, executive compensation and board functions. In addition, Mr. Ellis has deep knowledge of the Company and its business, having served on our and our affiliates’ boards since October 2005 and prior to that from 1998 through 2003. Mr. Ellis is a graduate of Baylor University, with a degree in economics.

B. James Ford became one of our directors on December 1, 2007. Mr. Ford is a Managing Director of Oaktree where he has worked since 1996. Mr. Ford is a co-portfolio manager of Oaktree’s Principal Opportunities Funds, which invest in controlling and minority positions in private and public companies. Mr. Ford serves on the Board of Directors of Crimson Exploration, Inc. as well as a number of private companies and not-for-profit entities. He is also an active member of the Children’s Bureau Board of Directors and serves as a trustee for the Stanford Graduate School of Business Trust. Prior to becoming portfolio manager, Mr. Ford led the group’s media and energy investing. Mr. Ford joined Oaktree in 1996 following graduation from the Stanford Graduate School of Business. Previously, Mr. Ford served as a consultant at McKinsey & Co., an analyst at PaineWebber Incorporated, and as an asset manager/acquisitions analyst at National Partnership Investments Corp., a real estate investment firm. Mr. Ford’s background and experience provide him with extensive investment, capital markets and strategic experience, as well as important insights into corporate governance and board functions. In addition to his graduate degree, Mr. Ford received a B.A. degree in Economics from the University of California at Los Angeles.

Mark Mulhern became one of our directors on February 1, 2010. Mr. Mulhern is chief financial officer of Progress Energy, Inc. and oversees its financial services group. Mr. Mulhern joined Progress Energy in 1996 as vice president and controller. Before joining Progress Energy, Mr. Mulhern was the chief financial officer at Hydra Co Enterprises, the independent power subsidiary of Niagara Mohawk. He also spent eight years at PricewaterhouseCoopers LLP in Syracuse, New York, serving a wide variety of manufacturing and service businesses. Mr. Mulhern serves on the Edison Electric Institute Financial Executive Advisory Committee and is on the board of directors of Habitat for Humanity of North Carolina. He is a 1982 graduate of St. Bonaventure University. Mr. Mulhern is a certified public accountant, a certified management accountant and a certified internal auditor. Mr. Mulhern’s background and experience provide him with extensive knowledge of the energy industry as well as significant finance and executive leadership experience and important insights into financial reporting and oversight, executive compensation and board functions. Mr. Mulhern has also completed the nuclear executive program at the Massachusetts Institute of Technology.

T. Boone Pickens became one of our directors in October 2005 and was previously one of our directors from March 1998 through July 2003. Mr. Pickens has served as the Chairman and CEO of BP Capital LP since September 1996 and Mesa Water, Inc. since August 2000 and is a board member of Clean Energy Fuels Corp. BP Capital LP or affiliates is the general partner and an investment advisor of private funds investing in energy commodities (BP Capital Energy Fund) and publicly traded energy equities (BP Capital Equity Fund and its offshore counterpart). Clean Energy Fuels Corp. is the largest provider of natural gas (CNG and LNG) and related services in North America. He was the founder of Mesa Petroleum Co., an independent oil and natural gas exploration and production company. He served as CEO and Chairman of the Board of Mesa Petroleum Co. from its inception until his departure in 1996. Mr. Pickens’s background and experience provide him with extensive knowledge of the oil and gas industry as well as significant investment and strategic leadership experience and important insights into corporate governance and board functions. In addition, Mr. Pickens has deep knowledge of the Company and its business, having served on our and our affiliates’ boards from 1998 through 2003 and since 2005.

Jeffrey S. Serota became one of our directors on March 30, 2007. Mr. Serota previously served as a director of EXCO Resources and EXCO Holdings from July 2003 until October 2005. He has served as a Senior Partner of Ares Management LLC, an alternative asset investment firm, since September 1997. Prior to joining Ares, Mr. Serota worked at Bear Stearns from March 1996 to September 1997, where he specialized in providing investment banking services to financial sponsor clients of the firm. He currently serves on the board of directors of SandRidge Energy, Inc., WCA Waste Corporation and LyondellBasell Industries N.V. and previously served on the board of directors of Douglas Dynamics, Inc. from 2004 until October 2010. Mr. Serota has over 20 years of experience managing investments in, and serving on the boards of directors of, companies operating in various industries, including in the oil and natural gas exploration and production industries. Mr. Serota’s background and experience provide him with extensive investment, capital markets and strategic experience, as well as important insights into corporate governance, financial reporting and oversight, executive compensation and board functions. Mr. Serota received a Bachelor of Science degree in Economics from the University of Pennsylvania’s Wharton School of Business and received a Master of Business Administration degree from UCLA’s Anderson School of Management.

Robert L. Stillwell became one of our directors in October 2005. Mr. Stillwell has served as the General Counsel of BP Capital LP, Mesa Water, Inc. and affiliated companies engaged in the petroleum business since 2001. Mr. Stillwell was a lawyer and Senior Partner at Baker Botts LLP in Houston, Texas from 1969 to 2001. He also served as a director of Mesa Petroleum Co. and Pioneer Natural Resources Company from 1969 to 2001. Mr. Stillwell’s background and experience provide him with extensive knowledge of the oil and gas industry as well as significant legal experience and important insights into corporate governance, executive compensation and board functions.

All of the Director Nominees are currently serving on our Board of Directors. There are no family relationships between any of our directors or executive officers.

MANAGEMENT DISCUSSION FROM LATEST 10K

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 own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia.

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. The accumulation of this shale potential allowed us to shift our focus to appraise and develop these shales, primarily through horizontal drilling, divest of properties that were outside our areas of focus, and to enter into joint ventures with BG Group to develop the Haynesville shale, the Marcellus shale, and our midstream operations.

In 2010 and 2009, we entered into two upstream joint ventures with BG Group, the Appalachia JV and the East Texas/North Louisiana JV, through the sale of 50% of certain oil and natural gas properties located in Appalachia, East Texas and North Louisiana. We also entered into two midstream joint ventures with BG Group, TGGT and the Appalachia Midstream JV. The closing of our upstream and midstream joint venture transactions enabled us to accelerate our horizontal drilling program in East Texas/North Louisiana and strategically add to our acreage position through two 2010 joint acquisitions in the Haynesville shale and one transaction in Appalachia, all with BG Group. The impact of our 2009 divestitures and 2010 and 2009 joint ventures resulted in significant reductions to our Proved Reserves, production volumes, revenue and operating expenses. While the reductions had a negative impact on our results of operations, particularly in 2009 and throughout most of 2010, our shift to horizontal drilling and the accelerated drilling plan has resulted in Proved Reserves and production being restored to pre-divestiture levels.

Our primary strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and to leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. Future acquisitions remain targeted on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We currently plan to continue to develop vertical drilling opportunities in our Permian area as this region has high oil reserves and natural gas with a high liquid content.

We expect to continue to grow by leveraging our management and technical team’s experience, appraising and developing our shale resource plays, drilling our multi-year inventory of development locations and accumulating undeveloped acreage in shale areas and implementing exploitation projects. We employ the use of debt, currently represented by a credit agreement with a borrowing base of $1.0 billion, of which $549.0 million was drawn as of February 17, 2011, and $750.0 million of the 2018 Notes outstanding, along with a comprehensive derivative financial instrument program to mitigate commodity price volatility, to support our strategy.

As of December 31, 2010, the PV-10 of our Proved Reserves was approximately $1.4 billion and the standardized measure was $1.2 billion (see “Item 1. Business—Summary of geographic areas of operations” for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the year ended December 31, 2010, we produced 112.0 Bcfe of oil and natural gas. Based on the 112.0 Bcfe of production, this translates to a Reserve Life of approximately 13.4 years.

In 2010, we drilled 207 wells and completed 205 gross (97.2 net) wells with 99.0% drilling success rate. Our 2010 development, exploitation and other oil and natural gas property capital expenditures totaled $346.6 million, net of $337.5 million of East Texas/North Louisiana Carry and $12.6 million of Appalachia Carry paid for our benefit by BG Group. In addition, we leased $46.9 million of undeveloped acreage in the Haynesville/Bossier shale resource play in East Texas/North Louisiana and $48.5 million of undeveloped acreage in the Marcellus shale resource play in Appalachia. Investments in our midstream equity investments were $143.7 million and corporate, gathering, and seismic capital expenditures totaled an additional $119.4 million. In addition, we completed $533.9 million of acquisitions, which were mostly undeveloped acreage in the Haynesville/Bossier and Marcellus shale resource plays.

Our plans for 2011 are focused on the Haynesville/Bossier and Marcellus shales. Our budgeted capital expenditures total $976.2 million, of which $864.6 million is allocated to our East Texas/North Louisiana and Appalachia regions. In East Texas and North Louisiana, our capital expenditures for the East Texas/North Louisiana JV are expected to total $757.0 million. In Appalachia, our planned capital expenditures for the Appalachia JV are expected to total $82.8 million. Our 2010 capital expenditures were favorably impacted by the East Texas/North Louisiana Carry. In 2011, our capital expenditures in Appalachia will benefit from the Appalachia Carry. As of December 31, 2010, the remaining balance of East Texas/North Louisiana Carry was approximately $30.2 million, which we anticipate will be fully utilized by the first quarter of 2011 and the remaining balance of the Appalachia Carry, after estimated contractual adjustments for post closing reductions to the original carry amount, was approximately $126.8 million.

For 2011, TGGT’s capital expenditure budget of $237.1 million will focus primarily on well hook-ups in DeSoto Parish and adding infrastructure in the Shelby Area. The management of TGGT is also evaluating several expansion projects. On January 31, 2011, TGGT closed the TGGT Credit Agreement. We expect the TGGT Credit Agreement, together with their cash flows from operations, will be sufficient to fund their 2011 capital expenditure programs. We expect to fund equity contributions to the Appalachia Midstream JV in the future depending on the results of the development and appraisal program.

Like all oil and natural gas production companies, we face the challenge of natural production declines. We attempt to overcome this natural decline by drilling to identify and develop additional reserves and add reserves through acquisitions. As of December 31, 2010, 97.1% of our estimated Proved Reserves were natural gas. Consequently, our results of operations are particularly impacted by natural gas markets.

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.

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 and Marcellus 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 Reserve 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 renewal is reasonably certain, regardless of whether the estimates are 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 the Financial Accounting Standards Board, or FASB, Accounting Standard Codification, or 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.

Share-based payments

We account for share-based payments to employees using the methodology prescribed in FASB ASC Topic 718 for Compensation—Stock Compensation. At December 31, 2010, our employees and directors held options under EXCO’s 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 16,478,926 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 $7.34 per share to $12.77 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 2010 was $23.2 million, of which $6.4 million was capitalized as part of our oil and natural gas properties. In 2009 and 2008, a total of $24.1 million and $20.0 million, respectively, of share-based compensation was incurred, of which $5.1 million and $4.0 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. The transactions to form our 2010 Appalachia JV and our 2009 East Texas/North Louisiana JV, along with certain of our 2009 divestitures, resulted in significant alterations to our depletion rate 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.

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

The quarterly calculation of the ceiling test is based upon estimates of Proved Reserves. 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 transactions to form our 2010 Appalachia JV and our 2009 East Texas/North Louisiana JV, along with certain of our 2009 divestitures, 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 $51.4 million of goodwill in 2010 and $177.6 million of goodwill in 2009 by reducing the gains associated with these transactions. In addition, the transaction to form TGGT 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, 2010, our consolidated goodwill totals $218.3 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, 2010, we did not have any impairment of our goodwill.

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 December 21, 2010, FASB issued Accounting Standards Update, or ASU, No. 2010-29—Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations, or ASU 2010-29. ASU 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures under Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for 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, 2010. This update was adopted by us on January 1, 2011 and will be considered if we enter into a business combination transaction.

On December 17, 2010, the FASB issued ASU No. 2010-28—Intangibles—Goodw ill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts, or ASU 2010-28. ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The update is effective for interim and annual reporting periods beginning after December 15, 2010. This update will be considered on an interim and annual basis when we review and perform our goodwill impairment test.

On January 21, 2010, the FASB issued ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009. See “Note 5. Derivative financial instruments and fair value measurements” in the notes to our consolidated financial statements included in this Annual Report on Form 10-K for the impact to our disclosures.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

Overview

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

Our primary strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and to leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. Future acquisitions are primarily targeted on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content. In order to accelerate our development efforts, we have entered into four separate joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows.


• A joint venture with BG Group covering an undivided 50% interest in a substantial portion of our assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale and conventional shallow producing assets, or the East Texas/North Louisiana JV. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating Company, LP, or EOC, serving as operator. Under the terms of the agreement, BG Group funded 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $400.0 million, or the East Texas/North Louisiana Carry. During the first quarter of 2011, we utilized the remaining balance of the East Texas/North Louisiana Carry.


• A joint venture with BG Group in which we both own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets.


• A 50/50 joint venture with BG Group covering our shallow producing assets and Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group jointly operate the Appalachia JV operations through a 50/50 owned operating entity, or OPCO, which holds a 0.5% working interest in all of the shallow conventional assets and the deep rights in the Appalachia JV. Under the terms of the agreement, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $150.0 million, or the Appalachia Carry. As of September 30, 2011, the remaining balance of the Appalachia Carry was approximately $78.8 million.


• A jointly-owned midstream company, or the Appalachia Midstream JV, to provide take-away capacity in the Marcellus shale.

We expect to continue to grow by leveraging our management and technical team’s experience, appraising and developing our shale resource plays, drilling our multi-year inventory of development locations and accumulating undeveloped acreage in shale areas and implementing exploitation projects. We also continue to pursue acquisitions primarily in the core areas of our shale plays. We employ the use of debt, currently represented by a credit agreement with a borrowing base of $1.5 billion, of which $1.0 million was drawn as of October 27, 2011, or the EXCO Resources Credit Agreement, and $750.0 million of 7.5% senior unsecured notes due September 15, 2018, or the 2018 Notes, along with a comprehensive derivative financial instrument program to mitigate commodity price volatility, to support our strategy.

Our plans for 2011 are focused on the Haynesville/Bossier and Marcellus shales. Our forecasted capital expenditures, which exclude $32.5 million of BG Group acreage reimbursements, total $1,014.4 million, of which $896.8 million is allocated to our East Texas/North Louisiana and Appalachia regions. In East Texas and North Louisiana, our capital expenditures for the East Texas/North Louisiana JV are expected to total $810.7 million. During the first nine months of 2011, we spent $624.8 million in East Texas/North Louisiana, excluding $22.8 million of BG Group acreage reimbursements, $618.7 million of which was in the area of mutual interest with BG Group, or the East Texas/North Louisiana AMI. In Appalachia, our share of planned capital expenditures for the Appalachia JV are expected to total $67.0 million for 2011, which reflects the benefit of $68.0 million of the Appalachia Carry. During the first nine months of 2011, we spent $43.0 million in Appalachia, net of the Appalachia Carry. As of September 30, 2011, the remaining balance of the Appalachia Carry was approximately $78.8 million.

For 2011, TGGT’s capital expenditure budget will focus primarily on well hook-ups in DeSoto Parish and adding infrastructure in the Shelby Area. TGGT’s management is also evaluating several expansion projects. On January 31, 2011, TGGT closed a $500.0 million credit facility, or the TGGT Credit Agreement, and used proceeds from the initial draw to make capital distributions of $125.0 million each to us and BG Group. We expect the TGGT Credit Agreement, together with its projected cash flows from operations, will be sufficient to fund TGGT’s 2011 capital expenditure programs.

For the three and nine months ended September 30, 2011, we funded $3.5 million in equity contributions to the Appalachia Midstream JV and we expect to continue to fund equity contributions in the future as it builds infrastructure to support our development activities in Appalachia.

For the nine months ended September 30, 2011, we produced 131.9 Bcfe of oil and natural gas. Of the amount produced, 117.6 Bcfe were produced in our East Texas/North Louisiana area, 8.6 Bcfe were produced in our Appalachia area and 5.7 Bcfe were produced in our Permian Basin area.

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 offset the impact of this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions. We are presently evaluating our 2012 capital expenditure budgets.

Critical accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2010.

Significant events

Chief transaction

On December 21, 2010, we funded the acquisition of undeveloped acreage and oil and natural gas properties primarily in the Marcellus shale from Chief Oil & Gas LLC and related parties for approximately $459.4 million, subject to post-closing title adjustments and customary post-closing purchase price adjustments, or the Chief Transaction. The $459.4 million preliminary purchase price was funded into an escrow account pending receipt of a waiver from a third party, which was received on January 11, 2011 and all properties were released to us. BG Group participated in its 50% share of the Chief Transaction and funded $229.7 million to us on February 7, 2011. During the third quarter of 2011 we post closed on the Chief Transaction for a final purchase price of $454.4 million ($227.2 million net to us), including all post-closing title adjustments and other customary post-closing purchase price adjustments.

Appalachia transaction

On March 1, 2011, we jointly closed the purchase of additional Marcellus shale properties with BG Group, which also included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $82.0 million ($41.0 million net to us), or the Appalachia Transaction.

Haynesville shale acquisition

On April 5, 2011, we closed on a $225.2 million acquisition of land, mineral interests and other assets in DeSoto Parish, Louisiana, or the Haynesville Shale Acquisition. On May 12, 2011, BG Group elected to participate in this acquisition for its 50% share in accordance with contracts covering our East Texas/North Louisiana JV and funded us $112.6 million.

Amendment of the EXCO Resources Credit Agreement and increase in borrowing base

On April 1, 2011, we entered into the Third Amendment to our credit agreement, or the EXCO Resources Credit Agreement, resulting in an increase of the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate under the EXCO Resources Credit Agreement was reduced by 50 basis points, or bps, and now ranges from the London Interbank Offered Rate, or LIBOR, plus 150 bps to LIBOR plus 250 bps, or from Alternate Base Rate, or ABR, plus 50 bps to ABR plus 150 bps, depending upon borrowing base usage. Our consolidated ratio of funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) increased by 0.5, so that the ratio can be no greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010. The maturity date was extended from April 30, 2014 to April 1, 2016.

TGGT incident

In the second quarter of 2011 an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications, which was restarted in October 2011. TGGT has ordered temporary treating units and expects to be capable of treating all projected northwest Louisiana throughput volumes by early in the first quarter of 2012 once these temporary treating units are operational. TGGT received an initial insurance reimbursement associated with the incident of approximately $6.2 million ($3.1 million net to us) during the third quarter 2011. TGGT expects to have the damaged facility re-commissioned early in 2012.

Former acquisition proposal

On October 29, 2010, our Chairman and Chief Executive Officer, Douglas H. Miller presented a letter to our board of directors indicating an interest in acquiring all of the outstanding shares of our stock not already owned by Mr. Miller for a cash purchase price of $20.50 per share. This proposal did not represent a definitive offer and there was no assurance that a definitive offer would be made or accepted, that any agreement would be executed or that any transaction would be consummated.

Our board of directors established a special committee on November 4, 2010 comprised of two of our independent directors to, among other things, evaluate and determine the Company’s response to the October 29, 2010 proposal. On July 8, 2011, after consultation with its independent financial and legal advisors, the special committee released a statement that its review of strategic alternatives did not result in any firm proposal or any other proposal that was in the best interests of the Company and its shareholders and that they had terminated the review process. See “Note 17. Former acquisition proposal” of the notes to our condensed consolidated financial statements for further information regarding the proposal.

Recent accounting pronouncements

On May 12, 2011, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2011-04 -Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, or ASU 2011-04. ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurement requirements and changes particular principles or requirements for measuring fair value or for disclosing information about fair value measurements. We anticipate the update will impact our fair value disclosures. This update is effective during interim and annual periods beginning after December 15, 2011, at which time we will adopt the update.

On June 16, 2011 the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income, or ASU 2011-05. This ASU requires entities to report items of other comprehensive income on either part of a single contiguous statement of comprehensive income or in a separate statement of comprehensive income immediately following the statement of income. While early adoption is permitted, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and must be applied retrospectively. Presently, we do not have any transactions which require the reporting of comprehensive income; therefore, we do not anticipate any immediate impact from this pronouncement.

Marketing arrangements

We produce oil and natural gas. We do not refine or process the oil we produce. We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

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

We may be unable to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas contained in our properties and related liquidity. 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. Economic conditions related to the liquidity and creditworthiness of our purchasers may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

Summary

For the three months ended September 30, 2011, we reported net income of $84.9 million compared to net income of $64.9 million for the three months ended September 30, 2010. For the nine months ended September 30, 2011, we reported net income of $189.2 million compared to net income of $744.8 million for the nine months ended September 30, 2010.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and nine months ended September 30, 2011 were $21.1 million and $60.8 million, respectively, compared with $22.1 million and $63.8 million for the three and nine months ended September 30, 2010, respectively. For the three months ended September 30, 2011, declines in maintenance and service costs in our shallow Cotton Valley wells and Vernon Field are primarily due to various divestitures in 2011 of property and field equipment. In our Appalachia area, commencement of our Marcellus shale horizontal drilling program and expenses attributable to the properties acquired in the Chief Transaction and the Appalachia Transaction and increased activity in Permian due to resumption of our drilling program during 2010. The decrease for the nine month period reflects reductions in Appalachia related to the formation of the Appalachia JV and similar decreases in our Cotton Valley area and Vernon Field as discussed above, offset by increased activity in the Permian Basin due to the resumption of drilling operations during 2010 and continual increased activity in our Haynesville area. To further analyze the variances in costs, management reviews the costs on a per Mcfe basis, as we believe this measure excludes the impact of any acquisitions or divestitures and actual operating expense trends due to fluctuating production volume.

As shown in the table below, on a per Mcfe basis, oil and natural gas operating expenses for the three months ended September 30, 2011 decreased $0.33 per Mcfe, a reduction of 44.0% from the same period in 2010, with lease operating expenses representing $0.24 per Mcfe of the decrease and workovers and other expense representing $0.09 per Mcfe of the decrease. The net decrease in oil and natural gas operating expenses per Mcfe in East Texas/North Louisiana is primarily due to the Haynesville shale wells, which have a relatively low lease operating rate per Mcfe, along with slight decreases in both our Vernon Field and Cotton Valley area due to a decline in unit operating costs. The declines in Cotton Valley and the Vernon Field were primarily due to reductions in maintenance and service costs and the 2011 divestitures of properties and field equipment. In addition, there were decreases in workovers in our Vernon Field. While there was an increase in total oil and natural gas operating expenses for the Appalachia region, there was an overall decrease in operating expenses per Mcfe in Appalachia primarily a result of increased production volumes from Marcellus shale wells, which have lower lease operating expense rate per Mcfe than our historical shallow production. These decreases are offset by the Permian region due to increased activity related to resumption of our drilling program in the third quarter of 2010.

CONF CALL

Douglas H. Miller

Thank you very much. We appreciate everybody signing in for the conference call. And before we get started, Ramsey is going to go over our disclosure statement.

J. Douglas Ramsey

All right. Thanks, Doug. I'd like to remind everyone that you can go to www.excoresources.com and click on the Presentations link in the Investor Relations section at the bottom of our homepage to access today's presentation slides.

The statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategies, market prices and related activities and other plans, forecasts and statements that are not historical facts are forward-looking statements as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on a variety of assumptions that may change any of our future events which are difficult to predict. Actual results may differ materially from those in forward-looking statements. We caution you not to place undue, if any, reliance on such statements.

Please refer to pages 22 and 23 of the slide presentation for the complete text regarding our forward-looking statements as well as the cautionary information set forth in our most recent Form 10-K, Form 10-Q and other SEC filings which are available on our website at www.excoresources.com.

In addition, the slide presentation contains information including reconciliation regarding certain non-GAAP financial numbers which will be discussed on today's call. Doug?

Douglas H. Miller

Thank you. With me in here today, I have 11 people plus myself, and we'll be here to answer any and all questions. Harold Jameson, Marcia Simpson, Steve Smith, Paul Rudnicki, Mark Wilson, Hal Hicky, who will be speaking Rudnicki and Steve will be speaking also. Doug Ramsey, of course, Mike Chambers, John Jacoby, part of our A&D group will guide into that and then last and least, our 2 IRs, Lenny [ph] and Justin Clarke.

Let me kind of give a little brief overview. I feel like I owe everybody an apology because I heard last night as we missed, we had probably our best quarter in the history of the company. And operationally we did everything plus some that we thought, and in here we'll talk about that a little bit.

What we did miss on is estimating, bringing back on our amine plant. And the reason for that is we have us and BG, who's our partner, working to safety and engineering and just making sure we have back up and double back up, and we missed that. We kind of forecast that will be coming out on October, where we would pick up some of that production that we have shut in. We have approximately 200 million a day gross which would all go through the pipeline, and 44 million a day been shut in because of that plant. We actually have more shut in, both in Appalachia and in East Texas, not Louisiana, maybe up to 80 million a day total, but that's just normal operational. But if I were begging an apology on that, it's our fault, my fault for misjudging, but we'll get into that. The amine plant is every -- it's all hands on deck. Looks like probably the beginning of the year, we'll have it back on. But I will note that we did have 400 million a day on the new Arcadia enterprise system that turned on yesterday. And we're flowing 400 million a day down that line. So that opens up a lot of extra capacity because our marketing guys were going crazy.

Couple of other things have been going on. We had our bank meeting this quarter. We did request increasing our line from, actually the base amount from $1.5 billion to $2 billion and our bottom base from $1.5 billion to $1.6 billion that should be -- we're very confident of that happening. That should be approved by the end of this week, early next week, we'll make an announcement if and when that gets -- when that happens.

Other than that, let's kind of talk about what happened. Your operating guys had a spectacular quarter. Our volumes are up almost 70%, our midstream volumes are up 30%. We were moving 1.6 billion a day through our East Texas, North Louisiana midstream. Again, we have another 200 million a day that will be coming on hopefully right at the end of the year. Our guys have done a spectacular job in both the North Louisiana, and the East Texas is coming in slightly better than we thought. We have a little program going on, a joint venture where we're doing a significant test on both the Bossier and the Haynesville, it's under way. We probably -- what do we have? 4 rigs on that 1 section? Excuse me, 5 rigs on the 1 section. So we're actually doing a spacing test on Bossier and Haynesville at the same time in a joint venture with another operator. So that could be quite exciting, that could come on early next year also.

We've had some pretty good success up in the Marcellus. I think we hit 100 million a day yesterday. So pipelines are being built right away. It's being launched and we are actively looking at seeing if we can improve our position up in certain areas.

Both areas -- again, and I think I've told everybody, we're in discussions with BG and we have a board meeting coming up on our capital program. And with gas prices, where they are, I kind of expect that we will be reducing our rig count. I can't tell you exactly what it is because our board meeting is scheduled for November 17. But under $4, our rigs return start going below 20%. So we will -- we're scrubbing that right now. Again, we'll announce that sometime after the 17th if the board will approve that.

Again, everything has -- we had a spectacular quarter from an operational standpoint, and I'll take the hit for that misforecast on construction and engineering. But we're all involved in it. It is underway, it's all hands on deck on the ground. And we just want to make sure that we have backup and backup to the backup before we turn it on.

So with that, I'm going to turn it over to Steve.

Stephen F. Smith

If you would just flip over to Slide 5, and we will go through the numbers a little bit in detail and then we'll get into the operational areas. As Doug said, this was a strong quarter for us except for that one problem that we got on amine plant.

Our production averaged 540 million a day, that's about -- well obviously, it's 69% over last year at this time. It's about 8% over Q2 -- I mean, yes, Q2. And in spite of a decrease in gas price, about 8%, all of our numbers, our EBITDA, cash flow, et cetera, as compared to Q2 '11 were pretty either slightly more or flat to the Q2 '11 numbers. So we're pleased with it. We're very pleased operationally with what we're doing. I'll show you on the next slide.

Direct operating costs continue to trend down pretty rapidly, a 44% decrease between this year's op cost per Mcfe. And last year's G&A continues to trend down, but also EBITDA is way up year-over-year, obviously, as is cash flow, over 50% increase on cash flow. So in general, we're very pleased with where we are.

On Page 6, it's a kind of an interesting chart. We tried to keep this updated at all times, and it's really a cash operating margin chart. The first shaded area is the operating margin before any hedging impact is considered. And you can see there that in spite of the gas prices, we're still hanging in at a decent margin of over $3, around $3.17 for the third quarter, which is 76% of the realized gas price per Mcfe. And then when you roll in the derivatives, even though obviously we don't have as many on the books as we did, we're still -- we're hanging in that as well.

Again, G&A, you can see is kind of trending downward with a little kick in the third quarter due to some bonuses that were paid.

But overall, margins are strong, even in this environment, and we're very pleased to where we are on our cost control, both operating capital, et cetera, and that's a strong area of focus for us.

Page 7 is the chart that we have each quarter just to kind of show you were we've been from a debt and production standpoint and where we are now and where we're headed for the fourth quarter. Our debt was, back in Q1 '09, was about $2.8 billion, it's now or will be, we expect at the end of the year around $1.6 billion net production. We've gained back everything that we sold in the '09, '10 time frame and should exit in the 5.75 range, maybe more if we can get the plan on a little earlier than we're currently forecasting.

Our leverage metrics look great. The balance sheet is in good shape. So we're poised to continue the kind of activities that we've had in the past.

So I'm going to turn it over to Paul and let him get into a little more detail on our liquidity, et cetera.

Paul B. Rudnicki

Thanks, Steve. I'll pick up on Slide 9. Looking at our summary liquidity and our current derivative position. As you can see, our cash at the end of the quarter was $174 million, of which $170 million was related to the escrow account that we hold for our joint venture. And just to remind everybody, we pre-fund a quarter's worth of capital in operating expenses related to our Haynesville shale development, and that's why we carry that large cash balance.

Bank debt was $972.5 million drawn under $1.5 billion revolver. The senior notes outstanding continued at $750 million. So, total debt was $1.7 billion. Net of the cash, it was $1.5 billion, leaving us with total liquidity of $692 million. As Doug already mentioned, we're in the process of finalizing the borrowing base redetermination, and we'll get that out as soon as we get that.

You can look at our derivatives for the rest of this year. And going into next year, we're about 56% hedged for the remainder of this year at an equivalent price of $5.52 in Mcf. And looking into 2012, we're just under 40% at an equivalent price of $5.49.

Looking at the guidance on Slide 10 for the third quarter versus our actuals, as we've discussed, we initially anticipated the shut-ins or the curtailments related to the amine facility being down to account for 2/3 of the quarter. And the actualities we've discussed, it was the entire quarter which led to a higher shut-in volume of 44 million versus our initial estimates of 27 million. All differentials and gas differentials remained strong. Our gas differentials are a little weaker this quarter as we use some interruptible transportation to move our gas.

Operating expenses, as we've discussed, coming down dramatically on a per Mcf basis and on a low-end of our guidance for the quarter, gathering expenses on the low end, production taxes below the low end. DD&A was a little uptick from where we expected, mainly resulting from the lower gas prices used for SEC purposes in determining the reserved base for calculating the depletion rate. All other items basically in line as we discussed.

And then on our capital side, we're a little bit over on the high end, mainly just due to the timing of activities during the quarter.

EBITDA of $164 million and the primary driver for the difference again is the lower production from the 3 facilities.

On Slide 11, we're looking into the fourth quarter. Basically, all of our guidance remains unchanged from the prior quarter. Other than the production, we've lowered our guidance from 30 million to 60 million a day, expecting on average of around 45 million a day shut in. Our midpoint was 610 million a day. As you can see we're at 565 million a day for the quarter. And as I mentioned, all other line items in the guidance remained unchanged from the prior guidance that we have put out.

Looking at our EBITDA forecast for the fourth quarter, we're coming in at $167 million versus our prior forecast of $201 million. $24 million of that is due to the decrease in price. Our prior guidance is assumed for $4.75 an Mcf for the fourth quarter, and we're now currently using $3.75 for the NYMEX. That was $24 million of the decrease, and the $10 million decrease is related to the lower production.

With that, I'll turn it over to Hal.

Harold L. Hickey

Thank you, Paul. Slide 13, I'll give you some color on the excellent operational results we had during the third quarter of '11. Haynesville, in both of our areas, continues to perform very well. In DeSoto, we've had very steady performance as we've continued to realize IP rates in the 19 million a day range. In East Texas, the performance is very exciting as we continue to see IP rates in the 28 million a day rates from the Haynesville wells and 26 million, 27 million a day from the Bossier wells.

We have a record production volumes of 540 million a day, we've exceeded 1.2 Bcf a day of gross operating production East Texas/North Louisiana when you add OBO in with that. We're over 1.7 Bcf a day. All the wells we drilled during the quarter and completed came in successfully as we forecast, so 100% drilling success rate from our 27 operated rigs. And you can see that of those 27 rigs, 4 in Appalachia, only 1 in the Permian, 22 in East Texas/North Louisiana. Of those 22 in East Texas/North Louisiana, we have 15 in our Holly area and 7 down in Shelby. And I'll note, that we've also got about 8 outside the operating wells drilling in the East Texas/North Louisiana region for this week. Hence, working interest there is about 15%.

Marcellus program will really get some traction in the Northeast area, particularly in Lycoming County. We've had some really good results there. We started our development program, we're drilling multiple wells off of pads and completing them simultaneously, and we'll get into some of the details on those results in a minute.

Paul referenced a minute ago that our activities have driven some of our capital up. You'll note our completed wells, 79 in the third quarter, that's versus 71 in the second quarter in East Texas/North Louisiana, because we've been drilling so efficiently and so quickly. We're actually going to end up drilling some 8 or 10 more wells this year than we originally had in our budget.

So that will drive some of our CapEx up, which is a good lead into Slide 14 where we're going to forecast slightly over $1 billion of spending this year. We're up about $17 million from what we had originally forecasted, that's a combination of drilling more wells. I think we're going to drill about 3 more wells in the quarter than we forecast. Then also, we really increased our activity around $2. So what we've done is we've taken advantage of some of the curtailments that's existed from the midstream activity, and in turn, done more on the operating upstream side to go ahead and just have a business there.

On the drilling and completion, the one thing I'll note is Appalachia looks a little bit low because we continue to have a significant input there of BG Carry, and we still have nearly $80 million of Carry remaining as of the end of Q3 for us to use in conjunction with BG as we implement our drilling and completion program in Appalachia.

Slide 15 is more detail on East Texas/North Louisiana. I've talked about our volume there on a gross basis. Net production totaled some for 419 million a day as of a couple of weeks ago. We currently have 264 operated wells and 144 wells that are operated by others. Haynesville horizontals are actually flowing to sales. And we're seeing some good improvement in our drilling and optimization of our frac designs.

I'll remind you that we have 2 focus areas, the DeSoto or Holly area up in the Northern DeSoto Parish and then our Shelby area down in East Texas in Nacogdoches, San Augustine and Shelby counties. I'll remind you that in Shelby, the drilling is a little bit tougher. It's high pressure, high temperature, a little deeper, a little longer laterals, so some of our costs are there, and I'll talk about that in a minute.

But one thing that's happened in Shelby that really encouraged about is the fact that the wells have really, really high pressures. They're coming on in over 10,000 pounds, so really good results there as we start to move toward the development program.

Slide 16, we can see how we've improved some of our cycle times and completions as we've driven down some of our cost. Now we'll say this cost isn’t quite as low as what we've forecast. We've had some increased labor cost from some of our drilling contractors. We had to pay a bit more for jail and diesel in some of our operating activities. But we're still targeting on bringing that down a bit more as we improve our cycle time and when we manage our business there.

In Holly, one of the big effort is continue to modify the profit mix and clusters spacing in order to optimize our completions. And in Shelby, Doug referenced it, it's a very, very important point that we have a very significant test ongoing in Shelby where we're drilling across 2 sections, and it's us and another working interest partner that we're going to drill both Haynesville and Bossier well in a section for doing that simultaneously. We're going to bring those wells on. We'll complete them all together, so we could have some 200-plus million a day and probably even more than that gross flow into sales in middle of the first quarter of next year. So that will be a very, very exciting activity for us to monitor and manage.

In Marcellus, like I said, we're having some really good results up there that's noted on Slide 17. We have a strong acreage position. We're currently producing about 104 million a day on a gross basis out of the Marcellus. It's about 25 head-to-head [ph] build up from yesterday's numbers. We have 54 operated and 4 outside-operated horizontal wells flowing to sales. Now our Northeast areas where we're really focusing and that's where our development program is, that's where 3 of our 4 drilling rigs are operating. Across our central areas where we're continuing some appraisal and delineation work.

And across both of these areas, we're seeing some very interesting results. I noted this last quarter, we're still continuing to evaluate this. But in certain areas, our production rates have improved between when we first bring the wells on and 3, 4, 5, 6 months down the road. And we're also seeing some very, very interesting flattening of our production curves as these wells come on. So very interesting in what's happening up there, we're very excited about the opportunity and we're going to continue to drill in the Northeast area with at least 3 of the rigs.

The results you can see on Slide 18. In Northeast area, we dropped 6 wells on line. They had average IPs of 6.4 million a day, somewhere over 8 million, somewhere around 5 million. Average lateral link is about 3,400 feet. These are all in Lycoming County. And we're continuing to evaluate our tubing program there and evaluate what's the best way to bring these wells online.

In the central area, our wells were completed in Armstrong and Clarion Clarion counties in the second quarter. And you can see there, there are some very interesting results as well, averaged about 5 million a day, and some of those were up over 6 million. So we're seeing some areas there. We're going to do some further investigation and we'll move into development.

Slide 19. The peak in our non-shale assets. This covers the Permian area where we've got about 22 million a day which is our oiliest area, as well about 45% of that 22 Mcfe a day is oily. Our Appalachia region, where we have about 17 million a day net, our interest of shallow production. And in East Texas/North Louisiana, primarily from the Cotton Valley, we have about 82 million a day. So you can see we have 120 million a day which is about like, I said, 22% of our net production coming from these more conventional assets.

Permian, very good cash margin, over $10 per Mcfe as a result of the oily content out there. But across all of these regions, we're very focused on cost management and flattening our declines, recompletion and work over program seem to be very successful across these areas. These assets also do a lot for us and give us an operational footprint in our shale areas. And very importantly, it allows us to hold a lot of our acreage and provide cash flow.

Last couple of slides I'm going to address, talk about TGGT, our equity midstream company that we own 50-50 with BG. We're over 1.6 Bcf a day of input and set a record in Q3 when we averaged over 1.5 Bcf a day. Our primary focus there is in the Holly area, is on restoring and increasing treating capacity. In the Shelby area, it's on continuing to build out our infrastructure as we move towards development in that region and also bringing on some additional treating capacity. And we're also looking at our tight-way ability down there for third parties.

Last slide on 21. I will highlight that after the incident occurred in the second quarter, we actually shut down all of our similar amine treating stock [ph] portfolio. We did bring on the amine treating system at Holly 3. Most recently, it's working very fine. It's in excellent operation at this point. We're installing temporary amine at Holly 6, and those will be on, like Doug said, early in '12. And we're going to restart the treating train in Holly 6 also early in '12. And Holly 6, you recall, is where we had our incident.

The restart was delayed for a couple of reasons. First and foremost, we wanted to bring in our experts and third-party experts to really assess what happened, why it happened and what was damaged. And in turn, we've decided to make some improvements, particularly to our control systems, our release systems, and ensure that our operators have the best training we can possibly give them. And I'm confident that these things, when we bring them back online, are going to have minimal risks associated with them. That's where the big driver is, to drive down our risk and make sure that there's minimal, minimal chance that we're going to have what we had experienced and may never occur again.

You can see the results on the bottom of Page 21, the impacts of this. We'll probably have a total adjusted EBITDA impact at EXCO for the full year 2011 of just slightly over $10 million.

With that, I'll turn the call back over to Mr. Miller.

Douglas H. Miller

Okay, thanks. Final comments, just talking a little bit about gas prices. Again, we're reviewing that and going around the table. I have 12 different forecasts as we would have talked to all over investors. So I think the main thing we can do is look at the forward curve, make decisions based on economics and that's what we'll be doing here over the next month for our capital budget.

It frustrates me and does a lot of people in the room here and in the business that we have a country with no energy plan. And I think we are and will be forever an importer of crude oil, 5 million barrels of which comes from an enemy that we're funding. We have begun exporting coal, and we are looking like we're going to be a major exporter of natural gas. So here's a country, the only one in the world, I might add, that has no energy policy. We're going to be an importer of crude from our enemy and an exporter of coal and natural gas to China to build them up. It does not make sense.

Now with that, gas prices being as cheap as they are and without any energy policy, you are going to see facilities built to export because gas is so cheap. We're selling it today at $3.70-ish, China is paying $17 to $20, Japan is paying $17 to $20, and they want a bunch more gas. We do have power plants being built today. Our forecast is over the next 3 to 4 years power demand to go out by 10 to 12 Bcf a day. And it looks like if gas prices stay cheap and our branch stay is high that over the next 4 or 5 years, you could get exports in the 15 to 20 Bcf a day. So it's going to take a lot of capital or up in prices to do what we're doing. It's a shame that -- Boone is on our onboard, he's a good friend, and he's been working and spending a lot of money on this natural gas vehicle because it does work, we've proven it. I think it will work on its own math. But there's over 5 billion vehicles around the world working on natural gas. And we have 100,000 of them. It doesn't make sense that we can't create a policy.

With that, I'll shut up and get off the soapbox and open it up to questions.

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