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.

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

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.

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.

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.

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.

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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.

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.

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.

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.

Our strengths

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

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

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Our joint ventures with BG Group in our shale plays allow us to share the development risk and costs of these capital intensive projects with a large, investment grade partner. We have received $1.8 billion of net proceeds from BG Group from the formation of four separate joint ventures. In addition, BG Group agreed to fund an aggregate of $550.0 million of our share of deep drilling costs in our Haynesville/Bossier and Marcellus shale resource plays. The funds received from our joint venture partner allow us to accelerate development of the shale plays, while affording us the opportunity to evaluate and fund additional shale acreage acquisitions in our focus areas.

A brief description of each of our joint ventures with BG Group follows:

Over the past three years, we have hired skilled, multi-disciplined technical and operational personnel who have allowed us to increase our horizontal drilling program. In addition, our access to BG Group’s personnel in our shale joint ventures complements our execution strategy.

Our Haynesville, Bossier and Marcellus shale resource plays present significant opportunities to grow our reserves with low finding and development costs. Because a significant portion of the acreage in these areas is held-by-production we have the flexibility to concentrate our drilling activities in higher return areas rather than having our drilling program dictated by the location of expiring leases.

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We operate a significant portion of our properties, coupled with significant held-by-production acreage, which permits us to manage our operating costs and better control capital expenditures as well as the timing of development and exploitation activities. As of December 31, 2010, we operated 7,276 of our 7,730 gross wells, or wells representing approximately 96.8% of our Proved Developed Reserves.

Our management team has led both public and private oil and natural gas companies and has an average of over 27 years of industry experience in exploring, acquiring, developing and exploiting oil and natural gas properties. Since acquiring a controlling interest in us in December 1997, the management team has increased our Proved Reserves from approximately 4.7 Bcfe in the beginning of 1998 to approximately 1.5 Tcfe in December 2010.

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,

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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

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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.

Debt summary

A summary of our outstanding long-term debt as of February 17, 2011 and December 31, 2010 and a brief description of our credit agreement and senior notes is presented below.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended, matures on March 30, 2014 and has a borrowing base of $1.0 billion as of December 31, 2010.

The outstanding balance under the EXCO Resources Credit Agreement as of February 17, 2011 reflects a reduction of $300.0 million due primarily to a distribution from TGGT and BG Group’s election to participate for their 50% share of the Chief Transaction.

2018 Notes

On September 15, 2010 we closed an underwritten offering of $750.0 million aggregate principal amount of 7.5% senior unsecured notes maturing on September 15, 2018. We received proceeds of approximately $724.1 million from the offering after deducting an original issue discount, commissions and offering fees and expenses. The net proceeds from the offering were used to redeem the 2011 Notes with the remaining balance being used to pay a portion of the outstanding balance under the EXCO Resources Credit Agreement. The 2018 Notes are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries, which excludes EXCO Water Resources, LLC and all of our jointly-held equity investments with BG Group. All of our non-guarantor subsidiaries are considered unrestricted subsidiaries under the 2018 Notes, with the exception of our equity investment in OPCO.

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Summary of geographic areas of operations

The following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2010:

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Our development and exploitation project areas

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.

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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.

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Our operational focus has resulted in significant improvements in drilling and completion efficiencies. In late 2010, in our DeSoto Parish area, we achieved our best drilling time performance to date of 28 days from spud to rig release. This was accomplished by the most consistent and experienced modern flex rig in our fleet, the same rig that drilled our first horizontal well in 2008. We have recently set several drilling records in the play including single bit runs from surface to intermediate hole depth and single bit runs from intermediate to production hole total depth, typically 16,500 ft.

We continue to use the latest technologies to enhance our shale development. We recently completed 168 square miles of 3-D seismic in DeSoto Parish and acquired another 126 square miles in the Shelby Area. In 2010, we monitored five wells with micro-seismic and another 19 wells with our buried array monitoring system. In our completion evaluation process, we gathered production logs on 10 horizontal wells and conducted tracer evaluations on 17 horizontal wells. In 2010, we also drilled a dedicated vertical pressure monitoring well and installed permanent down hole gauges to measure and monitor the reservoir pressure in the Haynesville shale.

In addition to our success in reducing well costs with drilling time improvements and efficiencies, we are also focused on optimizing completions. Almost 50% of our well cost is incurred during the completion phase. We plan to implement cost effective and efficient design changes as part of our manufacturing program. We are utilizing four dedicated fracture stimulation fleets and continue to see greater consistency and efficiencies in our fracturing operations. These commitments have provided consistent availability of completion equipment and personnel available to us, and we have maintained a proper alignment with our drilling to keep a low inventory of wells waiting on completion. At December 31, 2010, we had 17 wells in our completion inventory which is low considering our drilling activity level and pad development process. We target a minimum working inventory of completions and design our program to flow gas directly to the sales line once the well is completed. We have no wells currently waiting on pipeline. This is possible due to close coordination with our jointly-held midstream company, TGGT, which installs the gathering lines in concert with our drilling operations in most of our development areas.

Bossier shale

The Bossier shale that overlies the Haynesville shale is a significant resource that is present across most of our acreage. We drilled and tested two horizontal Bossier wells in our core DeSoto Parish area during 2010 with initial flow rates of 11 and 13 Mmcf per day. We will continue to monitor well performance of these two wells before we begin additional testing in this area. In the Shelby Area we drilled our first EXCO operated Bossier well in the fourth quarter 2010 and are presently testing the well. Additional Bossier testing for the Shelby Area will be conducted during 2011.

Cotton Valley, Hosston, Travis Peak, Pettet

The Vernon Field in Jackson Parish, Louisiana produces from the lower Cotton Valley and Bossier Sand formations at depths ranging from 12,000 to 15,000 feet. For 2010, the Vernon Field represented 24.2% of our company wide net production. The technical expertise obtained in the development of the Vernon Field and the exploitation of these high-pressure, high-temperature reservoirs greatly assisted in the rapid development of the Haynesville shale. The current focus in the Vernon Field is maintaining production and minimizing our operating expense. Within the past year, we have reduced our production decline rate.

We have acreage and production in Caddo and DeSoto Parishes, Louisiana, primarily in four fields—Holly, Kingston, Caspiana and Longwood. We also have acreage and production in Harrison, Panola, Gregg and Rusk Counties in Texas, primarily across five fields—Carthage, Waskom, Oak Hill, Minden and Danville. We are focused on producing primarily from Cotton Valley sands at depths ranging from 10,400 to 11,000 feet and the Travis Peak and Hosston Sands at 7,800 to 10,000 feet.

Due to low commodity prices, we are not actively drilling in these formations. We plan to conduct 25 recompletions in the DeSoto Parish area in 2011, primarily targeting the upper Cotton Valley and Hosston intervals. We maintain a strong emphasis on base production performance and focus on operating expense

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reductions. We typically run multiple service rigs replacing tubing, changing pumps, cleaning out fill and implementing general repairs to maintain optimum production levels.

Appalachia

The Appalachian Basin includes portions of the states of Kentucky, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee and covers an area of over 185,000 square miles. The Appalachian Basin is strategically located near the high energy demand markets of the northeast United States and, as a result, the natural gas produced from the area has typically commanded a higher wellhead price relative to other North American natural gas areas.

Most production in the Appalachian Basin has been traditionally derived from relatively shallow, low porosity and low permeability sand and shale formations at depths from approximately 1,000 to over 8,000 feet. Assets in the area are typically characterized by long reserve lives, high drilling success rates, and a large number of low productivity wells with shallow decline rates. Our operations in the area have primarily included maintaining our existing production from shallow wells and testing our Marcellus shale acreage.

The emergence of the Marcellus shale play over the last several years resulted in a shift in our focus from the traditional shallow development to exploration and development of the Marcellus shale. We currently hold approximately 350,000 net acres in the Appalachian Basin.

Marcellus shale

In June 2010, we closed our Appalachian joint venture with BG Group. Subsequently, the joint venture has positioned itself with key staff and resources to execute an appraisal and development program. During 2010, we spud 15 wells and completed 10 gross (4.9 net), with a 100% success rate. The 2010 program was a combination of appraisal and development wells in our east central and west central Pennsylvania areas. The development wells in west central Pennsylvania had initial production rates ranging from 3.7 to 6.3 Mmcf per day from lateral lengths varying from 2,500 to 5,700 feet. The east central Pennsylvania area had lower initial production rates ranging from 1.5 to 4.0 Mmcf per day from lateral lengths varying from 2,500 to 4,900 feet. A significant amount of data was collected and is being used to formulate a development plan based on these preliminary performance results in each area.

We continue to build our core positions in west central and northeast Pennsylvania. Concurrently, development capital will be focused in these areas, particularly where we have realized strong results, have significant acreage, and have market access that is either existing or currently under construction. We are adding to both positions with the acquisition of approximately 56,000 net acres in northeast Pennsylvania from Chief Oil & Gas LLC and the pending acquisition of approximately 32,000 net acres in west central Pennsylvania. These acquisitions are significant additions to our existing portfolio and provide years of multi-rig development inventory. The most recent completion on our northeast Pennsylvania acquired acreage is the best well in our Marcellus shale portfolio, and it recently produced to sales at a rate of approximately 10 Mmcf per day at 3,900 psi.

We continue to see improvement in all cost performance metrics. Total well costs are down 20% for 2010 with meaningful reductions in both drilling and completion costs. Improvements in drilling times, water management infrastructure, efficiencies due to multi-well pad drilling and single sourcing are among the key drivers to our cost reductions in 2010. These metrics will continue to improve as infrastructure is added, development activity is increased, and key findings from our 2010 program are implemented.

We currently have two horizontal drilling rigs operating in the basin with plans to exit 2011 with 4-5 operated rigs. The 2011 drilling plan includes both an appraisal program across parts of our acreage position and a three rig program in our development areas. We plan to drill 12 gross (6.0 net) operated appraisal wells, 52 gross (17.9 net) operated development wells and participate in 4 gross (0.3 net) outside operated wells during 2011, while spending net drilling and completion capital totaling $38 million. All of our planned 2011 drilling

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activity is located in areas which have sufficient gas markets and immediate take away capacity or a defined strategy to be sales ready by year end 2011.

Pennsylvania area

Our Pennsylvania area encompasses 27 counties. Drilling, completion and production activities target the Marcellus shale as well as the Upper Devonian, Venanago, Bradford and Elk sandstone groups at depths from 1,800 to 8,100 feet. We plan to drill 64 gross operated Marcellus shale wells in the Pennsylvania area during 2011.

West Virginia area

Our West Virginia area includes 30 counties and stretches from the northern to the southern areas of the state. Drilling, completion and production activities target the Marcellus shale and multiple reservoirs of the Mississippian and Devonian formations found at depths ranging from 1,500 to 8,100 feet. During 2011, we plan to participate in 4 gross (0.3 net) outside operated horizontal Marcellus wells.

Permian

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

Sugg Ranch Field

The Sugg Ranch Field is located primarily in Irion County, Texas. We have a total working interest of 96.0% in the property. At December 31, 2010, we had Proved Reserves of 93.8 Bcfe and 334 gross producing wells. Production is primarily from the Canyon Sand from depths of 6,700 to 7,900 feet. We currently plan to use two operated vertical rigs to drill 72 gross (69.8 net) wells in 2011.

Our oil and natural gas reserves

Changes in our Proved Reserves for the year ended December 31, 2010 were impacted by the following significant factors and events:

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The following table summarizes Proved Reserves at December 31, 2010, 2009 and 2008. This information was prepared in accordance with the rules and regulations of the Securities and Exchange Commission, or the SEC.

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We believe that PV-10 before income taxes, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics, which can differ significantly, among comparable companies. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is calculated in accordance with ASC 932. The following table provides a reconciliation of our PV-10 to our Standardized Measure:

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

The estimates of Proved Reserves and future net cash flow for our non-shale properties as of December 31, 2010, 2009 and 2008 have been prepared by Lee Keeling. Our estimated Proved Reserves and future net cash flows for our shale properties were prepared by Haas Engineering for 2010 and 2009. Lee Keeling and Haas Engineering are independent petroleum engineering firms that perform a variety of reserve engineering and valuation assessments for public and private companies, financial institutions and institutional investors. Lee Keeling has performed these services for over 50 years and Haas Engineering was founded in 1980. We selected Haas Engineering to prepare our estimates of Proved Reserves for our shale properties based upon its specific experience in performing services for industry peers with shale operations. Our internal technical employees responsible for reserve estimates and interaction with our independent engineers include corporate officers with petroleum and other engineering degrees, professional certifications and industry experience similar to those of our independent engineering firms. The estimates of future plugging and abandonment costs necessary to compute PV-10 and Standardized Measure were computed internally. Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s extensive visits, collection of any and all required geological, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely on various assumptions, including definitions and economic assumptions required by the SEC, including the use of constant oil and natural gas pricing, use of current and constant operating costs and current capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our

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Proved Undeveloped Reserves. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See “Note 23. Supplemental information relating to oil and natural gas producing activities (unaudited)” of the notes to our consolidated financial statements for additional information regarding our oil and natural gas reserves and our Standardized Measure.

Lee Keeling and Haas Engineering also examined our estimates with respect to reserve categorization, using the definitions for Proved Reserves set forth in SEC Regulation S-X Rule 4-10(a) and SEC staff interpretations and guidance. In preparing an estimate of our Proved Reserves and future net cash flows attributable to our interests, Lee Keeling and Haas Engineering did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of the examination something came to the attention of Lee Keeling or Haas Engineering which brought into question the validity or sufficiency of any such information or data, Lee Keeling or Haas Engineering did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. Lee Keeling and Haas Engineering determined that their estimates of Proved Reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of Proved Reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.

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

The following discussion and analysis of our proved oil and natural gas reserves and changes in our Proved Reserves is intended to provide additional guidance on the operational activities, transactions, economic and other factors which significantly impacted the determination of our estimate of Proved Reserves as of December 31, 2010 and changes in our Proved Reserves during 2010. This discussion and analysis should be read in conjunction with “Note 23. Supplemental information relating to oil and natural gas producing activities (unaudited)” and in “Risk factors” addressing the uncertainties inherent in the estimation of oil and natural gas reserves elsewhere in this Annual Report on Form 10-K. The following table summarizes the significant changes in our Proved Reserves from January 1, 2010 to December 31, 2010.

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Current year oil and natural gas production

Total oil and natural gas production in 2010 was 112.0 Bcfe, which includes approximately 29.4 Bcfe in production from 2010 extensions and discoveries that were not reflected in our beginning of the year Proved Reserves.

Sales of reserves in place

During 2010, we entered into the Appalachia JV which resulted in the sale of an undivided 50% interest in our oil and natural gas assets in Appalachia of approximately 133.1 Bcfe of Proved Reserves.

New discoveries and extensions

EXCO had additions to Proved Reserves through extensions and discoveries in 2010 of 645.6 Bcfe. Of this total, 592.7 Bcfe, or 91.8%, of the extensions and discoveries, were predominantly from our Haynesville shale play activities, including 565.1 Bcfe in our core DeSoto Parish area and 27.6 Bcfe in the Shelby Area. During 2010, we began developing our core DeSoto Parish area on 80-acre spacing in a manufacturing mode utilizing multi-pad development. This area has demonstrated consistent well performance and EXCO has 63 contiguous operated sections under development. By the end of 2010, we had 14 wells on 80-acre spacing patterns and we expect to have 11 sections fully developed in the first quarter of 2011. Estimated ultimate recovery, or EUR, is based on production performance analysis and supported with reliable technologies such as seismic, microseismic, reservoir simulation, pressure transient and volumetric analysis. Our core DeSoto Parish area proved undeveloped locations were booked using a probabilistic approach as of December 31, 2010, resulting in an average of 2.7 offsetting proved undeveloped locations, each having an average EUR of 6.1 Bcfe, for each producing well drilled. As a result, the gross EUR from these Haynesville wells on a 640-acre unit increased to 48.8 Bcfe at year end 2010 compared with 26.4 Bcfe at year end 2009. As of December 31, 2010, our Proved Undeveloped Reserves represent 45.2% of our Proved Reserves with the Haynesville shale representing approximately 71.9% of our total Proved Undeveloped Reserves at year end.

Revisions of previous estimates

Revisions in 2010 include positive revisions due to prices and other economic factors of 53.1 Bcfe. Net positive revisions resulting from performance factors were 66.4 Bcfe. In East Texas/North Louisiana we had positive revisions of 75.0 Bcfe, primarily due to an improvement in the decline rate in our Vernon Field. We also had positive performance revisions in our Permian division of 13.7 Bcfe resulting from better than expected well performance. These positive revisions were partially offset by decreases of approximately 22.3 Bcfe in our Appalachia area, primarily in Proved Undeveloped Reserves.

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Impacts of 2010 changes in reserves on depletion rate and statements of operations

For the year ended December 31, 2010, there were no transactions or other Proved Reserve changes that had a significant impact on depreciation, depletion and amortization.

East Texas/North Louisiana Carry

We received a positive impact on our full cost pool amortization rate in 2010 from the East Texas/North Louisiana Carry. However, the impact of future development costs for proved undeveloped reserve additions, which are not subject to a carry, more than offset the 2010 benefits. As a result, our depletion rate increased during 2010. With the completion of carry commitment in East Texas/North Louisiana, we would anticipate an increase in our depletion rate in 2011 and subsequent periods.

Our production, prices and expenses

The following table summarizes revenues, net production of oil and natural gas sold, average sales price per unit of oil and natural gas and costs and expenses associated with the production of oil and natural gas.

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Our interest in productive wells

The following table quantifies information regarding productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut in wells. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refer to the total number of physical wells in which we hold a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interests we hold in all wells. We compute the number of net wells by totaling the percentage interests we hold in all our gross wells.

As of December 31, 2010, we were the operator of 7,276 gross (3,774.3 net) wells, which represented approximately 96.8% of our proved developed producing reserves as of December 31, 2010.

Our drilling activities

In 2010 and 2009, our drilling activities were primarily focused on horizontal drilling in shale plays, particularly in the Haynesville/Bossier and Marcellus shales.

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The following tables summarize our approximate gross and net interests in the wells we drilled during the periods indicated and refer to the number of wells completed at any time during the period, regardless of when drilling was initiated. At December 31, 2010, we had 26 gross (11.3 net) wells being drilled and 11 gross (5.6 net) wells being completed. In addition to the wells being completed, at December 31, 2010, we had 37 gross (18.0 net) wells waiting to be completed.

Our developed and undeveloped acreage

Developed acreage includes those acres spaced or assignable to producing wells. Undeveloped acreage represents those acres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The definitions of gross acres and net acres conform to how we determine gross wells and net wells. The following table sets forth our developed and undeveloped acreage at December 31, 2010:

The primary terms of our oil and natural gas leases expire at various dates. Much of our undeveloped acreage is held-by-production, which means that these leases are active as long as we produce oil or natural gas from the acreage or comply with certain lease terms. Upon ceasing production, these leases will expire. We have 72,320, 24,752 and 10,714 net acres with leases expiring in 2011, 2012 and 2013, respectively.

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

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Sales of producing properties and undeveloped acreage

We periodically review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of properties with higher operating costs, properties that are not within our core geographic operating areas and properties that are not strategic. We also seek to opportunistically divest properties in areas in which acquisitions and investment economics no longer meet our objectives.

Equity investments

Midstream operations

EXCO and BG Group each own a 50% interest in TGGT, which provides midstream services to natural gas producers. TGGT’s operations are principally designed to facilitate delivery of natural gas produced in the East Texas/North Louisiana region to markets. Revenues are primarily derived from sales of natural gas purchased for resale and fixed fees earned from gathering, treating and compression of natural gas. TGGT does not own any natural gas processing facilities.

Due to the rapid natural gas production growth in the Haynesville/Bossier shale, TGGT has increased its throughput dramatically in its core areas of operation within East Texas and North Louisiana. TGGT’s primary customers are EXCO and BG Group. TGGT owns and operates TGG Pipeline, Ltd., or TGG, and Talco Midstream Assets, Ltd., or Talco. The assets of TGG include treating facilities and gathering pipelines that connect to downstream pipelines. Talco’s assets primarily consist of gathering pipelines that provide well hookups and lateral connections. Current throughput totals approximately 1.2 Bcf per day.

In 2010, TGG completed a 27 mile, 36–inch diameter header for gathering natural gas from Haynesville/Bossier shale and Cotton Valley wells, principally in DeSoto Parish, Louisiana. TGG operates amine, glycol, and H2S facilities, which treat natural gas in order to meet pipeline quality specifications for downstream transportation. TGGT’s system has access to 13 interstate and intrastate pipeline markets. TGG has approximately 126 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe in its legacy East Texas area with a current throughput capacity of approximately 460 Mmcf per day. TGG continues to see growth in throughput in both its existing East Texas gathering system area as well as in its new shale-focused systems in the North Louisiana area.

Additionally, TGG has initiated major midstream expansion efforts in the Shelby Area in East Texas. Certain pipelines and facilities were completed in 2010 and upon completion in 2011, TGGT estimates it will operate approximately 72 miles of gathering systems. The current throughput capacity is approximately 190 Mmcf per day, and the throughput capacity is planned to increase to approximately 740 Mmcf per day by the third quarter of 2011. In addition, the gathering systems are expected to have treating capacity in excess of 500 Mmcf per day by year end 2011.

Through Talco, TGGT owns and operates a network of gas gathering systems comprised of over 800 miles of pipeline located in East Texas and North Louisiana. These gathering pipelines primarily service Cotton Valley production in East Texas/North Louisiana and Haynesville/Bossier production in North Louisiana. Approximately 200 miles of Talco’s gathering lines are located in the core area of the Haynesville/Bossier shale in North Louisiana. Natural gas is gathered through fixed fee arrangements pursuant to which the fee income represents an agreed rate per unit of throughput. The revenues earned from these arrangements are directly related to the volume of natural gas that flows through the systems and are not directly dependent on commodity prices.

The increase in throughput across TGGT’s operations has generated increases in operating cash flows in 2010. The projected drilling programs by producers targeting the Haynesville/Bossier shale areas of East Texas and North Louisiana are expected to generate continued growth for TGGT.

Our Appalachia midstream operations are jointly owned with BG Group. The near term focus is to maximize take-away from existing infrastructure and leverage the TGGT personnel and practices as the Marcellus shale region develops. The current plans, which are largely dependent on the results of the Appalachia

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JV’s development and appraisal drilling results, will likely be a combination of built facilities, joint ventures with third parties or outsourcing in certain areas.

Appalachia upstream operations

OPCO serves as the operator of our Appalachia producing and development operations and owns a 0.5% working interest in our Appalachia joint venture properties. EXCO and BG Group each own 50% of OPCO.

Other gas gathering systems

A gathering system and treating facility in the area of our Vernon Field operations, or Vernon Gathering, gathers and transports natural gas from our Vernon Field and, to a lesser extent, natural gas from third-party producers. The gathering system transports natural gas to our Caney Lake facility where the natural gas is treated and delivered to interstate pipeline systems. During 2010, average throughput in Vernon Gathering was approximately 100 Mmcf per day.

Our principal customers

For the year ended December 31, 2010, sales to BG Energy Merchants LLC and Louis Dreyfus Energy Services LP, accounted for approximately 21.5% and 10.1%, respectively, of total consolidated revenues. The loss of any significant customer may cause a temporary interruption in sales of, or lower price for, our oil and natural gas, but we believe that the loss of any one customer would not have a material adverse effect on our results of operations or financial condition.

Competition

The oil and natural gas industry is highly competitive, particularly with respect to capturing prospective oil and natural gas properties and oil and natural gas reserves. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and headcount substantially larger than ours. Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity.

The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Depending on the region, we may experience difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We are unable to predict when, or if, such shortages may again occur or how such shortages and price increases will affect our development and exploitation program. Competition has also been strong in hiring experienced personnel, particularly in petroleum engineering, geoscience, accounting and financial reporting, tax and land professions. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We are often outbid by competitors in our attempts to acquire properties or companies. The oil and natural gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas. Competitive conditions may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. All of these challenges could make it more difficult to execute our growth strategy and increase our costs.

Applicable laws and regulations

General

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

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the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

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

Production regulation

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

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

Our Pennsylvania operations are subject to numerous stringent federal and state statutes and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing, storage and disposal of water used in the drilling and completion process, restrict or prohibit drilling activities in certain areas and on certain lands lying within wetlands and other protected areas, require closing earthen impoundments and impose liabilities for pollution resulting from operations or failure to comply with regulatory filings.

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making the prediction of future costs or the impact of regulatory compliance to new laws and statute difficult. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.

FERC matters

The availability, terms and cost of downstream transportation significantly affect sales of natural gas, oil and NGLs. With regard to natural gas, the interstate transportation and sale for resale is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and

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various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Since 1985, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. Federal and state regulations govern the rates and terms for access to intrastate natural gas pipeline transportation, while states alone regulate natural gas gathering activities. With regard to oil and NGLs, the rates and terms and conditions of service for interstate transportation is regulated by FERC. Tariffs for such transportation must be just and reasonable and not unduly discriminatory. Oil and NGL transportation that is not federally regulated is left to state regulation.

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

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

Federal, state or Indian oil and natural gas leases

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

Surface Damage Acts

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

Other regulatory matters relating to our pipeline and gathering system assets

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

The Pipeline Safety Act of 1992, as reauthorized and amended, mandates requirements in the way that the energy industry ensures the safety and integrity of its pipelines. The law applies to natural gas and hazardous

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liquids pipelines, including some natural gas gathering pipelines. Central to the law are the requirements it places on each pipeline operator to prepare and implement an “integrity management program.” The Pipeline Safety Act of 1992 mandates a number of other requirements, including increased penalties for violations of safety standards and qualification programs for employees who perform sensitive tasks. The DOT has established a number of rules carrying out the provisions of this act. The Pipeline and Hazardous Materials Safety Administration of DOT, or the PHMSA, has established a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We could incur significant expenses as a result of these laws and regulations.

U.S. federal taxation

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

U.S. environmental regulations

The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Federal environmental statutes to which our domestic activities are subject include, but are not limited to:

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

Under the CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing or remediating a release; (2) administrative, civil or criminal fines or penalties; or (3) specified damages, such as loss of use, property damage and natural resource damages. The scope of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges into waters of the United States, including certain wetlands, of dredged materials, which may apply to various of our construction activities, as well as requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines. State laws governing

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discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters.

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

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

RCRA and comparable state and local programs impose requirements on the management, treatment, storage and disposal of both hazardous and nonhazardous solid wastes. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease, in addition to the locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generate hazardous and non-hazardous solid waste in our routine operations. It is possible that certain wastes generated by our operations, which are currently exempt from “hazardous waste” regulations under RCRA, may in the future be designated as “hazardous waste” under RCRA or other applicable state statutes and become subject to more rigorous and costly management and disposal requirements.

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. The CAA and analogous state laws require certain new and modified sources of air pollutants to obtain permits prior to commencing construction. Smaller sources may qualify for exemption from permit requirements, for example, through qualifications for permits by rule or general permits. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional operating permits. Federal and state laws designed to control hazardous (i.e., toxic) air pollutants might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution

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regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forgo construction, modification or operation of certain air emission sources.

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

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

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

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

We are also unable to assure you that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with them in the future. For example, although federal legislation regarding the control of emissions of greenhouse gases or GHGs, for the present, appears unlikely, EPA has been implementing regulatory measures under existing CAA authority and some of those regulations may affect our operations. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to warming of the Earth’s atmosphere resulting in climatic changes. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.

On June 3, 2010, EPA published its so-called GHG tailoring rule that will phase in federal prevention of significant deterioration (PSD) and Title V operating permit requirements for new sources and modifications with the potential to emit specific quantities of GHGs. Those permitting provisions, when they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions, with the first annual report—for 2010—being due in March of 2011. Although this rule does not limit the amount of

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GHGs that can be emitted, it could require us to incur costs to monitor, recordkeep and report GHG emissions associated with our operations.

Many of the company’s exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand and other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Many of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well.

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

In addition, state, local and river basin conservancy districts have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include, but not be limited to, the following:

Local regulations, which may by preempted by state and federal regulations, have included the following which, while prompted by hydraulic fracturing, may extend to all operations:

OSHA and other regulations

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

Title to our properties

When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local mineral records. We do conduct title investigations and, in most cases,

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obtain a title opinion of local counsel before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.

Our properties are generally burdened by:

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

Operational Factors

Oil and natural gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. In the event of exploration failures, environmental damage, or other accidents such as well fires, blowouts, equipment failure, human error, substantial liabilities to third parties or governmental entities may be incurred, the satisfaction of which could substantially reduce available cash and possibly result in loss of oil and natural gas properties. As is common in the oil and natural gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our operating results, financial position or cash flows. For further discussion on risks see Item 1A. Risk Factors .

Our employees

As of December 31, 2010, we employed 927 persons. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be good. We also utilize the services of independent consultants and contractors.

Forward-looking statements

This Annual Report on Form 10-K contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

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

We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other “forward-looking” information. We do not undertake

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any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Annual Report on Form 10-K, including, but not limited to:

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no

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control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Annual Report on Form 10-K. The risk factors noted in this Annual Report on Form 10-K and other factors noted throughout this Annual Report on Form 10-K provide examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. Please see “Item 1A. Risk factors” for a discussion of certain risks of our business and an investment in our common stock.

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

Glossary of selected oil and natural gas terms

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

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

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

Appraisal wells.     Wells drilled to convert an area or sub-region from the resource to the reserves category

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

Bcf.     One billion cubic feet of natural gas.

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

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

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

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

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

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

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

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

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

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

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

Exploratory Well.     A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

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

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

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

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

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

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

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

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

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

Mbbl.     One thousand stock tank barrels.

Mcf.     One thousand cubic feet of natural gas.

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

Mmbbl.     One million stock tank barrels.

Mmbtu.     One million British thermal units.

Mmcf.     One million cubic feet of natural gas.

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

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

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

Mmmbtu.     One billion British thermal units.

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Net Acres or Net Wells.     The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX.     New York Mercantile Exchange.

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

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

Pad drilling.     The drilling of multiple wells from the same site.

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

Present value of estimated future net revenues or PV-10.     The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.

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

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

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

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

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

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

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

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

Proved Undeveloped Reserves.     Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

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

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

Reserve Life.     The estimated productive life, in years, of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this Annual Report on Form 10-K, reserve life is calculated by dividing the Proved Reserves (on an Mmcfe basis) at the end of the period by production volumes for 2010.

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

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

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

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

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Spud.     To start the well drilling process.

Standardized Measure of discounted future net cash flows or the Standardized Measure.     Under the Standardized Measure, future cash flows for the years ended December 31, 2010 and 2009 are estimated by applying the simple average spot prices for the trailing twelve month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for fixed and determinable escalations, to the estimated future production of year-end Proved Reserves. Spot prices used to compute estimated future cash flows for the year ended December 31, 2008 are based on year-end spot prices for such year. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

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

Tcf.     One trillion cubic feet of natural gas.

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

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

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

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

Available information

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