EXCO Resources, Inc. Reports Full Year 2009 Results and 2010 Outlook

EXCO Resources, Inc. (NYSE: XCO) today announced fourth quarter and full year 2009 results, year end 2009 proved reserves and 2010 planned activity.

Our operating results for the fourth quarter and full year 2009 reflect the successful achievement of our 2009 strategic initiatives to focus our operations on developing our shale assets. These initiatives included entering into upstream and midstream joint ventures with BG Group plc, or BG Group, in East Texas/North Louisiana, accelerating the development of our Haynesville shale assets within the joint venture, disposing of non-strategic assets and beginning our horizontal drilling in the Marcellus shale. The joint ventures and asset sales resulted in $2.1 billion of proceeds which allowed us to repay approximately 60% of our indebtedness outstanding at December 31, 2008. The following table highlights certain key financial and operating results for the fourth quarter and full year of 2009:

The production sold in the joint venture and divestiture transactions in 2009 represents approximately 40% of our beginning of year production level, making comparisons of financial and operating results for 2009 with those of 2008 of limited usefulness.

- Oil and natural gas production was 23 Bcfe, or 254 Mmcfe per day, and 128 Bcfe, or 351 Mmcfe per day, for the fourth quarter and full year 2009, respectively. Although these volumes were less than 2008 primarily due to the asset sales, the declines were partially offset by the increase in our Haynesville production.

Our gross operated Haynesville production increased from an average of 7 Mmcf per day in the fourth quarter of 2008 to 340 Mmcf per day as of February 7, 2010. We achieved this significant production growth completing only 34 operated wells and with an average of only 7 operated rigs drilling.

Our net Haynesville production, including non-operated volumes, averaged 6 Mmcf per day for the fourth quarter 2008, 47 Mmcf per day for the fourth quarter 2009 and 96 Mmcf per day as of February 7, 2010. The fourth quarter 2009 and current net production levels reflect the sale of 50% of our interest to BG Group through the joint venture transaction.

As we continue to increase our level of drilling in the Haynesville play, we expect our production to grow substantially. We currently estimate our total net production to average between 315-330 Mmcfe per day for the full year 2010, and fourth quarter 2010 production is expected to average between 360-380 Mmcfe per day. This level of production growth will effectively replace the production sold during 2009.

- Oil and natural gas revenues, excluding the impacts of derivative financial instruments (derivatives), were $107 million for the fourth quarter 2009 and $551 million for the full year 2009. Cash settlements of oil and natural gas derivatives were $124 million for the fourth quarter 2009 and $478 million for the full year 2009.

- Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative gains and losses, non-cash ceiling test write-downs and other non-cash items typically not included by securities analysts in published estimates, was $0.29 per share for the fourth quarter 2009 and $0.98 per share for the full year 2009.

- Adjusted EBITDA, defined as earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (a non-GAAP measure) for the fourth quarter 2009 was $168 million and $746 million for the full year 2009.

- Our principal midstream operations are now conducted through TGGT Holdings, LLC, or TGGT, an entity jointly-owned 50/50 with an affiliate of BG Group. Our results of operations are now reported as an equity method investment. TGGT’s average throughput currently exceeds 850 Mmcf per day. During the fourth quarter 2009, TGGT completed the first of four stages of a 29-mile, 36-inch diameter header system to gather and deliver our Haynesville shale production to interstate pipelines. The first stage of this header system became operational on November 30, 2009.

- Our full year 2009 GAAP earnings were negatively impacted by a net non-cash loss of approximately $1.3 billion representing a ceiling test write-down during the first quarter of 2009 and unrealized losses on derivatives of $239 million. These loss transactions were partially offset by $676 million of gains on certain divestitures and other non-recurring operational items during 2009. See our Net Income section, which presents details for each of the aforementioned significant non-cash items.

- For 2009, the Securities and Exchange Commission (SEC) implemented new rules which require reserve calculations to be based on the simple average of first of the month cash prices for a trailing twelve month period. Under the previous SEC rules, reserves were calculated using year-end cash prices. Using the $3.87 per Mmbtu for natural gas and $61.18 per Bbl for oil pursuant to the new SEC pricing, our December 31, 2009 proved reserves were approximately 1.0 Tcfe. Using the SEC’s previous pricing method, which would have required the use of $5.79 per Mmbtu for natural gas and $79.36 per Bbl of oil, our proved reserves would have been approximately 1.2 Tcfe.

In addition to the impact of the lower pricing, our reserve quantities were impacted by the sale of 790 Bcfe of proved reserves during 2009 through our joint venture and divestiture transactions. Reserve additions of 242 Bcfe more than replaced production of 128 Bcfe. Our 2009 direct finding and development cost, which includes drilling, completion, capitalized exploitation and workover costs, was $1.24 per Mcfe. Including revisions other than price, our finding and development cost was $1.59 per Mcfe. Our "all-in” finding and development cost, which also includes leasehold additions, was $1.88 per Mcfe for 2009. It is significant to note that the direct finding and development cost of our Haynesville shale program was $0.71 per Mcfe.

Douglas H. Miller, EXCO’s Chairman and Chief Executive Officer, commented, "2009 was a transformational year for EXCO. We achieved everything we set out to do, starting with our successful drilling program and results in the Haynesville area, execution of our divestiture program, including our strategic partnership with BG Group, and the deleveraging of our balance sheet. In Appalachia, we continued evaluating our Marcellus shale assets and spud our first full length horizontal well. All of this was accomplished in spite of a very difficult commodity price environment. Our derivative program provided us with the ability to execute our plans over a long-term horizon. We have completed our divestiture program enabling us to focus on our shale assets. We began 2010 with production of approximately 234 Mmcfe per day. This production level represents a new baseline which we will use to evaluate our future results. Already in 2010, our net production has increased to a current level in excess of 265 Mmcfe per day. We have increased our operated horizontal rig count to 13 in the Haynesville and plan to increase that rig count to at least 14 for the rest of the year. We also plan to run at least one operated horizontal rig in Appalachia throughout 2010 while we continue our testing and evaluations in that area. We continue to make significant investments in our people and technology to maximize the value of our shale assets. With our concentrated portfolio of Haynesville and Marcellus shales, we are well positioned for significant reserve additions and organic production growth.”

Net Income

Our reported net income (loss) and net loss available to common shareholders shown below, both GAAP measures, include certain items not typically included by securities analysts in their published estimates of financial results. Management is disclosing the non-GAAP measures of adjusted net income and adjusted net income available to common shareholders because it quantifies the financial impact of non-cash gains or losses resulting from derivatives, non-cash ceiling test write-downs and other items management believes affect the comparability of our results of operations which are included in GAAP net income measures. The following table provides a reconciliation of our net income (loss) and net income (loss) available to common shareholders to non-GAAP measures of adjusted net income and adjusted net income available to common shareholders:

Cash Flow

Our cash flow from operations before working capital changes (cash flow) for 2009 was $603 million, a 28% decrease from 2008. Fourth quarter 2009 cash flow was $107 million, a 39% decrease from the prior year’s quarter due to the combination of lower commodity prices and the impacts of our divestiture program.

Reserves

Our proved reserves at December 31, 2009 are estimated at 1.0 Tcfe with a pre-tax PV10, a non-GAAP measure, of $747.7 million, calculated pursuant to the new SEC pricing rules, which are based on the simple average of the first of the month prices for the prior twelve month period. For 2009, this equates to $3.87 per Mmbtu for natural gas and $61.18 per Bbl for oil. At year end 2009 our proved reserves were 67% proved developed and 97% natural gas. Based on our pro forma 2009 production of 84 Bcfe, our reserve life equates to 11.4 years and, more importantly, our proved developed reserve life equates to 7.7 years, reflecting the relatively long-lived nature of our proved reserves. Using the previous SEC pricing rules, which were based on year end prices of $5.79 per Mmbtu for natural gas and $79.36 per Bbl for oil, our estimated proved reserves would have been 1.2 Tcfe with a pre-tax PV10 of $1.7 billion. Using the five year futures strip price at December 31, 2009, which averaged $6.43 per Mmbtu for natural gas and $87.44 per Bbl for oil, our estimated proved reserves would have been 1.2 Tcfe with a pre-tax PV10 of $2.2 billion.

During 2009, we added 242 Bcfe of proved reserves through the drill bit and produced 128 Bcfe, resulting in a production replacement ratio of 189%. This level of reserve replacement is outstanding when considering that the majority of these new reserves resulted from our 2009 Haynesville development horizontal program where we ran an average of only 6 operated rigs for the year and completed 25 operated wells. Also in 2009, we sold 790 Bcfe and purchased 8 Bcfe. As a result of the lower prices used for our 2009 estimates of proved reserves, we had 259 Bcfe of negative revisions due to price. We also had 54 Bcfe of negative performance related revisions. Adjusted for sold reserves and price related revisions, our proved reserves grew by 8% from the prior year.

The following table presents the details of our changes in proved reserves:

Our drilling and development spending in 2009 was $300 million resulting in a direct finding and development cost of $1.24 per Mcfe. Including revisions other than price, our finding and development cost was $1.59 per Mcfe. Including $63 million of leasehold additions and our proved property acquisitions, our "all-in” finding and development cost was $1.88 per Mcfe. The following table details the components of our 2009 finding and development cost:

During 2009, we reduced the average gross cost of our Haynesville operated horizontal wells to approximately $9.5 million, and currently expect our 2010 well costs to continue at or below this level. This reflects a decrease of 25% in gross drilling and completion costs per well from approximately $12.6 million at the beginning of 2009. Our initial wells took an average of 72 days to drill and were further burdened by geological evaluation costs, including coring and pilot holes. By the end of 2009, we reduced our drilling days by nearly 50%, completed our geological evaluations and reduced many of our service costs. Because our share of capital in our wells was reduced as a result of the BG Group joint venture in August 2009, our capital expenditures for the full year reflect a higher proportion of the more costly wells drilled at the beginning of 2009. As a result, our dollar weighted average well cost was approximately $11.2 million per well for 2009. The following table illustrates the combined effects of reduced gross operated well costs and our reduced share of capital throughout 2009:

In addition to the new SEC rules regarding prices, the SEC also implemented new rules related to the classification of drilling locations as proved. The new rules allow for additional undeveloped locations to be classified as proved reserves if these locations can be supported by reliable technologies and developed in a five-year time frame. In the Haynesville, we added an average of 2.5 offsetting proved undeveloped locations with average gross reserves of 6.6 Bcf for each producing well drilled. Under the prior rules, we would have added an average of 1.6 offsetting proved undeveloped locations. Our direct finding and development cost would have been $1.40 per Mcfe, our finding and development cost, including revisions other than price, would have been $1.95 per Mcfe and our "all-in” finding and development cost would have been $2.25 per Mcfe under the old rules.

During 2009, we added 96 Bcfe to our proved developed reserves resulting in a finding and development cost of $3.13 per Mcfe. The following table details the components of our 2009 proved developed additions:

Operations activity and outlook

We spent $41 million on development and exploitation activities, drilling and completing 22 gross (10.2 net) wells, for the fourth quarter 2009, and $300 million for the full year 2009. Our overall drilling success rate for full year 2009 exceeded 98%, as we completed 106 of the 108 wells drilled. Excluding acquisitions, our total capital expenditures, which include leasing, midstream and corporate activities, were $110 million for the fourth quarter 2009 and $511 million for full year 2009.

During 2009, we also closed $234 million of acquisitions, of which $227 million were related to unproved properties. Nearly all of these acquisitions were in our core Haynesville operating area.

Pursuant to our joint development agreement, BG Group has an option to participate for 50% of our leasing and acquisitions we close within our area of mutual interest in East Texas/North Louisiana. In January 2010, we received $54 million from BG Group for a portion of the transactions closed during 2009. Assuming BG Group exercises their right to participate in the remaining 2009 transactions, we will receive an additional $102 million in 2010.

We currently have 17 operated drilling rigs and an interest in 4 drilling rigs operated by others working across our portfolio. Anticipated 2010 capital spending on drilling and midstream is anticipated to decrease as a result of the BG Carry and the midstream joint venture. Our 2010 capital plan and our 2009 capital spending by significant operating areas are presented on the following table:

(1) The decrease in the 2010 capital budget reflects a favorable impact of $205 million from the BG Carry.

We have a strong commitment to technical application, operational excellence and property evaluation to improve our understanding of our shale plays and we have made appropriate investments to reduce risks. We are members of a major shale consortium, reservoir engineering consortium and several other engineering and geoscience study projects. We are acquiring 2D seismic data, are shooting 3D seismic surveys and have initiated microseismic fracture stimulation and other monitoring projects.

East Texas/North Louisiana

East Texas/North Louisiana is our largest division in terms of production and reserves, and our primary targets across this region include the Haynesville shale, Cotton Valley, Travis Peak, Pettet and Hosston formations. Currently, our emphasis is focused on exploitation of our acreage in the Haynesville shale play where the EXCO / BG Group JV holds approximately 107,800 net acres. Since we closed the joint venture with BG Group, we have acquired approximately 22,800 net acres for the joint venture, all located in the core area of the shale play. This additional acreage is complementary to our existing acreage, operations and pipeline infrastructure and provides significant development potential in the play.

Our budgeted capital expenditures in 2010 are $255 million net to EXCO to drill 138 wells (115 operated and 23 non operated). The 115 operated wells consist of 95 Haynesville shale horizontals, seven Bossier shale horizontals, six Cotton Valley horizontals and seven wells in the Vernon area. In the EXCO / BG Group area of mutual interest (BG AMI), we will actually spend $741 million net to the JV; however, EXCO's share will only be $165 million due to the capital carry by BG Group. In East Texas/North Louisiana, we drilled and completed 18 gross wells (6.3 net) in the fourth quarter 2009. We drilled and completed 71 gross wells (25.8 net) during the year in the region and realized a 100% success rate.

We are minimizing our impact on local water supplies and have made two major water projects a top priority. We are making a significant investment in a water supply project where we plan to use discharge water from a local industrial plant as a key water source for fracture stimulation operations. This solution will lessen the impact on local water supplies, reduce truck traffic and provide an environmentally safe option for water procurement. We also have a salt water management project to transport service water and gather produced water across our acreage. This project will reduce truck traffic and handle water much more efficiently and more cost effectively.

Haynesville shale

Our development program in the Haynesville shale play transitioned from a vertical testing and data acquisition program to a horizontal development drilling program. In early 2009, we were running three operated horizontal rigs in the play and we exited 2009 with 11 operated horizontal rigs. In 2009, we spud 43 operated horizontal wells and by year end had 25 of those wells completed and flowing to sales.

Our first horizontal well, the Oden 30H #6 (EXCO/BG Group JV 100% WI) in DeSoto Parish, Louisiana, tested to sales in December 2008 at an initial production rate, or IP, of 22.9 Mmcf per day and has performed exceptionally well, having produced 3.2 Bcf of natural gas to sales in the first year of production. That level of performance has been repeated consistently in DeSoto Parish during 2009. Our average operated well IP for the DeSoto area is 22.8 Mmcf per day. We also participated in 12 outside operated horizontal Haynesville wells that were completed and turned to sales in 2009, all located in the core area. The following table summarizes the quarterly results of our operated Haynesville horizontal drilling program:

Our operational focus has resulted in significant improvements in drilling and completion efficiencies. Our initial horizontal wells in the program required 72 days from spud to rig release. During 2009, we averaged 54 days from spud to rig release and the amount of time to drill these wells has continued to improve. Our most recent wells have averaged 37 days from spud to rig release, a 50% reduction over a one year period. We are also utilizing dedicated fracture stimulation fleets and the consistency in our fracturing operations has improved and become more efficient. We work very closely with our midstream business, allowing us to immediately flow our new completions to sales.

We plan to have at least 14 operated horizontal rigs throughout most of the year and plan to drill 102 operated horizontal shale wells. We also anticipate participating in 23 horizontal shale wells operated by others in 2010. As of February 7, 2010, our gross operated Haynesville shale production is approximately 340 Mmcf per day (92 Mmcf per day net) from a total of 35 wells flowing to sales. The growth from an average of 7 Mmcf per day for the fourth quarter 2008 came from 34 completions with an average of only 7 operated rigs drilling. We expect significant production and reserve growth with our Haynesville shale development program in 2010 and beyond.

Bossier shale

The Bossier shale overlies the Haynesville shale. In 2009, we initiated a Bossier shale testing program with a procedure identical to one we used to evaluate the Haynesville shale. We acquired over 900 feet of whole core in the Bossier shale in different wells and we are conducting core analysis and other engineering studies. We have completed testing of the Bossier shale in four of our vertical Haynesville wells across our acreage by utilizing the vertical Haynesville test wells from 2008. We are encouraged with the test results to date in these vertical wells. We are now drilling our first Bossier horizontal test and expect to complete it in the first quarter of 2010. We are planning a total of seven Bossier horizontal tests across our acreage in East Texas and North Louisiana in our 2010 development plan. These seven Bossier horizontal tests are included in the total of 102 horizontal shale wells planned for the year.

Cotton Valley, Hosston, Travis Peak, Pettet

With low commodity prices during the year, our activity level in the conventional horizons has been significantly reduced. We drilled and completed 31 gross wells (15.2 net) in 2009 across the area. Our plans for 2010 include a horizontal testing program in the Cotton Valley including six tests across our DeSoto and Caddo Parish acreage to evaluate the feasibility of a larger scale horizontal program for 2011 and beyond. We are planning to drill seven wells in our Vernon area. We are also planning to conduct 28 recompletions in the DeSoto Parish area, primarily targeting the Hosston interval. We maintain a strong emphasis on base production performance and focus on operating expense reductions.

Appalachia

Our operations in Appalachia are conducted in Pennsylvania and West Virginia where we hold over 654,000 net acres. We believe approximately 343,000 net acres are prospective for Marcellus and Huron potential, and approximately 186,000 net acres are in the over-pressured Marcellus fairway. Approximately 70% of our fairway acreage is held by shallow production as we have traditionally drilled for and exploited the Clinton/Medina sandstone, stacked Devonian sandstone, Devonian shale, Berea shale and other productive horizons.

On November 24, 2009, we closed the sale of our Ohio and northwestern Pennsylvania producing assets. Net proceeds were approximately $130 million, subject to customary post closing adjustments. We expect to receive an additional $13 million of proceeds from this sale upon receipt of pending consents on certain wells. With this divestiture we have exited these operating areas, allowing us to focus the majority of our financial and technical resources toward our shale opportunities and provide higher economic returns.

Throughout 2009, our main focus has been on consolidating our leasehold position in key development areas as well as continuing our testing and evaluation to determine the best areas and techniques for Marcellus shale development. We spud a horizontal well late in the fourth quarter of 2009 and were continuing drilling as of December 31, 2009. In addition, 1 gross (1.0 net) vertical Marcellus well was completed during the fourth quarter of 2009 in northeastern Pennsylvania and is currently under evaluation. During 2009, we drilled and completed 5 gross (5.0 net) development wells targeting the conventional reservoirs and 8 gross (8.0 net) exploratory wells to test the Marcellus shale potential across our acreage position.

Our capital budget for 2010 totals $154 million for drilling, land, seismic, midstream expansion and operations. Exploration and development plans for 2010 will be focused on the Marcellus shale. These activities will include drilling 11 gross (11.0 net) operated horizontal wells, participating in 4 gross (0.6 net) horizontal wells operated by others and drilling 6 gross (6.0 net) operated vertical wells. We will continue testing and reservoir evaluation activities in selected areas, acquiring both 2D and 3D seismic data, and expanding our gathering assets. Our land strategy for 2010 is to continue building contiguous acreage positions that lend themselves to development of the Marcellus shale and utilizing multi-well pad operations. We continue to actively acquire acreage in our focus areas and are currently in various stages of negotiations with multiple parties for approximately 42,000 net acres.

Permian

In the Permian, we hold approximately 99,000 net acres of which approximately 79,000 net acres are in our Canyon Sand field. During 2009, we focused on evaluating 3D seismic and disposing of non-core assets. The production in our Canyon Sand field is approximately 40% oil and 60% liquids rich natural gas. As oil prices recovered during 2009, we began drilling a one-rig program and plan on continuing this level of activity throughout 2010.

We drilled and completed 3 gross (2.9 net) wells in our Permian area Canyon Sand field during the fourth quarter 2009 and achieved a 100% success rate. This brings the total number of wells drilled during 2009 in this field to 14 gross (12.6 net) with an 85% success rate. In 2010, we plan to spend approximately $29 million drilling 40 wells.

Midstream – TGGT Holdings, LLC

In connection with our upstream joint venture with BG Group, we also sold a 50% interest in TGGT Holdings, LLC, or TGGT. TGGT owns the midstream assets located within the BG AMI in East Texas and North Louisiana and is accounted for using the equity method of accounting. The TGGT capital budget for 2010 is $101 million, $50.5 million net to our interest. Although this budget will be mostly funded by internal TGGT cash flow, we have included in our budget a $8 million contribution to TGGT. In addition, the management of TGGT is evaluating several expansion projects which, if approved, would require additional capital contributions.

In 2009, TGGT undertook a major expansion of its TGG system in North Louisiana in order to take advantage of the increasing opportunities for gathering of Haynesville/Bossier shale natural gas. The first phase of the expansion was the installation of a header system comprised of approximately 29 miles of 36-inch diameter pipe through the Holly field area. The header will primarily gather our produced natural gas but will also seek opportunities to gather natural gas from other producers in the area. The system provides producers with dehydration and amine treating facilities and has connections to major third party intrastate and interstate pipelines. The majority of the system was completed in the fourth quarter of 2009, and the remaining pipe segment is scheduled to be completed in the first quarter of 2010. Once completed, this system will have gathering throughput capacity in excess of 1.5 Bcf per day with the opportunity to significantly increase throughput with compression and system management. TGGT is currently in the process of evaluating additional opportunities associated with the expansion of this 29-mile pipeline system and the legacy East Texas TGG system.

The East Texas TGG system has approximately 110 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe and has access to 12 interstate pipeline markets. TGGT also owns and operates Talco, a network of eight natural gas gathering systems comprised of approximately 615 miles of pipeline in their East Texas/North Louisiana areas of operation.

During 2009, TGGT averaged 474 Mmcf per day of throughput and throughput currently exceeds 850 Mmcf per day.

Financial Data

Our consolidated balance sheets as of December 31, 2009 and 2008 and consolidated statements of operations for the three months and years ended December 31, 2009 and 2008, consolidated statements of cash flows for the years ended December 31, 2009 and 2008, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Wednesday, February 24, 2010 at 9:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID# 54910096. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website on Tuesday, February 23, 2010, after market close.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., March 10, 2010. Please call (800) 642-1687 and enter conference ID# 54910096 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.

Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website at www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this presentation, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2009 to be filed on or about February 24, 2010, our Annual Report on Form 10-K for the year ended December 31, 2008, and our other periodic filings with the SEC.

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 also may 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.

The SEC permits oil and natural gas companies in filings made with the SEC to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Beginning with reserves reported for the year ended December 31, 2009, the SEC permits optional disclosure of "probable” and "possible” reserves in its filings with the SEC. EXCO may use broader terms to describe additional reserve opportunities such as "potential,” "unproved,” or "unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2009, which will be available on our website at www.excoresources.com under the Investor Relations tab on or about February 24, 2010.