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24.02.2009 21:29:00

EXCO Resources, Inc. Reports Full Year 2008 and Fourth Quarter 2008 Results and 2009 Outlook

EXCO Resources, Inc. (NYSE: XCO) today announced full year and fourth quarter 2008 results and 2009 planned activity.

  • Oil and natural gas revenues for the full year 2008 were a record $1.4 billion, exclusive of the impacts of derivative financial instruments (derivatives), compared with the full year 2007 oil and natural gas revenues of $876 million, an increase of 60%. Oil and natural gas revenues for the fourth quarter 2008 were $249 million, prior to derivatives.
  • Oil and natural gas production was 145 Bcfe for the full year 2008, a 19% increase from the prior year’s production of 121 Bcfe, and 37 Bcfe for the fourth quarter 2008, approximately 7% higher than the prior year’s quarter. The average daily production for the fourth quarter 2008 was 403 Mmcfe per day.
  • 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 $0.82 per share for the full year 2008 and $0.13 per share for the fourth quarter 2008 compared with an adjusted net loss of $0.04 per share for the full year 2007 and $0.08 of adjusted net income per share for the fourth quarter 2007.
  • 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 full year 2008 was $978 million, an increase of approximately 28% from the full year 2007 level. Fourth quarter 2008 adjusted EBITDA was $212 million.
  • Midstream operating profit, before the effect of intercompany eliminations, was $35 million for the full year 2008 and $8 million for the fourth quarter 2008 compared with $23 million and $6 million for the full year 2007 and the fourth quarter 2007, respectively.
  • Our full year 2008 GAAP earnings were negatively impacted by net non-cash after-tax losses of approximately $1.9 billion representing ceiling test write-downs and income tax valuation allowances, which were partially offset by unrealized gains on derivatives. The after-tax impact from the same non-cash items in the fourth quarter 2008 totaled $1.2 billion. See our Net Income section, which presents details for each of the aforementioned significant non-cash items. Our ceiling test write-down in the fourth quarter 2008 was based on December 31, 2008 cash spot market prices of $5.71 per Mmbtu for natural gas and $44.60 per Bbl of oil computed in accordance with guidelines established by the Securities and Exchange Commission (SEC). None of the aforementioned non-cash items affect our liquidity or compliance with bank covenants.
  • We completed our first Haynesville shale horizontal well in December 2008, the Oden 30 H #6 (EXCO 100% WI) located in DeSoto Parish, Louisiana, which produced at an initial rate of 22.9 Mmcf per day. The well produced 1.0 Bcf in the first 64 days of production and is currently producing in excess of 12 Mmcf per day. We spud our second and third operated horizontal wells late in the quarter and have recently completed one of the two. Our Lattin 24 #4 (EXCO 92.8% WI), also located in Desoto Parish, produced at an initial rate of 24.2 Mmcf per day with 7,350 psi flowing pressure on a 26/64ths choke. The third horizontal well in DeSoto Parish is currently being completed and should be on line in early March 2009.

Douglas H. Miller, EXCO’s Chief Executive Officer commented, "EXCO had record production, revenues and cash flows in 2008. We made very good progress in exploiting our shale assets, particularly the Haynesville shale in East Texas and North Louisiana, and also began the process of exploiting the Marcellus shale in Pennsylvania. Our first two horizontal wells in DeSoto Parish, Louisiana are two of the best wells drilled in the play to date and confirmed that our core acreage, much of which is held by production, is in a very advantageous position. We plan to continue an aggressive development program in the Haynesville play in 2009 even though our overall 2009 capital expenditure budget has been reduced by over 40% from 2008 capital expenditures due to low commodity prices. Our strong production base and hedge position coupled with planned sales of non-core assets will generate substantial free cash flow in 2009 thereby allowing us to continue a significant development program and also reduce our debt.”

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 (loss) and adjusted net income (loss) 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 loss available to common shareholders to non-GAAP measures of adjusted net income and adjusted net income (loss) available to common shareholders:

  Three months ended   Three months ended   Twelve months ended   Twelve months ended

December 31, 2008

December 31, 2007 December 31, 2008 December 31, 2007
       
(in thousands, except per share amounts) Amount Per share Amount Per share Amount Per share Amount Per share
Net income (loss), GAAP $ (1,161,389 ) $ (1,995 ) $ (1,733,471 ) $ 49,656
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes
(424,807 ) 76,785 (483,811 ) 81,606
Non-cash write down of oil and natural gas properties 1,622,730 - 2,815,835 -
Nonrecurring financing costs, before taxes - - - 32,100
Income taxes on above adjustments (1) (479,169 ) (30,791 ) (932,810 ) (45,596 )
Deferred tax asset valuation allowance (2)   470,147       540,369     11,000  
Total adjustments, net of taxes   1,188,901     45,994     1,939,583     79,110  
Adjusted net income $ 27,512   $ 43,999   $ 206,112   $ 128,766  
 
Net loss available to common shareholders, GAAP (3) $ (1,161,389 ) $ (5.51 ) $ (36,995 ) $ (0.35 ) $ (1,810,468 ) $ (11.81 ) $ (83,312 ) $ (0.80 )

Adjustments shown above

1,188,901 5.64 45,994 0.44 1,939,583 12.65 79,110 0.76

Dilution attributable to stock options (4)

  -     -     -     (0.01 )   -     (0.02 )   -     -  
Adjusted net income (loss) available to common shareholders $ 27,512   $ 0.13   $ 8,999   $ 0.08   $ 129,115   $ 0.82   $ (4,202 ) $ (0.04 )
 
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding 210,944 104,522 153,346 104,364
Dilutive stock options - 2,010 5,035 2,620
Dilutive preferred stock - - - -
                       

Shares used to compute diluted EPS for adjusted net income (loss) available to common shareholders

  210,944     106,532     158,381     106,984  
 

(1) The assumed income tax rate is 40% for all periods.

(2) Deferred tax valuation allowance has been adjusted to reflect favorable impacts of adjustments.

(3) Per share amounts are based on weighted average number of common shares outstanding.

(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options for periods with adjusted net income available to common shareholders.  None of the Preferred Stock, which was issued on March 30, 2007 and converted into common stock on July 18, 2008, was dilutive for any of the periods.

Cash Flow

Our cash flow from operations before working capital changes (cash flow) for 2008 was $841 million, a 40% increase from 2007. Fourth quarter 2008 cash flow was $176 million, a 9% decrease from the prior year’s quarter due primarily to lower product prices. We utilized our cash flow in combination with drawings under our revolving credit facilities and term loans to fund our capital programs, leasing activities and acquisitions of oil and natural gas properties.

  Three months ended     Twelve months ended  
December 31,

%

change

  December 31,

%

change

 
(in thousands)   2008       2007     2008       2007  
Cash flow from operations, GAAP $ 162,949 $ 197,531 $ 974,966 $ 577,829
Net change in working capital (80 ) 821 (49,866 ) 36,139
Settlements of derivative financial instruments with a financing element
12,901 (6,194 ) (83,603 ) (14,214 )

 

       

Cash flow from operations before changes in working capital, non-GAAP measure (1)

$ 175,770   $ 192,158   -9 % $ 841,497   $ 599,754   40 %
 

(1) Cash flow from operations before working capital changes and adjustments for settlements of derivative financial instruments with a financing element is presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Cash flow from operations before working capital is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. We have also elected to exclude the adjustment for derivative financial instruments with a financing element as this adjustment simply reclassifies settlements from operating cash flows to financing activities. Management believes these settlements should be included in this non-GAAP measure to conform to the intended measure of our ability to generate cash to fund operations and development activities.

Reserves

Our proved reserves, using December 31, 2008 cash spot prices, on a constant price basis, of $5.71 per Mmbtu and $44.60 per Bbl were as follows:

 

Oil

(Mbbls)

 

Natural gas

(Mmcfe)

 

Equivalent

natural gas

(Mmcfe)

Proved developed 14,815 1,354,730 1,443,620
Proved undeveloped 5,986   460,408   496,324  
Total 20,801   1,815,138   1,939,944  
 
The changes in reserves for the year are as follows:
 
December 31, 2007 20,930 1,739,550 1,865,130
Purchase of reserves in place 635

175,679

179,489
Extensions and discoveries 5,040 259,801 290,041
Revisions of previous estimates:
Changes in price (2,407 ) (93,015 ) (107,457 )
Changes other than price (1,060 )

(130,605

) (136,965 )
Sales of reserves in place (101 ) (5,113 ) (5,719 )
Production (2,236 ) (131,159 ) (144,575 )
December 31, 2008 20,801   1,815,138   1,939,944  

Our drilling and development spending in 2008 was $693 million resulting in finding costs of $2.39 per Mcfe. Over 2008, 2007 and 2006, our finding and development costs have averaged $2.32 per Mcfe.

On December 31, 2008, the SEC issued Release No. 33-8995 amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009 and reporting reserves under the new rule is not permitted prior to the effective date in documents filed with the SEC. The new rules, among other things, may impact our proved reserves as average spot prices at the first of each month for a trailing twelve-month period will be used in contrast to the existing end of quarter spot market prices. Since average spot prices in 2008 exceeded the December 31, 2008 spot prices, our estimated quantities of proved reserves would have been 2,253 Bcfe, or an increase of 16% from prices only. The definition of proved reserves has also been revised. Additional quantities of proved reserves resulting from this new definition have not been considered in the aforementioned 2,253 Bcfe. We are presently evaluating the application of this new definition to our reserve determinations.

Operations activity and outlook

We spent $204 million on development and exploitation activities, drilling and completing 118 gross (99.5 net) wells in the fourth quarter of 2008, and $989 million for the full year 2008. Our overall drilling success rate for full year 2008 exceeded 98%, as we completed 467 of the 475 wells drilled. Our total capital expenditures, including leasing, midstream and corporate activities, were $240 million in the fourth quarter 2008. As commodity prices continued declining in the fourth quarter 2008, we accelerated our reduction of drilling rigs, which reduced our growth in production. We currently have 11 drilling rigs operating across our portfolio, which we have reduced from 32 drilling rigs late in the third quarter of 2008 in response to lower commodity prices. Anticipated 2009 capital spending on drilling and leasing in our exploration and production operations is reduced in all operating areas while midstream capital has been increased as we begin building additional capacity in the East Texas/North Louisiana area. Our 2009 capital plan and our 2008 capital spending by significant operating areas are presented on the following table:

 

2009 planned

gross wells

 

2009

Capital

budget

 

2008

Actual

spending

 

2009

Increase

(decrease)

(dollars in millions)
East Texas/North Louisiana 64 $ 284 $

507

$

(223

)
Appalachia 58 65

212

(147

)
Mid-Continent 24 31 62

(31

)
Permian/Rockies 40 36

115

(79

)
Midstream - 141 55 86

Corporate and other

-   25  

38

 

(13

)
Total 186 $ 582 $ 989 $ (407 )

Although our board of directors has approved our 2009 capital budget of up to $582 million, we will continue to evaluate planned projects based on current commodity prices and service costs. We may decide to defer capital expenditures in certain operating areas if those projects do not meet our economic return hurdles.

We are continuing with plans to sell certain non-core assets over the next twelve months and are also continuing to explore joint venture opportunities. Although specific additional sales have not been announced, proceeds of all sales or joint ventures will be used to reduce debt and allow more capital to be focused on our shale development and other activities.

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 have been the upper and lower Cotton Valley, Travis Peak, Pettet and Hosston formations. While we have continued to drill and exploit these formations, we are reducing most of this activity in response to low commodity prices, but we are increasing emphasis and expanding our activity in our Haynesville shale play position. Our 2009 capital spending outlook for the division totals $284 million, with $189 million allocated to Haynesville shale activities (primarily drilling and completion activity). In East Texas/North Louisiana, we drilled and completed 38 gross (27.1 net) wells in the fourth quarter 2008. We drilled and completed 158 gross wells (117.7 net) during the year in East Texas/North Louisiana and realized a 100% success rate.

Haynesville Shale

A significant amount of our Haynesville shale acreage is held by production and is within areas of the play which have been proven productive by our and our competitors’ drilling and completion activities. During 2008, we strategically focused on adding to our leasehold and drilling to delineate the shale play rather than focusing on maximizing production from the shales. During the fourth quarter of 2008, our activities in the Haynesville shale play transitioned from a vertical testing and data acquisition program to a horizontal development program. By the end of the fourth quarter 2008, we had drilled nine operated vertical wells and spud five horizontal wells in the play (three EXCO operated, two outside operated). Our drilling to date in Harrison County, Texas and Caddo and DeSoto Parishes, Louisiana has identified a Haynesville shale section up to 300 feet thick. We are seeing a consistent shale section over the areas of the play delineated to date and we are very encouraged with our results. Our first operated horizontal well located in DeSoto Parish, the Oden 30 H#6, initially flowed 22.9 Mmcf per day at 7,800 psi flowing pressure on a 26/64ths choke. Our second horizontal well in DeSoto Parish, the Lattin 24 #4 initially flowed 24.2 Mmcf per day at 7,350 psi flowing pressure on a 26/64ths choke and is performing similarly to the Oden. Our third horizontal well in DeSoto Parish, the Sammo Partnership 18 #5, is currently in the completion phase and should be on line in early March. We also have an outside operated horizontal well in the completion phase that should be on line in early March. We are currently running four operated horizontal rigs and three outside operated rigs in the play. Our current plans in the Haynesville shale anticipate a peak of six operated horizontal drilling rigs running by mid 2009. In total, we expect to drill 34 horizontal wells, seven of which will be drilled by other operators during 2009, with 27 of these wells forecasted to be completed in 2009. We believe our Haynesville shale acreage could contain potential reserves of approximately 4.5 Tcf.

Our Haynesville shale production for the week ended February 16, 2009 was 35 Mmcf per day gross (26 Mmcf per day net). We expect significant production and reserve growth from our Haynesville shale development program in 2009 and beyond.

Cotton Valley

Recent reductions in gas prices have put pressure on Cotton Valley economics, but through high grading our drilling opportunities and expected cost reductions, certain projects continue to meet our economic hurdle criteria. We plan to drill three operated Cotton Valley wells in the Vernon Field area, nine operated wells in the Holly/Caspiana Field and two operated wells in the Danville Field. We currently have two vertical rigs drilling in our Vernon Field area and two vertical rigs operating in northwest Louisiana in our Holly/Caspiana Field. The existing rigs are under term drilling contracts and as these commitments expire, we plan to release these rigs.

Appalachia

In Appalachia, we primarily operate in Pennsylvania, Ohio, and West Virginia, where we have historically drilled for the Clinton/Medina sandstone, stacked Devonian sandstones, Devonian shales, Berea shale and other productive horizons. During the fourth quarter of 2008, we achieved a 100% drilling success rate on the 42 gross (40.7 net) wells drilled on our Appalachian properties. During 2008, we drilled 149 gross (139.2 net) wells and achieved a 99% success rate. At the end of the fourth quarter of 2008, we had two active drilling rigs; one pursuing conventional targets and one pursuing unconventional targets.

We hold in excess of 1,038,000 net leasehold acres which represents an increase of over 175,000 acres as compared to December 31, 2007. This increase resulted from leasing activities in the Marcellus play together with our February 2008 acquisition of shallow assets. We now control approximately 395,000 acres in the Marcellus shale fairway, with more than 249,000 acres located in the over-pressured core area of the play. A significant percentage of this fairway acreage is held-by-production by our shallow producing assets. We also hold 130,000 acres within the Huron shale play in West Virginia.

Successful testing of the Marcellus and Huron has been conducted within the over-pressured and the normal to under-pressured areas of the basin. We have identified areas with encouraging reservoir characteristics, including thickness, pressures and total organic content. During 2008, we drilled and completed two horizontal Marcellus wells in our over-pressured area of central Pennsylvania with initial production rates of 1.0 Mmcf per day and 3.4 Mmcf per day following one-stage and four stage fracs, respectively. The number of fracs and resulting production rates were lower than expected, as our lateral sections were shortened due to geological issues. To avoid similar issues and improve drilling efficiencies, we are acquiring 3-D seismic in certain areas and have ordered new-build, fit-for-purpose drilling rigs. Our primary efforts are to evaluate and plan the development of our Marcellus shale position in the core over-pressured areas of Pennsylvania and West Virginia. During the fourth quarter 2008, we spud two vertical wells and drilled and cased two horizontal wells. We plan to complete these two horizontal wells in the second quarter of 2009.

We believe our present leasehold position in the Marcellus and Huron shale fairways contains 7–12 Tcf of potential reserves.

Other

We drilled and completed 26 gross (24.3 net) wells in our Permian area Canyon Sand Field during the fourth quarter and achieved a 96% success rate. This brings the total number of wells drilled during 2008 in this field to 118 gross (111.2 net) with a 98% success rate. In 2009, we will drill two wells to earn 11,000 net contiguous acres under a joint venture and will evaluate recently acquired 3-D seismic over approximately 35,000 net acres adjacent to the Canyon Sand Field. Our total leasehold in this area is approximately 77,000 net acres. Fourth quarter net production of 25.9 Mmcfe per day is up from less than 20 Mmcfe per day in November 2007 when EXCO took over operations.

Our Mid-Continent division production averaged approximately 66 Mmcfe per day during the fourth quarter 2008. In the Mid-Continent, we drilled 12 gross (7.4 net) wells and achieved a 92% success rate. While we had one rig running at year end, no rigs are currently running in the Mid-Continent division.

Midstream

During the fourth quarter 2008, we continued to see positive results from our midstream operations. Throughput on our transportation and gathering systems in East Texas and North Louisiana was 554 Mmcf per day for the fourth quarter 2008, up from 522 Mmcf per day in the third quarter 2008, and presently exceeds 570 Mmcf per day. In 2009, we will be focused on the installation of our 29 mile Haynesville Header system, which will be strategically located near our Haynesville shale development in northwest Louisiana. The first phase of the project is expected to be operational in the third quarter of 2009. When complete, the system will have throughput capacity of 450 Mmcf per day at 500 psi, expandable to more than 1.0 Bcf per day with added compression. This pipeline installation program will ensure that we and other third party producers have access to multiple gas markets.

Financial Data

Our consolidated balance sheets as of December 31, 2008 and 2007 and consolidated statements of operations for the three months and years ended December 31, 2008 and 2007, and consolidated statements of cash flows for the years ended December 31, 2008 and 2007, 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 25, 2009 at 11:00 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# 82871332. The conference call will also be webcast on EXCO’s website at http://www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website on Tuesday, February 24, 2009, 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 11, 2009. Please call (800) 642-1687 and enter conference ID# 82871332 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 http://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, 2008 to be filed on or about February 26, 2009, our Annual Report on Form 10-K for the year ended December 31, 2007, 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 has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only 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. We use the terms "probable,” "possible,” "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 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, 2008, which will be available on our website at www.excoresources.com under the Investor Relations tab on or about February 26, 2009.

EXCO Resources, Inc.

Consolidated balance sheets

   
December 31,
(in thousands)   2008     2007  
Assets
Current assets:
Cash and cash equivalents $ 57,139 $ 55,510
Accounts receivable:
Oil and natural gas 130,970 146,297
Joint interest 22,807 21,614
Interest and other 5,895 2,151
Inventory 42,479 3,686
Derivative financial instruments 247,614 66,632
Deferred income taxes - 6,764
Other   6,136     8,646  
Total current assets   513,040     311,300  
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties 481,596 334,803
Proved developed and undeveloped oil and natural gas properties 3,578,344 4,926,053
Accumulated depletion   (936,088 )   (500,493 )
Oil and natural gas properties, net   3,123,852     4,760,363  
Gas gathering assets 485,201 340,706
Accumulated depreciation and amortization   (32,232 )   (16,142 )
Gas gathering assets, net   452,969     324,564  
Office and field equipment, net 25,647 20,844
Advance on pending acquisition - 39,500
Derivative financial instruments 173,003 2,491
Deferred financing costs, net 62,884 20,406
Other assets 880 6,226
Goodwill   470,077     470,077  
Total assets $ 4,822,352   $ 5,955,771  
 

EXCO Resources, Inc.

Consolidated balance sheets

     
December 31,
(in thousands, except per share and share data)   2008       2007
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 172,400 $ 106,305
Accrued interest payable 28,746 21,835
Revenues and royalties payable 108,130 100,978
Income taxes payable 160 87
Current portion of asset retirement obligations 1,830 1,656
Derivative financial instruments   11,607     47,306
Total current liabilities   322,873     278,167
Long-term debt 3,019,738 2,099,171
Asset retirement obligations and other long-term liabilities 125,279 89,810
Deferred income taxes 9,371 271,398
Derivative financial instruments 12,590 109,205
Commitments and contingencies - -
 
7.0% Cumulative Convertible Perpetual Preferred Stock, par value $0.001 per share, 39,008 shares outstanding at December 31, 2007, liquidation preference of $391,218
- 388,574
Hybrid Preferred Stock, par value $0.001 per share, 160,992 shares outstanding at December 31, 2007, liquidation preference of $1,614,616
- 1,603,704
 
Shareholders' equity:

Preferred stock, $0.001 par value; authorized shares - 10,000,000; issued and outstanding shares - 200,000 shares at December 31, 2007 presented above

- -
Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 210,968,931 at December 31, 2008 and 104,578,941 at December 31, 2007
 
211 105
Additional paid-in capital 3,070,766 1,043,645
Retained earnings (deficit)   (1,738,476 )   71,992
Total shareholders' equity   1,332,501     1,115,742
Total liabilities and shareholders' equity $ 4,822,352   $ 5,955,771
 

EXCO Resources, Inc.

Consolidated statement of operations

         
Three months ended Twelve months ended
December 31, December 31,
(in thousands, except per share and share data)   2008       2007     2008       2007  
Revenues:
Oil and natural gas $ 248,840 $ 265,560 $ 1,404,826 $ 875,787
Midstream   23,580     4,628     85,432     18,817  
Total revenues   272,420     270,188     1,490,258     894,604  
Costs and expenses:
Oil and natural gas production 60,545 47,650 238,071 168,999
Midstream operating expenses 23,126 4,950 82,797 16,289
Gathering and transportation 3,703 3,548 14,206 10,210
Depreciation, depletion and amortization 113,609 109,623 460,314 375,420
Write-down of oil and natural gas properties 1,622,730 - 2,815,835 -
Accretion of discount on asset retirement obligations 2,432 1,344 6,703 4,878

General and administrative

  24,282     18,495     87,568     64,670  
Total cost and expenses   1,850,427     185,610     3,705,494     640,466  
Operating income (loss) (1,578,007 ) 84,578 (2,215,236 ) 254,138
Other income (expense):
Interest expense (60,471 ) (34,575 ) (161,638 ) (181,350 )
Gain (loss) on derivative financial instruments 487,923 (53,323 ) 384,389 26,807
Other income (expense)   (1,515 )   2,578     3,981     10,157  
  425,937     (85,320 )   226,732     (144,386 )
Income (loss) before income taxes (1,152,070 ) (742 ) (1,988,504 ) 109,752
Income tax expense (benefit)   9,319     1,253     (255,033 )   60,096  
Net income (loss)   (1,161,389 )   (1,995 )   (1,733,471 )   49,656  
Preferred stock dividends   -     (35,000 )   (76,997 )   (132,968 )
Net loss available to common shareholders $ (1,161,389 ) $ (36,995 ) $ (1,810,468 ) $ (83,312 )
Earnings per share:
Basic
Net loss available to common shareholders $ (5.51 ) $ (0.35 ) $ (11.81 ) $ (0.80 )
Weighted average common shares outstanding   210,944     104,522     153,346     104,364  
Diluted
Net loss available to common shareholders $ (5.51 ) $ (0.35 ) $ (11.81 ) $ (0.80 )
Weighted average common and common equivalent shares outstanding
  210,944     104,522     153,346     104,364  
 

EXCO Resources, Inc.

Consolidated statement of cash flows

     
Year ended Year ended
(in thousands) December 31, 2008 December 31, 2007
Operating Activities:
Net income (loss) $ (1,733,471 ) $ 49,656
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
(Gain) loss on sale of other assets 39 (941 )
Depreciation, depletion and amortization 460,314 375,420
Stock option compensation expense 15,978 12,632
Accretion of discount on asset retirement obligations 6,703 4,878
Write-down of oil and natural gas properties 2,815,835 -
Non-cash change in fair value of derivatives (483,811 ) 81,606
Cash settlements of assumed derivatives 83,603 14,214
Deferred income taxes (255,285 ) 66,171
Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt and term loan
 
15,195 10,332
Effect of changes, net of acquisition effects, in:
Accounts receivable 7,884 (59,290 )
Other current assets 1,734 (3,092 )
Accounts payable and other current liabilities   40,248     26,243  
Net cash provided by operating activities   974,966     577,829  
 
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment
(1,004,792 )

(654,982

)

Property and Midstream acquisitions

(719,330 )

(2,191,987

)
Proceeds from disposition of property and equipment 15,543 490,362
Advance payment on pending acquisition - (39,500 )
Proceeds from sales of marketable securities - 5,228
Other investing activities   -     (5,558 )
Net cash used in investing activities   (1,708,579 )   (2,396,437 )
 
Financing Activities:
Borrowings under credit agreements 1,700,136 2,235,500
Repayments under credit agreements (776,200 ) (2,221,532 )
Proceeds from issuance of common stock, net of underwriter's commissions and initial public offering costs
14,777 4,162
Proceeds from issuance of Preferred Stock, net of underwriter's commissions and issuance costs
- 1,992,273
Dividends on preferred stock (82,827 ) (127,134 )
Settlements of derivative financial instruments with a financing element
(83,603 ) (14,214 )
Deferred financing costs and other   (37,041 )   (17,759 )
Net cash provided by financing activities   735,242     1,851,296  

Net increase in cash

1,629 32,688
Cash at beginning of period   55,510     22,822  
Cash at end of period $ 57,139   $ 55,510  
 
Supplemental Cash Flow Information:
Interest paid $ 134,087   $ 182,192  
Income taxes received $ -   $ (6,075 )
Derivative financial instruments assumed in acquisitions $ -   $ (102,219 )
Supplemental non cash investing:
Capitalized stock compensation $ 4,060   $ 2,411  
Capitalized interest $ 3,861   $ -  
Issuance of common stock for director services $ 136   $ -  
Value of shares received for sale of properties $ -   $ 4,575  
 

EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

   
Three months ended Twelve months ended
December 31, December 31,
(in thousands)   2008       2007     2008       2007  
 
Net income (loss) $ (1,161,389 ) $ (1,995 ) $ (1,733,471 ) $ 49,656

Interest expense

60,471 34,575 161,638 181,350
Income tax expense (benefit) 9,319 1,253 (255,033 ) 60,096
Depreciation, depletion and amortization   113,609       109,623       460,314     375,420  
EBITDA(1) (977,990 ) 143,456 (1,366,552 ) 666,522
Accretion of discount on asset retirement obligations 2,432 1,344 6,703 4,878
Non-cash write-down of oil and natural gas properties 1,622,730 2,815,835 -
Non-cash change in fair value of derivative financial instruments
(439,840 ) 76,785 (493,689 ) 81,606
Stock based compensation expense   5,136     5,904     15,978     12,632  

Adjusted EBITDA (1)

$ 212,468     227,489     978,275   $ 765,638  

Interest expense (2)

(45,438 ) (34,575 ) (151,760 ) (181,350 )
Income tax (expense) benefit (9,319 ) (1,253 ) 255,033 (60,096 )
Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt
8,668 (468 ) 15,195 10,332
Deferred income taxes 9,372 1,253 (255,285 ) 66,171
Changes in operating assets and liabilities 99 (1,109 ) 49,905 (37,080 )
Settlements of derivative financial instruments with a financing element
  (12,901 )   6,194     83,603     14,214  
Net cash provided by operating activities $ 162,949   $ 197,531   $ 974,966   $ 577,829  
 
  Three months ended   Twelve months ended
December 31, December 31,
(in thousands)   2008       2007     2008       2007  
 
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities $ 162,949 $ 197,531 $ 974,966 $ 577,829
Investing activities (223,442 ) (367,885 ) (1,708,579 ) (2,396,437 )
Financing activities 22,497 79,067 735,242 1,851,296
Other financial and operating data:
EBITDA(1) (977,990 ) 143,456 (1,366,552 ) 666,522
Adjusted EBITDA(1) 212,468 227,489 978,275 765,638
 

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or "EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. "Adjusted EBITDA” represents EBITDA adjusted to exclude non-cash write-downs of oil and natural gas properties, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives and stock-based compensation. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our revolving and term credit agreements and the indenture governing our 7 1/4 % senior notes. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.

 

(2) Excludes non-cash changes in fair value of $15.0 million and $9.9 million for the three and twelve months ended December 31, 2008 for interest rate swaps included in GAAP interest expense. There were no interest rate swaps in the 2007 periods.

 
 

EXCO Resources, Inc.

Summary of operating data

           
Three months ended Twelve months ended
December 31,

%

Change

  December 31,

%

Change

 
  2008     2007   2008     2007
 
Production:
Oil (Mbbls) 593 469 26 % 2,236 1,645 36 %
Gas (Mmcf) 33,472 31,828 5 % 131,159 111,419 18 %
Oil and natural gas (Mmcfe) 37,030 34,642 7 % 144,575 121,289 19 %
 
Average sales prices (before derivative financial instrument activities):
 
Oil (per Bbl) $ 56.11 $ 88.25 -36 % $ 96.93 $ 71.17 36 %
Gas (per Mcf) 6.44 7.04 -9 % 9.06 6.81 33 %
Total production (per Mcfe) 6.72 7.67 -12 % 9.72 7.22 35 %
 
Average costs (per Mcfe):
Oil and natural gas operating costs $ 1.22 $ 0.98 24 % $ 1.11 $ 0.95 17 %
Gathering and transportation costs 0.10 0.10 - 0.10 0.08 25 %
Production and ad valorem taxes 0.42 0.39 8 % 0.53 0.44 20 %

General and administrative

0.66 0.53 25 % 0.61 0.53 15 %
Depletion 2.88 3.01 -4 % 3.01 2.95 2 %
Depreciation and amortization 0.19 0.15 27 % 0.17 0.15 13 %

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