10-Q 1 d10q.htm FORM 10-Q Form 10-Q
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

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

For the quarterly period ended June 30, 2010

OR

 

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

For the transition period from              to             

Commission File Number 001-32743

 

 

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Texas   74-1492779
(State of incorporation)   (I.R.S. Employer Identification No.)

12377 Merit Drive

Suite 1700, LB 82

Dallas, Texas

  75251
(Address of principal executive offices)   (Zip Code)

(214) 368-2084

(Registrant’s telephone number, including area code)

 

 

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

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

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

 

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

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

The number of shares of common stock, par value $0.001 per share, outstanding as of July 29, 2010 was 212,654,604

 

 

 


Table of Contents

EXCO RESOURCES, INC.

INDEX

 

PART I.    FINANCIAL INFORMATION   
Item 1.    Financial Statements    3
   Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009    3
   Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009    5
   Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009    6
   Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2010 and 2009    7
   Notes to Condensed Consolidated Financial Statements    8
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    33
Item 3.    Quantitative and Qualitative Disclosures About Market Risk    53
Item 4.    Controls and Procedures    54
PART II.    OTHER INFORMATION    54

Item 1A.

   Risk Factors    54

Item 2.

   Unregistered Sales of Securities and Use of Proceeds    57
Item 6.    Exhibits    57
   Signatures    58
   Index to Exhibits    59

 

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PART I—FINANCIAL INFORMATION

 

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

(in thousands)

   June 30,
2010
    December 31,
2009
 
     (Unaudited)        

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 98,027      $ 68,407   

Restricted cash

     75,246        58,909   

Accounts receivable, net:

    

Oil and natural gas

     63,362        56,485   

Joint interest

     88,944        47,104   

Interest and other

     17,651        10,832   

Inventory

     12,600        15,830   

Derivative financial instruments

     102,507        138,120   

Other

     40,471        6,401   
                

Total current assets

     498,808        402,088   
                

Equity investments

     288,143        216,987   

Oil and natural gas properties (full cost accounting method):

    

Unproved oil and natural gas properties

     622,294        492,882   

Proved developed and undeveloped oil and natural gas properties

     2,114,990        1,875,749   

Accumulated depletion

     (1,207,745     (1,132,604
                

Oil and natural gas properties, net

     1,529,539        1,236,027   
                

Gas gathering assets

     145,954        180,506   

Accumulated depreciation and amortization

     (20,939     (22,841
                

Gas gathering assets, net

     125,015        157,665   
                

Office and field equipment, net

     24,238        31,771   

Deferred financing costs, net

     18,756        7,602   

Derivative financial instruments

     39,912        34,677   

Goodwill

     218,256        269,656   

Other assets

     11,234        2,421   
                

Total assets

   $ 2,753,901      $ 2,358,894   
                

See accompanying notes.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     June 30,     December 31,  

(in thousands, except per share and share data)

   2010     2009  
     (Unaudited)        

Liabilities and shareholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 87,368      $ 112,991   

Revenues and royalties payable

     106,693        79,356   

Accrued interest payable

     16,302        16,193   

Current portion of asset retirement obligations

     900        900   

Income taxes payable

     5,210        210   

Derivative financial instruments

     639        3,264   

Current maturities of long-term debt

     446,831        —     
                

Total current liabilities

     663,943        212,914   
                

Long-term debt, net of current maturities

     477,500        1,196,277   

Deferred income taxes

     —          —     

Derivative financial instruments

     5,648        11,688   

Asset retirement obligations and other long-term liabilities

     60,327        78,427   

Commitments and contingencies

     —          —     

Shareholders’ equity:

    

Preferred stock, $0.001 par value; authorized shares - 10,000,000; none issued and outstanding

     —          —     

Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 212,648,328 at June 30, 2010 and 211,905,509 at December 31, 2009

     213        212   

Additional paid-in capital

     3,124,991        3,105,238   

Accumulated deficit

     (1,578,721     (2,245,862
                

Total shareholders’ equity

     1,546,483        859,588   
                

Total liabilities and shareholders’ equity

   $ 2,753,901      $ 2,358,894   
                

See accompanying notes.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three months ended
June 30,
    Six months ended
June 30,
 

(in thousands, except per share data)

   2010     2009     2010     2009  

Revenues:

        

Oil and natural gas

   $ 118,344      $ 146,252      $ 249,338      $ 318,460   

Midstream

     —          12,942        —          29,955   
                                

Total revenues

     118,344        159,194        249,338        348,415   
                                

Costs and expenses:

        

Oil and natural gas production

     31,024        48,394        58,082        101,512   

Midstream operating

     —          11,719        —          30,169   

Gathering and transportation

     12,873        4,055        23,986        7,952   

Depreciation, depletion and amortization

     45,339        55,180        84,157        136,974   

Write-down of oil and natural gas properties

     —          —          —          1,293,579   

Accretion of discount on asset retirement obligations

     1,001        2,018        2,090        4,089   

General and administrative

     25,866        22,488        52,285        43,035   

Gain on divestures and other operating items

     (574,946     8,382        (575,353     7,977   
                                

Total costs and expenses

     (458,843     152,236        (354,753     1,625,287   
                                

Operating income (loss)

     577,187        6,958        604,091        (1,276,872

Other income (expense):

        

Interest expense

     (14,476     (46,891     (25,110     (83,023

Gain (loss) on derivative financial instruments

     707        (31,017     99,856        190,367   

Other income

     57        13        117        35   

Equity method income

     5,290        —          5,379        —     
                                

Total other income (expense)

     (8,422     (77,895     80,242        107,379   
                                

Income (loss) before income taxes

     568,765        (70,937     684,333        (1,169,493

Income tax expense

     4,452        1,055        4,452        2,110   
                                

Net income (loss)

   $ 564,313      $ (71,992   $ 679,881      $ (1,171,603
                                

Earnings (loss) per common share:

        

Basic

        

Net income (loss)

   $ 2.66      $ (0.34   $ 3.20      $ (5.55
                                

Weighted average common shares outstanding

     212,497        211,089        212,293        211,042   
                                

Diluted

        

Net income (loss)

   $ 2.62      $ (0.34   $ 3.15      $ (5.55
                                

Weighted average common and common equivalent shares outstanding

     215,498        211,089        215,520        211,042   
                                

See accompanying notes.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Six months ended
June 30,
 

(in thousands)

   2010     2009  

Operating Activities:

    

Net income (loss)

   $ 679,881      $ (1,171,603

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Depreciation, depletion and amortization

     84,157        136,974   

Stock option compensation expense

     8,463        6,480   

Accretion of discount on asset retirement obligations

     2,090        4,089   

Write-down of oil and natural gas properties

     —          1,293,579   

Gain on divestitures

     (574,878  

Income from equity investments

     (5,379     —     

Non-cash change in fair value of derivatives

     21,711        46,196   

Cash settlements of assumed derivatives

     907        (90,294

Deferred income taxes

     —          2,110   

Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011

     3,847        23,767   

Effect of changes in:

    

Accounts receivable

     (65,218     27,300   

Other current assets

     (4,081     (3,497

Accounts payable and other current liabilities

     30,353        (48,168
                

Net cash provided by operating activities

     181,853        226,933   
                

Investing Activities:

    

Additions to oil and natural gas properties, gathering systems and equipment

     (263,361     (267,405

Property acquisitions

     (438,382     (62,963

Restricted cash

     (16,337     (37,500

Deposit on pending divestitures

     —          57,688   

Investment in equity investments

     (68,500     —     

Proceeds from disposition of property and equipment

     956,296        55,783   

Advances to Appalachia JV

     (30,448     —     
                

Net cash provided by (used in) investing activities

     139,268        (254,397
                

Financing Activities:

    

Borrowings under credit agreements

     1,352,399        52,949   

Repayments under credit agreements

     (1,622,463     (22,740

Proceeds from issuance of common stock

     9,091        1,648   

Payment of common stock dividends

     (12,740     —     

Settlements of derivative financial instruments with a financing element

     (907     90,294   

Deferred financing costs and other

     (16,881     (20,468
                

Net cash provided by (used in) financing activities

     (291,501     101,683   
                

Net increase in cash

     29,620        74,219   

Cash at beginning of period

     68,407        57,139   
                

Cash at end of period

   $ 98,027      $ 131,358   
                

Supplemental Cash Flow Information:

    

Cash interest payments

   $ 25,520      $ 72,718   
                

Supplemental non-cash investing and financing activities:

    

Capitalized stock option compensation

   $ 2,175      $ 1,180   
                

Capitalized interest

   $ 6,114      $ 2,797   
                

Issuance of common stock for director services

   $ 25      $ 35   
                

See accompanying notes.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

 

          Additional    Retained     Total  
     Common Stock    paid-in    earnings     shareholders’  

(in thousands)

   Shares    Amount    capital    (deficit)     equity  

Balance at December 31, 2008

   210,969    $ 211    $ 3,070,766    $ (1,738,476   $ 1,332,501   

Issuance of common stock

   207      —        1,683      —          1,683   

Share-based compensation

           7,660      —          7,660   

Net loss

           —        (1,171,603     (1,171,603
                                   

Balance at June 30, 2009

   211,176    $ 211    $ 3,080,109    $ (2,910,079   $ 170,241   
                                   

Balance at December 31, 2009

   211,905    $ 212    $ 3,105,238    $ (2,245,862   $ 859,588   

Issuance of common stock

   743      1      9,115      —          9,116   

Share-based compensation

           10,638      —          10,638   

Common stock dividends

           —        (12,740     (12,740

Net income

           —        679,881        679,881   
                                   

Balance at June 30, 2010

   212,648    $ 213    $ 3,124,991    $ (1,578,721   $ 1,546,483   
                                   

See accompanying notes.

 

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EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

1. Organization and basis of presentation

Unless the context requires otherwise, references in this quarterly report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in 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.

We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and pursuing opportunistic acquisitions. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments, and manage our capital structure.

The accompanying Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009, the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009, the Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the six months ended June 30, 2010 and 2009, are for EXCO and its subsidiaries. The consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America, or GAAP, and therefore, all intercompany transactions have been eliminated.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the SEC, and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of EXCO at June 30, 2010 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2009.

In August 2009, we discontinued reporting our midstream operations as a separate business segment in connection with the sale to an affiliate of BG Group plc, or BG Group, of a 50% interest in a newly formed company, TGGT Holdings, LLC, or TGGT, which now holds most of our East Texas/North Louisiana midstream assets.

Beginning December 31, 2009, we reclassified certain items that relate to our operations from “Other income” into “Other operating items.” Prior year amounts have been reclassified to conform to the current year presentation.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

 

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2. Significant recent activities

On April 30, 2010, we amended and restated the EXCO Resources Credit Agreement which consolidated the EXCO Resources Credit Agreement and the EXCO Operating Credit Agreement into one credit agreement with a borrowing base of $1.3 billion. Terms of the amended and restated agreement include, among other things, EXCO Operating Company, LP, or EXCO Operating and certain of its subsidiaries becoming guarantor subsidiaries under the EXCO Resources Credit Agreement and our 7  1/4% senior notes due January 15, 2011, or the Senior Notes. The amended EXCO Resources Credit Agreement matures on April 30, 2014.

On May 14, 2010, EXCO and BG Group jointly closed the purchase of Common Resources, L.L.C., or the Common Transaction. The total purchase price paid at the closing was approximately $441.6 million ($220.8 million net to EXCO), subject to customary post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under our credit agreement. The development of these assets are governed by our East Texas/North Louisiana joint venture with BG Group, or the East Texas/North Louisiana JV.

On June 1, 2010, we closed a transaction 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 for cash consideration of approximately $835.2 million, subject to customary final closing adjustments, or the Appalachia JV. In addition to the cash consideration received at closing, BG Group agreed to fund 75% of our working interest share for each deep rights well (primarily the Marcellus shale play) up to a total of $150.0 million. In conjunction with the Appalachia JV, we entered into a Joint Development Agreement, or JDA, with BG Group. The effective date of the transaction was January 1, 2010.

In conjunction with the Appalachia JV, EXCO and BG Group each own a 50% interest in an operating company, EXCO Resources (PA), LLC, or OPCO, which operates the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. On June 1, 2010, we made a $33.0 million advance to OPCO to provide working capital for our share of properties. This advance was recorded as a prepaid asset and included in “Other” current assets on our Condensed Consolidated Balance Sheet and will be offset by any payments made by OPCO for our interest in the operated properties. We will continue to fund OPCO with advances based on the activity of our properties.

In addition, certain midstream assets owned by us were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, 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. We use the equity method to account for the Appalachia Midstream, LLC.

The Appalachia JV caused a significant alteration to our full cost pool and a gain, net of a reduction in goodwill, of $575.0 million was recognized during the second quarter of 2010.

On June 30, 2010, EXCO and BG Group jointly closed 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 total purchase price paid at the closing was $355.8 million ($177.9 million net to EXCO), subject to customary post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under our 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 incremental working interests in properties that EXCO and BG Group acquired in the Common Transaction.

 

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3. Recent accounting pronouncements

On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

 

4. Significant accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2009.

 

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5. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2010:

 

(in thousands)

      

Asset retirement obligation at January 1, 2010

   $ 65,115   

Activity during the six months ended June 30, 2010:

  

Liabilities incurred during the period

     431   

Liabilities settled during the period

     (433

Reduction to retirement obligations due to divestitures

     (19,251

Accretion of discount

     2,090   
        

Asset retirement obligations at June 30, 2010

     47,952   

Less current portion

     (900
        

Long-term portion

   $ 47,052   
        

We have no assets that are legally restricted for purposes of settling asset retirement obligations.

 

6. Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all exploration, exploitation, development and acquisition costs. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs, which totaled $622.3 million and $492.9 million as of June 30, 2010 and December 31, 2009, respectively, are not subject to depletion. The $129.4 million increase in our unproved properties between December 31, 2009 and June 30, 2010 was due primarily to the properties purchased in the Southwestern Transaction and the Common Transaction, offset by reimbursements of acreage costs from BG Group in the Haynesville area and elimination of all of our unproved property costs as of June 1, 2010 in the Appalachia area in connection with the proceeds received in connection with the Appalachia JV and the related gain. No impairment of undeveloped properties occurred during the second quarter of 2010. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment and transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds.

When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with FASB ASC Subtopic 835-20 for Capitalization of Interest. We began capitalizing interest in April 2008, upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. The cost of these projects, net of any amount sold amortized or transferred amounts into the depletable full cost pool was $372.2 million as of June 30, 2010. When the balance is moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we will cease capitalizing interest.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs are divided by the total estimated quantities of Proved Reserves. This unit-of-production rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.

 

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Divestitures and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the unit-of-production rate and/or the relationship between capitalized costs and Proved Reserves. In the event a divestiture results in a significant alteration to our full cost pool, we also record a proportionate reduction of goodwill associated with our oil and natural gas properties.

At the end of each quarterly period, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the full cost ceiling, calculated as the sum of the estimated future net revenues from Proved Reserves using the simple average spot price for the trailing twelve month period using the first day of each month. For the six months ended June 30, 2010, the trailing twelve month price was $75.76 per Bbl for oil at Cushing, Oklahoma and $4.10 per Mmbtu for natural gas at Henry Hub. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results. There were no ceiling test write-downs for the first or second quarters of 2010.

For the six months ended June 30, 2009, we recognized a ceiling test write-down of $1.3 billion to our proved oil and natural gas properties. This write-down occurred during the first quarter of 2009. Under the full cost accounting rules in place prior to the SEC’s Release No. 33-8995 on December 31, 2009, the SEC required the full cost ceiling to be computed using spot market prices for oil and natural gas at our balance sheet date. On June 30, 2009, the spot price for natural gas at Henry Hub was $3.89 per Mmbtu and the spot oil price at Cushing, Oklahoma was $69.79 per Bbl.

The ceiling test calculation is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

 

7. Earnings (loss) per share

We account for earnings per share in accordance with FASB ASC Subtopic 260-10 for Earnings Per Share. ASC 260-10 requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings (loss) per share for the three and six months ended June 30, 2010 and 2009 equals the net income (loss) divided by the weighted average common shares outstanding during the periods. Diluted earnings (loss) per common share for the three and six months ended June 30, 2010 and 2009 is computed in the same manner as basic earnings (loss) per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, whether exercisable or not. Antidilutive options represented by 1,300,320 and 869,561 potential common stock equivalents were excluded from the three and six months ended June 30, 2010 diluted earnings per share. Since we incurred a net loss for the three and six months ended June 30, 2009, we have excluded potentially dilutive common stock equivalents from the assumed conversion of stock options of 14,687,706 and 14,790,302 for the three and six months ended June 30, 2009, respectively.

 

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The following table presents the basic and diluted earnings (loss) per share computations:

 

     Three months ended June 30,     Six months ended June 30,  

(in thousands, except per share amount)

   2010    2009     2010    2009  

Basic income (loss) per common share:

          

Net income (loss)

   $ 564,313    $ (71,992   $ 679,881    $ (1,171,603
                              

Shares:

          

Weighted average number of common shares outstanding

     212,497      211,089        212,293      211,042   
                              

Basic income (loss) per common share:

          

Net income (loss) per common share

   $ 2.66    $ (0.34   $ 3.20    $ (5.55
                              

Diluted income (loss) per share:

          

Net income (loss)

   $ 564,313    $ (71,992   $ 679,881    $ (1,171,603
                              

Shares:

          

Weighted average number of common shares outstanding

     212,497      211,089        212,293      211,042   

Dilutive effect of stock options

     3,001      —          3,227      —     
                              

Weighted average number of common shares and common stock equivalent shares outstanding

     215,498      211,089        215,520      211,042   
                              

Diluted income (loss) per share:

          

Net income (loss) per common share

   $ 2.62    $ (0.34   $ 3.15    $ (5.55
                              

 

8. Stock options

We account for stock options in accordance with FASB ASC Topic 718 for Compensation – Stock Compensation Topic. As required by ASC 718, the granting of options to our employees under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Volatility is determined based on the combination of the weighted average volatility of our common stock price and the weighted average volatility from five comparable public companies during the period when we were privately held. Total share-based compensation to be recognized on unvested awards as of June 30, 2010 is $23.8 million over a weighted average period of 1.09 years.

The following is a reconciliation of our stock option expense for the three and six months ended June 30, 2010 and 2009:

 

     Three months ended June 30,    Six months ended June 30,

(in thousands)

   2010    2009    2010    2009

General and administrative expense

   $ 3,603    $ 2,575    $ 7,862    $ 5,101

Lease operating expense

     251      682      601      1,379
                           

Total share-based compensation expense

     3,854      3,257      8,463      6,480

Share-based compensation capitalized

     1,070      673      2,175      1,180
                           

Total share-based compensation

   $ 4,924    $ 3,930    $ 10,638    $ 7,660
                           

During the six months ended June 30, 2010, options to purchase 364,350 shares were granted under the 2005 Incentive Plan at prices ranging from $16.34 to $22.22 per share with fair values ranging from $9.07 to $12.77 per share. During the six months ended June 30, 2009, options to purchase 178,600 shares were granted under the 2005 Incentive Plan at prices ranging from $7.89 to $16.29 per share with fair values ranging from $4.89 to $10.44 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of June 30, 2010 and December 31, 2009, there were 3,740,400 and 3,920,100 shares available to be granted under the 2005 Incentive Plan, respectively.

 

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In connection with certain divestitures, we accelerated the vesting of a number of employee stock options on the date of the employee’s termination and extended their exercise terms to one year from date of termination. For the six months ended June 30, 2010, we recognized $0.9 million in additional compensation expense related to the modification of option terms, $0.5 million of which would have been recognized over the remaining life of the options had they not been accelerated. The underlying stock price on the dates of modification ranged from $17.54 to $21.23 and the exercise prices of the options accelerated ranged from $7.50 to $24.66.

 

9. Derivative financial instruments and fair value measurements

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

We account for our derivative financial instruments in accordance with FASB ASC Topic 815. ASC 815 requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. ASC 815 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. In accordance with FASB ASC Section 815-10-65, the table below outlines the location of our derivative financial instruments on our Condensed Consolidated Balance Sheets and their financial impact in our Condensed Consolidated Statement of Operations.

Fair Value of Derivative Financial Instruments

 

(in thousands)

  

Balance Sheet location

   June 30,
2010
    December 31,
2009
 
Commodity contracts    Derivative financial instruments - Current assets    $ 102,507      $ 138,120   
Commodity contracts    Derivative financial instruments - Long-term assets      39,912        34,677   
Commodity contracts    Derivative financial instruments - Current liabilities      (639     (1,246
Commodity contracts    Derivative financial instruments - Long-term liabilities      (5,648     (11,688
Interest rate contracts    Derivative financial instruments - Current liabilities      —          (2,018
                   

Net derivative financial instruments

   $  136,132      $ 157,845   
                   

The Effect of Derivative Financial Instruments

 

          Three months ended June 30,     Six months ended June 30,  

(in thousands)

  

Statement of Operations location

   2010    2009     2010     2009  
Commodity contracts (1)    Gain (loss) on derivative financial instruments    $ 707    $ (31,017   $ 99,856      $ 190,367   
Interest rate contracts (2)    Interest expense      —        (4,597     (45     (481
                                  
Net gain (loss)       $ 707    $ (35,614   $ 99,811      $ 189,886   
                                  

 

(1) Included in these amounts are net cash receipts of $46,538 and $123,585 for the three and six months ended June 30, 2010, respectively, and net cash receipts of $142,139 and $240,568 for the three and six months ended June 30, 2009, respectively.
(2) Included in these amounts are net cash payments of $0 and $2,063 for the three and six months ended June 30, 2010, respectively, and net cash payments of $2,816 and $4,486 for the three and six months ended June 30, 2009, respectively. Our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2010.

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursement to, our derivative contract counterparties. Changes in the

 

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fair value of our derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Unrealized fair value adjustments included in “Gain (loss) on derivative financial instruments,” which do not impact cash flows, were losses of $45.8 million and $173.2 million for the three months ended June 30, 2010 and 2009, respectively, and were losses of $23.7 million and $50.2 million for the six months ended June 30, 2010 and 2009, respectively. Unrealized fair value adjustments included in “Interest expense,” which do not impact cash flows, were losses of $1.8 million for the three months ended June 30, 2009, and gains of $2.0 million and $4.0 million for the six months ended June 30, 2010 and 2009, respectively. There was no impact for the three months ended June 30, 2010, as our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2010.

We place our derivative financial instruments with the financial institutions that are lenders under our credit agreement and we believe they all have high credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with our counterparties on our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. As of June 30, 2010 and December 31, 2009, we had a net asset position of $136.1 million and $157.8 million, respectively.

Fair value measurements

We value our derivatives according to FASB ASC Topic 820 for Fair Value Measurements and Disclosures, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. This fair value may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities.

We prioritize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include:

Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.

The following presents a summary of the estimated fair value of our derivative financial instruments as of June 30, 2010 and as of December 31, 2009:

 

     For the six months ended June 30, 2010  

(in thousands)

   Level 1    Level 2     Level 3    Total  

Oil and natural gas derivative financial instruments

   $ —      $ 136,132      $ —      $ 136,132   
                              
     For the year ended December 31, 2009  

(in thousands)

   Level 1    Level 2     Level 3    Total  

Oil and natural gas derivative financial instruments

   $ —      $ 159,863      $ —      $ 159,863   

Interest rate swaps

     —        (2,018     —        (2,018
                              
   $ —      $ 157,845      $ —      $ 157,845   
                              

 

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In accordance with FASB ASC Section 815-10-45 for the Scope Section of Subtopic 815-10 for Derivatives and Hedging, we evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them gross on the Condensed Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

Oil and natural gas derivatives

Our commodity price derivatives represent oil and natural gas swap contracts. We have classified our oil and natural gas swaps and their related fair value tier as Level 2.

Oil derivatives. Our oil derivatives are swap contracts for notional Bbls of oil at fixed NYMEX West Texas Intermediate (WTI) oil prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the applicable estimated credit-adjusted risk-free rate curve, as described above.

Natural gas derivatives. Our natural gas derivatives are swap contracts for notional Mmbtus of natural gas at posted price indexes, using NYMEX Henry Hub. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Henry Hub for natural gas swaps for our existing basis swaps and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

The following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value as of June 30, 2010:

 

(in thousands, except prices)

   Volume
Mmbtus/Bbls
   Weighted average
strike price per
Mmbtu/Bbl
   Fair value at
June 30, 2010

Natural gas:

        

Swaps:

        

Remainder of 2010

   27,880    $ 7.19    $ 65,026

2011

   31,025      6.55      36,686

2012

   16,470      6.05      5,921

2013

   5,475      5.99      571
              

Total natural gas

   80,850         108,204
              

Oil:

        

Swaps:

        

Remainder of 2010

   226      114.96      8,465

2011

   548      111.32      17,018

2012

   92      109.30      2,445
              

Total oil

   866         27,928
              

Total oil and natural gas and derivatives

         $ 136,132
            

 

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At December 31, 2009, we had outstanding derivative contracts to mitigate price volatility covering 88,213 Mmcf of natural gas and 995 Mbbls of oil. At June 30, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $76.73 and $79.38, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2010 and for 2011 were $4.85 and $5.34, respectively.

Our derivative financial instruments, used to mitigate price volatility, covered 54.5% and 60.1% for the three and six months ended June 30, 2010, respectively, and 75.2% and 75.0% for the three and six months ended June 30, 2009, respectively, of our total equivalent Mcfe production.

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. The net derivative liability value attributable to our interest rate derivative contracts as of the end of the reporting period are based on (i) the contracted notional amounts, (ii) forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. We classified our interest rate swaps and their related fair value tier as Level 2.

During the six months ended June 30, 2010, we recognized increases of $0.1 million to interest expense on our interest rate swaps. During the three and six months ended June 30, 2009, we recognized increases of $4.6 million and $0.5 million, respectively, to interest expense on our interest rate swaps. There was no impact for the three months ended June 30, 2010, as our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2010.

Fair value of other financial instruments

Our financial instruments include cash and cash equivalents, accounts receivable and payable, current portion of debt and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature.

The estimated fair value of our Senior Notes is $445.0 million with a carrying amount of $446.8 million as of June 30, 2010. The estimated fair value has been calculated based on market quotes.

 

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10. Current and long-term debt

Our total debt is summarized as follows:

 

(in thousands)

   June 30,
2010
   December 31,
2009

EXCO Resources Credit Agreement

   $ 477,500    $ 81,486

EXCO Operating Credit Agreement (1)

     —        666,078

7  1/4% senior notes due January 15, 2011

     444,720      444,720

Unamortized premium on 7  1/4 % senior notes due January 15, 2011

     2,111      3,993
             

Total debt

     924,331      1,196,277

Less current maturities

     446,831      —  
             

Total long-term debt

   $ 477,500    $ 1,196,277
             

 

(1) On April 30, 2010, the EXCO Operating Credit Agreement was consolidated into the EXCO Resources Credit Agreement.

Credit agreements

As of June 30, 2010, we had total debt outstanding aggregating $922.2 million consisting of borrowings under our EXCO Resources Credit Agreement of $477.5 million and $444.7 million of Senior Notes, net of unamortized premiums. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended, has a borrowing base of $1.2 billion. On June 30, 2010, we had $477.5 million of outstanding indebtedness and $707.3 million of available borrowing capacity under the credit agreement. The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries which are jointly held with BG Group. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group. On July 16, 2010, the EXCO Resources Credit Agreement was further amended to allow us to repurchase up to $200.0 million of our common stock (see “Note 15. Subsequent events”).

Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the Engineered Value, as defined in the credit agreement, in our oil and natural gas properties covered by the borrowing base. EXCO is permitted to have derivative financial instruments covering no more than 100% of forecasted production from all Proved Reserves (as defined in the agreement) during the first two years of the forthcoming five year period, 90% of the forecasted production for any month during the third year of the forthcoming five year period and 85% of the forecasted production during the fourth and fifth year of the forthcoming five year period.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the amendment, EXCO may declare and pay cash dividends on its common stock in an amount not to exceed $50.0 million in any four consecutive fiscal quarters, provided that as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) EXCO has at least 10% of its borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under EXCO’s 7  1/ 4 % Senior Notes Indenture.

The interest rate ranges from LIBOR plus 200 basis points, or bps, to LIBOR plus 300 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 100 bps to ABR plus 200 bps depending upon borrowing base usage.

 

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As of June 30, 2010, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:

 

   

maintain a consolidated current ratio (as defined in the agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

 

   

not permit our ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 3.50 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2010.

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

EXCO Operating Credit Agreement

On April 30, 2010, the EXCO Operating Credit Agreement was consolidated into the EXCO Resources Credit Agreement. Terms of the amended and restated agreement include, among other things, EXCO Operating and certain of its subsidiaries becoming guarantor subsidiaries under the EXCO Resources Credit Agreement and our Senior Notes.

7   1 /4% senior notes due January 15, 2011

As of June 30, 2010 and December 31, 2009, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at June 30, 2010 and December 31, 2009 was $2.1 million and $4.0 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $445.0 million on June 30, 2010. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.

 

11. Dividends

On May 21, 2010 our Board of Directors approved a second quarter 2010 cash dividend equal to $0.03 per share. The total cash dividend of $6.4 million was paid on June 15, 2010 to holders of record on June 1, 2010. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources Credit Agreement, our Senior Notes and the approval of EXCO’s Board of Directors.

 

12. Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws. We apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial operating losses primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties. For the three and six months ended June 30, 2010, we utilized $231.7 million and $277.7 million, respectively, of our accumulated valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $400.0 million, as of June 30, 2010, until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowance does not impact future utilization of the underlying tax attributes.

 

13. Operating Segments

We follow FASB ASC Topic 280 for Segment Reporting when reporting operating segments. Prior to the East Texas/North Louisiana Midstream JV where we sold a 50% interest in most of our East Texas/North Louisiana midstream operations, our reportable segments consisted of exploration and production and midstream. Our exploration and production segment and midstream segment were managed

 

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separately because of the nature of their products and services. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment was responsible for purchasing, gathering, transporting, processing and treating natural gas. We evaluated the performance of our operating segments based on segment profits, which included segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and segment costs and expenses. Segment profit generally excluded income taxes, interest income, interest expense, unallocated corporate expenses, depreciation and depletion, asset retirement obligations, and gains and losses associated with ceiling test write-downs and asset sales, other income and expense, and income from equity investments.

As a result of the East Texas/North Louisiana Midstream JV, we reviewed the criteria outlined in ASC 280-10 and determined that the midstream assets we retained, made up exclusively of the Vernon Field midstream assets, were not material and therefore, would no longer meet thresholds to be defined as a reportable segment. We also reviewed our equity investment in TGGT and concluded that it also would not be considered a reportable segment. We now account for our interest in TGGT using the equity method (see “Note 14. Equity investments”).

The reportable midstream segment for 2009 is effective from January 1, 2009 through August 13, 2009. The Vernon Field midstream assets operations are included in the exploration and production segment effective August 14, 2009.

 

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Summarized financial information concerning our reportable segments is shown in the following table:

 

(in thousands)

   Exploration and
production
    Midstream    Intercompany
eliminations
    Consolidated
total

For the three months ended June 30, 2010:

         

Third party revenues

   $ 118,344      $ —      $ —        $ 118,344

Intersegment revenues

     —          —        —          —  
                             

Total revenues

   $ 118,344      $ —      $ —        $ 118,344
                             

Segment profit

   $ 74,447      $ —      $ —        $ 74,447
                             

For the three months ended June 30, 2009:

         

Third party revenues

   $ 146,252      $ 12,942    $ —        $ 159,194

Intersegment revenues

     (8,050     16,676      (8,626     —  
                             

Total revenues

   $ 138,202      $ 29,618    $ (8,626   $ 159,194
                             

Segment profit

   $ 85,753      $ 9,273    $ —        $ 95,026
                             

For the six months ended June 30, 2010:

         

Third party revenues

   $ 249,338      $ —      $ —        $ 249,338

Intersegment revenues

     —          —        —          —  
                             

Total revenues

   $ 249,338      $ —      $ —        $ 249,338
                             

Segment profit

   $ 167,270      $ —      $ —        $ 167,270
                             

For the six months ended June 30, 2009:

         

Third party revenues

   $ 318,460      $ 29,955    $ —        $ 348,415

Intersegment revenues

     (16,032     32,252      (16,220     —  
                             

Total revenues

   $ 302,428      $ 62,207    $ (16,220   $ 348,415
                             

Segment profit

   $ 192,964      $ 15,818    $ —        $ 208,782
                             

As of June 30, 2010:

         

Capital Expenditures

   $ 270,103      $ —      $ —        $ 270,103
                             

Goodwill

   $ 218,256      $ —      $ —        $ 218,256
                             

Total assets

   $ 2,753,901      $ —      $ —        $ 2,753,901
                             

As of December 31, 2009:

         

Capital Expenditures

   $ 458,410      $ 53,122    $ —        $ 511,532
                             

Goodwill

   $ 269,656      $ —      $ —        $ 269,656
                             

Total assets

   $ 2,358,894      $ —      $ —        $ 2,358,894
                             

 

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The following table reconciles the segment profits reported above to income (loss) before income taxes:

 

     Three months ended
June 30,
    Six months ended
June 30,
 

(in thousands)

   2010     2009     2010     2009  

Segment profits

   $ 74,447      $ 95,026      $ 167,270      $ 208,782   

Depreciation, depletion and amortization

     (45,339     (55,180     (84,157     (136,974

Write-down of oil and natural gas properties

     —          —          —          (1,293,579

Gain on divestitures and other operating items

     574,946        (8,382     575,353        (7,977

Accretion of discount on asset retirement obligations

     (1,001     (2,018     (2,090     (4,089

General and administrative

     (25,866     (22,488     (52,285     (43,035

Interest expense

     (14,476     (46,891     (25,110     (83,023

Gain (loss) on derivative financial instruments

     707        (31,017     99,856        190,367   

Other income

     57        13        117        35   

Equity income

     5,290        —          5,379        —     
                                

Income (loss) before income taxes

   $ 568,765      $ (70,937   $ 684,333      $ (1,169,493
                                

 

14. Equity investments

In conjunction with the Appalachia JV that closed on June 1, 2010, we own a 50% interest in OPCO, which will operate the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. Our investment in OPCO is equal to the working capital and historical costs of assets we retained in OPCO, less the 50% interest we sold to BG Group upon closing the Appalachia JV. Our equity investment in OPCO exceeds our book value of assets by $4.1 million representing the difference in the historical basis of our investment and the 50% interest in the fair value of BG Group’s purchase. The $4.1 million basis difference is being amortized over the estimated amortized life of OPCO’s unproved properties.

In addition, certain midstream assets owned by EXCO were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which EXCO and BG Group will pursue the construction and expansion of gathering systems for anticipated future production from the Marcellus Shale. Our investment in Appalachia Midstream, LLC is equal to the assets we contributed, less the 50% interest we sold to BG Group upon closing the Appalachia JV.

Along with our 50% ownership interest in TGGT, we account for these investments under the equity method. The following tables present summarized consolidated financial information of our equity investments and a reconciliation of our investment to our proportionate 50% interest.

 

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(in thousands)

   June 30, 2010

Assets

  

Total current assets

   $ 151,387

Property and equipment, net

     669,370

Other assets

     848
      

Total assets

   $ 821,605
      

Liabilities and members’ equity

  

Total current liabilities

   $ 143,003

Total long term liabilities

     8,791

Members’ equity:

  

Total members’ equity

     669,811
      

Total liabilities and members’ equity

   $ 821,605
      

 

     Three months ended
June 30, 2010
   Six months ended
June 30, 2010

Revenues

     

Oil and natural gas

   $ 25    $ 25

Midstream

     43,568      75,352
             

Total revenues

     43,593      75,377
             

Costs and expenses:

     

Oil and natural gas production

     42      42

Midstream operating

     25,161      50,884

Other expenses

     3,879      7,578

Depreciation, depletion and amortization

     4,758      7,680
             

Total costs and expenses

     33,840      66,184
             

Income before income taxes

     9,753      9,193

Income tax expense

     92      159
             

Net income

   $ 9,661    $ 9,034
             

EXCO’s share of equity income before amortization

   $ 4,831    $ 4,517

Amortization of the difference in the historical basis of our contribution

     459      862
             

EXCO’s share of equity income after amortization

   $ 5,290    $ 5,379
             

 

(in thousands)

   June 30, 2010  

Equity investments

   $ 288,143   

Basis adjustment (1)

     48,242   

Cumulative amortization of basis adjustment (2)

     (1,479
        

EXCO’s 50% interest in June 30, 2010 equity investments

   $ 334,906   
        

 

(1) Our equity investments in TGGT and OPCO exceed our book value of assets by $48.2 million represented by $59.6 million difference in the historical basis of our contribution and the fair value of BG Group’s contribution offset by $11.4 million of goodwill included in our investment in TGGT.
(2) The $59.6 million basis difference is being amortized over the estimated life of associated assets.

 

15. Subsequent events

On July 19, 2010, we announced a share repurchase program which authorizes us to purchase up to $200.0 million of our common stock. Any repurchases will be made in the open market, in privately negotiated transactions or in structured share repurchase programs, and may be made from time to time and

 

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in one or more larger repurchases. The program will be conducted in compliance with the Securities and Exchange Commission’s Rule 10b-18 and applicable legal requirements and shall be subject to market conditions and other factors.

EXCO is not obligated to repurchase any common stock, or any particular amount of common stock, and the repurchase program may be modified or suspended at any time at EXCO’s discretion. The repurchases may be funded from available cash or borrowings under our credit agreement.

 

16. Condensed consolidating financial statements

On April 30, 2010, when the EXCO Operating credit agreement was consolidated into the EXCO Resources Credit Agreement, certain non-guarantor subsidiaries, including EXCO Operating, which owns all of our East Texas/North Louisiana assets, became guarantor subsidiaries under our Senior Notes. The accompanying condensed consolidating financial statements are presented as if the previous non-guarantor subsidiaries were guarantor subsidiaries for each of the periods presented. As of June 30, 2010, the non-guarantor subsidiaries consist primarily of TGGT, OPCO and certain oil and natural gas properties which are pending transfer to EXCO. Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The Senior Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some of our subsidiaries (referred to as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources (defined below), and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish us from the Guarantor Subsidiaries.

The following financial information presents consolidating financial statements, which include:

 

   

Resources;

 

   

the Guarantor Subsidiaries on a combined basis;

 

   

the Non-Guarantor Subsidiaries;

 

   

elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and

 

   

EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

June 30, 2010

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations     Consolidated  

Assets

          

Current assets:

          

Cash and cash equivalents

   $ 4,278      $ 93,509      $ 240      $ —        $ 98,027   

Restricted cash

     —          75,246        —          —          75,246   

Other current assets

     61,903        259,604        4,028        —          325,535   
                                        

Total current assets

     66,181        428,359        4,268        —          498,808   
                                        

Equity Investment

     —          —          288,143        —          288,143   

Oil and natural gas properties (full cost accounting method):

          

Unproved oil and natural gas properties

     44,285        341,048        236,961        —          622,294   

Proved developed and undeveloped oil and natural gas properties

     358,122        1,706,441        50,427        —          2,114,990   

Accumulated depletion

     (285,029     (921,470     (1,246     —          (1,207,745
                                        

Oil and natural gas properties, net

     117,378        1,126,019        286,142        —          1,529,539   
                                        

Gas gathering, office and field equipment, net

     9,610        134,774        4,869        —          149,253   

Investments in and advances to affiliates

     962,057        —          —          (962,057     —     

Deferred financing costs, net

     18,756        —          —          —          18,756   

Derivative financial instruments

     29,521        10,391        —          —          39,912   

Goodwill

     38,100        180,156        —          —          218,256   

Other assets

     3        11,231        —          —          11,234   
                                        

Total assets

   $ 1,241,606      $ 1,890,930      $ 583,422      $ (962,057   $ 2,753,901   
                                        

Liabilities and shareholders’ equity

          

Current liabilities

   $ 491,464      $ 170,058      $ 2,421      $ —        $ 663,943   

Long-term debt

     477,500        —          —          —          477,500   

Deferred income taxes

     —          —          —          —          —     

Other liabilities

     10,806        55,116        53        —          65,975   

Payable to parent

     (1,284,647     1,267,079        17,568        —          —     

Total shareholders’ equity

     1,546,483        398,677        563,380        (962,057     1,546,483   
                                        

Total liabilities and shareholders’ equity

   $ 1,241,606      $ 1,890,930      $ 583,422      $ (962,057   $ 2,753,901   
                                        

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
   Eliminations     Consolidated  

Assets

           

Current assets:

           

Cash and cash equivalents

   $ 47,412      $ 20,995      $ —      $ —        $ 68,407   

Restricted cash

     —          58,909        —        —          58,909   

Other current assets

     69,449        204,880        443      —          274,772   
                                       

Total current assets

     116,861        284,784        443      —          402,088   
                                       

Equity investment in TGGT Holdings, LLC

     —          —          216,987      —          216,987   

Oil and natural gas properties (full cost accounting method):

           

Unproved oil and natural gas properties

     54,570        394,313        43,999      —          492,882   

Proved developed and undeveloped oil and natural gas properties

     328,135        1,539,252        8,362      —          1,875,749   

Accumulated depletion

     (274,275     (858,329     —        —          (1,132,604
                                       

Oil and natural gas properties, net

     108,430        1,075,236        52,361      —          1,236,027   
                                       

Gas gathering, office and field equipment, net

     8,175        181,261        —        —          189,436   

Investments in and advances to affiliates

     198,661        —          —        (198,661     —     

Deferred financing costs, net

     3,166        4,436        —        —          7,602   

Derivative financial instruments

     31,312        3,365        —        —          34,677   

Goodwill

     38,100        231,556        —        —          269,656   

Other assets

     3        2,418        —        —          2,421   
                                       

Total assets

   $ 504,708      $ 1,783,056      $ 269,791    $ (198,661   $ 2,358,894   
                                       

Liabilities and shareholders’ equity

           

Current liabilities

   $ 39,917      $ 172,795      $ 202    $ —        $ 212,914   

Long-term debt

     530,199        666,078        —        —          1,196,277   

Deferred income taxes

     —          —          —        —          —     

Other liabilities

     5,998        84,117        —        —          90,115   

Payable to parent

     (930,994     930,994        —        —          —     

Total shareholders’ equity

     859,588        (70,928     269,589      (198,661     859,588   
                                       

Total liabilities and shareholders’ equity

   $ 504,708      $ 1,783,056      $ 269,791    $ (198,661   $ 2,358,894   
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2010

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
   Eliminations     Consolidated  

Revenues:

           

Oil and natural gas

   $ 16,077      $ 99,220      $ 3,047    $ —        $ 118,344   
                                       

Costs and expenses:

           

Oil and natural gas production

     3,895        26,716        413      —          31,024   

Gathering and transportation

     —          12,699        174      —          12,873   

Depreciation, depletion and amortization

     5,697        38,624        1,018      —          45,339   

Accretion of discount on asset retirement obligations

     85        915        1      —          1,001   

General and administrative

     6,612        19,254        —        —          25,866   

Gain on divestitures and other operating items

     2,766        (577,712     —        —          (574,946
                                       

Total costs and expenses

     19,055        (479,504     1,606      —          (458,843
                                       

Operating income (loss)

     (2,978     578,724        1,441      —          577,187   

Other income (expense):

           

Interest expense

     (11,301     (3,175     —        —          (14,476

Gain (loss) on derivative financial instruments

     3,088        (2,381     —        —          707   

Other income (expense)

     4,155        (4,098     —        —          57   

Equity method income

     —          —          5,290      —          5,290   

Equity in earnings of subsidiaries

     575,801        —          —        (575,801     —     
                                       

Total other income (expense)

     571,743        (9,654     5,290      (575,801     (8,422
                                       

Income (loss) before income taxes

     568,765        569,070        6,731      (575,801     568,765   

Income tax expense

     4,452        —          —        —          4,452   
                                       

Net income (loss)

   $ 564,313      $ 569,070      $ 6,731    $ (575,801   $ 564,313   
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
   Eliminations    Consolidated  

Revenues:

            

Oil and natural gas

   $ 41,543      $ 104,709      $ —      $ —      $ 146,252   

Midstream

     —          12,942        —        —        12,942   
                                      

Total revenues

     41,543        117,651        —        —        159,194   
                                      

Costs and expenses:

            

Oil and natural gas production

     13,169        35,225        —        —        48,394   

Midstream operating

     —          11,719        —        —        11,719   

Gathering and transportation

     35        4,020        —        —        4,055   

Depreciation, depletion and amortization

     12,073        43,107        —        —        55,180   

Accretion of discount on asset retirement obligations

     505        1,513        —        —        2,018   

General and administrative

     3,886        18,602        —        —        22,488   

Other operating items

     (467     8,849        —        —        8,382   
                                      

Total costs and expenses

     29,201        123,035        —        —        152,236   
                                      

Operating income (loss)

     12,342        (5,384     —        —        6,958   

Other income (expense):

            

Interest expense

     (17,194     (29,697     —        —        (46,891

Gain (loss) on derivative financial instruments

     (35,214     4,197        —        —        (31,017

Other income (expense)

     6,211        (6,198     —        —        13   

Equity method income

     —          —          —        —        —     

Equity in earnings of subsidiaries

     (37,082     —          —        37,082      —     
                                      

Total other income (expense)

     (83,279     (31,698     —        37,082      (77,895
                                      

Income (loss) before income taxes

     (70,937     (37,082     —        37,082      (70,937

Income tax expense

     1,055        —          —        —        1,055   
                                      

Net income (loss)

   $ (71,992   $ (37,082   $ —      $ 37,082    $ (71,992
                                      

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2010

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
   Eliminations     Consolidated  

Revenues:

           

Oil and natural gas

   $ 33,722      $ 211,888      $ 3,728    $ —        $ 249,338   
                                       

Costs and expenses:

           

Oil and natural gas production

     7,851        49,870        361      —          58,082   

Gathering and transportation

     —          23,694        292      —          23,986   

Depreciation, depletion and amortization

     12,847        70,064        1,246      —          84,157   

Accretion of discount on asset retirement obligations

     168        1,921        1      —          2,090   

General and administrative

     14,257        38,028        —        —          52,285   

Gain on divestitures and other operating items

     2,164        (577,517     —        —          (575,353
                                       

Total costs and expenses

     37,287        (393,940     1,900      —          (354,753
                                       

Operating income (loss)

     (3,565     605,828        1,828      —          604,091   

Other income (expense):

           

Interest expense

     (18,375     (6,735     —        —          (25,110

Gain on derivative financial instruments

     33,942        65,914        —        —          99,856   

Other income (expense)

     10,329        (10,212     —        —          117   

Equity method income

     —          —          5,379      —          5,379   

Equity in earnings of subsidiaries

     662,002        —          —        (662,002     —     
                                       

Total other income (expense)

     687,898        48,967        5,379      (662,002     80,242   
                                       

Income (loss) before income taxes

     684,333        654,795        7,207      (662,002     684,333   

Income tax expense

     4,452        —          —        —          4,452   
                                       

Net income (loss)

   $ 679,881      $ 654,795      $ 7,207    $ (662,002   $ 679,881   
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
   Eliminations    Consolidated  

Revenues:

            

Oil and natural gas

   $ 79,625      $ 238,835      $ —      $ —      $ 318,460   

Midstream

       29,955        —           29,955   
                                      

Total revenues

     79,625        268,790        —        —        348,415   
                                      

Costs and expenses:

            

Oil and natural gas production

     27,375        74,137        —        —        101,512   

Midstream operating

     —          30,169        —        —        30,169   

Gathering and transportation

     87        7,865        —        —        7,952   

Depreciation, depletion and amortization

     30,963        106,011        —        —        136,974   

Write-down of oil and natural gas properties

     279,632        1,013,947        —           1,293,579   

Accretion of discount on asset retirement obligations

     1,022        3,067        —        —        4,089   

General and administrative

     5,714        37,321        —        —        43,035   

Other operating items

     (770     8,747        —        —        7,977   
                                      

Total costs and expenses

     344,023        1,281,264        —        —        1,625,287   
                                      

Operating income (loss)

     (264,398     (1,012,474     —        —        (1,276,872

Other income (expense):

            

Interest expense

     (28,136     (54,887     —        —        (83,023

Gain on derivative financial instruments

     71,006        119,361        —        —        190,367   

Other income (expense)

     12,398        (12,363     —        —        35   

Equity method income

     —          —          —        —        —     

Equity in earnings of subsidiaries

     (960,363     —          —        960,363      —     
                                      

Total other income (expense)

     (905,095     52,111        —        960,363      107,379   
                                      

Income (loss) before income taxes

     (1,169,493     (960,363     —        960,363      (1,169,493

Income tax expense

     2,110                2,110   
                                      

Net income (loss)

   $ (1,171,603   $ (960,363   $ —      $ 960,363    $ (1,171,603
                                      

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2010

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations    Consolidated  

Operating Activities:

           

Net cash provided by operating activities

   $ 58,315      $ 135,348      $ (11,810     —      $ 181,853   
                                       

Investing Activities:

           

Additions to oil and natural gas properties, gathering systems and equipment

     (19,885     (478,113     (203,745     —        (701,743

Restricted cash

     —          (16,337     —          —        (16,337

Investment in equity investments

     —          (68,500     —          —        (68,500

Proceeds from dispositions

     11,348        944,948        —          —        956,296   

Advances to Appalachia JV

     —          (30,448     —          —        (30,448

Advances/investments with affiliates

     223,570        (439,365     215,795        —        —     
                                       

Net cash provided by (used in) investing activities

     215,033        (87,815     12,050        —        139,268   
                                       

Financing Activities:

           

Borrowings under credit agreements

     1,302,437        49,962        —          —        1,352,399   

Repayments under credit agreements

     (1,597,482     (24,981     —          —        (1,622,463

Proceeds from issuance of common stock, net

     9,091        —          —          —        9,091   

Payment of common stock dividends

     (12,740     —          —          —        (12,740

Settlement of derivative financial instruments with a financing element

     (907     —          —          —        (907

Deferred financing costs and other

     (16,881     —          —          —        (16,881
                                       

Net cash provided by (used in) financing activities

     (316,482     24,981        —          —        (291,501
                                       

Net increase (decrease) in cash

     (43,134     72,514        240        —        29,620   

Cash at beginning of period

     47,412        20,995        —          —        68,407   
                                       

Cash at end of period

   $ 4,278      $ 93,509      $ 240      $ —      $ 98,027   
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
   Eliminations    Consolidated  

Operating Activities:

            

Net cash provided by operating activities

   $ 121,583      $ 105,350      $ —      $ —      $ 226,933   
                                      

Investing Activities:

            

Additions to oil and natural gas properties, gathering systems and equipment

     (34,436     (295,932     —        —        (330,368

Restricted Cash

     (21,000     (16,500     —        —        (37,500

Deposits on pending property divestitures

     41,188        16,500        —        —        57,688   

Proceeds from dispositions of property and equipment

     35,733        20,050        —        —        55,783   

Advances/investments with affiliates

     (53,187     53,187        —        —        —     
                                      

Net cash used in investing activities

     (31,702     (222,695     —        —        (254,397
                                      

Financing Activities:

            

Borrowings under credit agreements

     14,979        37,970        —        —        52,949   

Repayments under credit agreements

     (17,500     (5,240     —        —        (22,740

Settlement of derivative financial instruments with a financing element

     31,082        59,212        —        —        90,294   

Proceeds from issuance of common stock, net

     1,648        —          —        —        1,648   

Deferred financing costs and other

     (5,386     (15,082     —        —        (20,468
                                      

Net cash provided by financing activities

     24,823        76,860        —        —        101,683   
                                      

Net increase (decrease) in cash

     114,704        (40,485     —        —        74,219   

Cash at beginning of period

     8,618        48,521        —        —        57,139   
                                      

Cash at end of period

   $ 123,322      $ 8,036      $ —      $ —      $ 131,358   
                                      

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context requires otherwise, references to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

Forward-looking statements

This quarterly report contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

 

   

our future financial and operating performance and results;

 

   

our business strategy;

 

   

market prices;

 

   

our future derivative financial instrument activities; and

 

   

our plans and forecasts.

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

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

 

   

fluctuations in prices of oil and natural gas;

 

   

imports of foreign oil and natural gas, including liquefied natural gas;

 

   

future capital requirements and availability of financing;

 

   

continued disruption of credit and capital markets and the ability of financial institutions to honor their commitments;

 

   

estimates of reserves and economic assumptions;

 

   

geological concentration of our reserves;

 

   

risks associated with drilling and operating wells;

 

   

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

 

   

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

 

   

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

 

   

cash flow and liquidity;

 

   

timing and amount of future production of oil and natural gas;

 

   

availability of drilling and production equipment;

 

   

marketing of oil and natural gas;

 

   

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

 

   

title to our properties;

 

   

litigation;

 

   

competition;

 

   

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

 

   

environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments and elimination of income tax incentives available to our industry;

 

   

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

 

   

decisions whether or not to enter into derivative financial instruments;

 

   

potential acts of terrorism;

 

   

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

 

   

fluctuations in interest rates; and

 

   

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

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

 

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Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas, the availability of capital from our credit agreement and liquidity from capital markets. Declines in oil or natural gas prices may have a material adverse affect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in 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.

Our primary strategy is to develop and exploit our Haynesville, Bossier and Marcellus shale resources and leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. Funds generated from our mature, low-cost fields are used as a source of cash flows to drill and develop our shale resources. We also continue to pursue acquisitions with shale potential.

In 2009 and 2010, we entered into joint venture agreements with affiliates of BG Group plc, or BG Group, in East Texas/North Louisiana, or the East Texas/North Louisiana JV, and Appalachia, or the Appalachia JV, which provided us with substantial liquidity to reduce our outstanding debt. These joint ventures provide a total of $550.0 million of carried drilling costs in our favor, which allows us to accelerate drilling activities in our shale plays at a smaller initial cash outlay until the drilling carry is exhausted.

In addition to the Appalachia JV, we recently acquired approximately 26,000 net acres in the Haynesville and Bossier shales, including approximately 23,800 acres in the Shelby Trough, which has allowed us to establish a second major focus area within the Haynesville and Bossier shale plays outside of our core DeSoto Parish position.

We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays in our joint ventures, exploiting our multi-year inventory of development drilling locations and accumulating undeveloped acreage in shale areas.

We intend to exploit these shales primarily through horizontal drilling. Future acquisitions are likely to be focused on supplementing these shale resource holdings in the East Texas/North Louisiana and Appalachian areas. We will continue to develop certain vertical drilling opportunities in our East Texas/North Louisiana, Appalachia and Permian areas as industry economic conditions permit.

Our credit agreement, as amended on April 30, 2010, or the EXCO Resources Credit Agreement, has a borrowing base of $1.2 billion, of which $497.5 million was drawn as of July 29, 2010. Available borrowing capacity was $687.3 million as of July 29, 2010. We also have $444.7 million of 7 1/4% senior notes due January 15, 2011, or the Senior Notes.

For the three months ended June 30, 2010, we produced 26.5 Bcfe of oil and natural gas, with June 2010 daily production of 299 Mmcfe. Of the amount produced, 22.0 Bcfe were produced in our East Texas/North Louisiana division, 2.7 Bcfe were produced in our Appalachia division and 1.8 Bcfe were produced in our Permian division.

For the six months ended June 30, 2010, we produced 50.3 Bcfe of oil and natural gas. Of the amount produced, 40.8 Bcfe were produced in our East Texas/North Louisiana division, 6.0 Bcfe were produced in our Appalachia division and 3.5 Bcfe were produced in our Permian division.

Our plans for 2010 are focused on the Haynesville, Bossier and Marcellus shales. Our net budgeted capital expenditures for 2010, which include equity contributions to TGGT and acreage reimbursements from BG Group totals $546.8 million. Our East Texas/North Louisiana capital expenditures are favorably impacted by our joint development agreement with BG Group, which includes a $400.0 million carry equal to 75% of our share of drilling and completion costs within our joint venture area until the carry amount is satisfied, or the East Texas/North Louisiana Carry. During the first half of 2010, we spent $158.5 million in East Texas/North Louisiana, $123.9 million of which was in the area of mutual interest with BG Group, or the BG AMI. As of June 30, 2010, the remaining balance of the East Texas/North Louisiana Carry was approximately $237.8 million. In Appalachia we spent $75.0 million during the first half of 2010 and our remaining planned capital expenditures are expected to total $44.4 million. Similar to East Texas/North Louisiana, our Appalachia capital expenditures will be favorably impacted by the Appalachia JV, which included a $150.0 million carry equal to approximately 75% of our share of deep drilling and completion costs within our joint venture area until the carry amount is satisfied, or the Appalachia Carry. As of June 30, 2010, none of the Appalachia Carry had been utilized.

 

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For the three and six months ended June 30, 2010, we made $24.0 million and $68.5 million, respectively, in equity contributions to our East Texas/North Louisiana midstream joint venture, or TGGT. Our remaining 2010 capital budget includes $6.5 million in equity contributions to TGGT. The management of TGGT is also evaluating several expansion projects which, if approved, will require additional capital contributions.

Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to identify and develop additional reserves and add additional reserves through acquisitions.

Critical accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, proved reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009.

Recent accounting pronouncements

On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” in Notes to Condensed Consolidated Financial Statements for the impact to our disclosures.

 

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Our results of operations

A summary of key financial data for the three and six months ended June 30, 2010 and 2009 related to our results of operations is presented below:

 

     Three months ended
June 30,
    Quarter to
quarter change
    Six months ended
June 30,
    Period to period
change
 

(dollars in thousands, except per unit prices)

   2010     2009     2010-2009     2010     2009     2010-2009  

Production:

            

Oil (Mbbls)

     168        485        (317     327        1,012        (685

Natural gas (Mmcf)

     25,539        33,608        (8,069     48,376        66,792        (18,416

Total production (Mmcfe) (1)

     26,547        36,518        (9,971     50,338        72,864        (22,526

Oil and natural gas revenues before derivative financial instrument activities:

            

Oil

   $ 12,506      $ 27,197      $ (14,691   $ 24,469      $ 46,893      $ (22,424

Natural gas

     105,838        119,055        (13,217     224,869        271,567        (46,698
                                                

Total oil and natural gas

   $ 118,344      $ 146,252      $ (27,908   $ 249,338      $ 318,460      $ (69,122
                                                

Oil and natural gas derivative financial instruments:

            

Cash settlements (payments) on derivative financial instruments

   $ 46,538      $ 142,139      $ (95,601   $ 123,585      $ 240,568      $ (116,983

Non-cash change in fair value of derivative financial instruments

     (45,831     (173,156     127,325        (23,729     (50,201     26,472   
                                                

Total derivative financial instrument activities

   $ 707      $ (31,017   $ 31,724      $ 99,856      $ 190,367      $ (90,511
                                                

Average sales price (before cash settlements of derivative financial instruments):

            

Oil (per Bbl)

   $ 74.44      $ 56.08      $ 18.36      $ 74.83      $ 46.34      $ 28.49   

Natural gas (per Mcf)

     4.14        3.54        0.60        4.65        4.07        0.58   

Natural gas equivalent (per Mcfe)

     4.46        4.00        0.46        4.95        4.37        0.58   

Costs and expenses:

            

Oil and natural gas operating costs (2)

   $ 22,503      $ 39,032      $ (16,529   $ 41,696      $ 79,718      $ (38,022

Production and ad valorem taxes

     8,521        9,362        (841     16,386        21,794        (5,408

Gathering and transportation

     12,873        4,055        8,818        23,986        7,952        16,034   

Depletion

     41,122        48,093        (6,971     75,142        123,077        (47,935

Depreciation and amortization

     4,217        7,087        (2,870     9,015        13,897        (4,882

General and administrative (3)

     25,866        22,488        3,378        52,285        43,035        9,250   

Interest expense, net, including impacts of interest rate swaps

     14,476        46,891        (32,415     25,110        83,023        (57,913

Costs and expenses (per Mcfe):

            

Oil and natural gas operating costs

   $ 0.85      $ 1.07      $ (0.22   $ 0.83      $ 1.09      $ (0.26

Production and ad valorem taxes

     0.32        0.26        0.06        0.33        0.30        0.03   

Gathering and transportation

     0.48        0.11        0.37        0.48        0.11        0.37   

Depletion

     1.55        1.32        0.23        1.49        1.69        (0.20

Depreciation and amortization

     0.16        0.19        (0.03     0.18        0.19        (0.01

General and administrative

     0.97        0.62        0.35        1.04        0.59        0.45   

Net income (loss)

   $ 564,313      $ (71,992   $ 636,305      $ 679,881      $ (1,171,603   $ 1,851,484   

 

(1) Mmcfe is calculated by converting one barrel of oil into six Mcf of natural gas.
(2) Share-based compensation included in oil and natural gas operating costs is $0.2 million, $0.6 million, $0.7 million and $1.4 million for the three and six months ended June 30, 2010 and 2009, respectively.
(3) Share-based compensation included in general and administrative expenses are $3.6 million, $7.9 million, $2.6 million and $5.1 million for the three and six months ended June 30, 2010 and 2009, respectively.

The following is a discussion of our financial condition and results of operations for the three and six months ended June 30, 2010 and 2009.

The comparability of our results of operations from period to period is impacted by:

 

   

the East Texas/North Louisiana JV;

 

   

2009 divestitures;

 

   

fluctuations in oil and natural gas prices, which impact our oil and natural gas reserves, revenues and net income or loss;

 

   

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

 

   

changes in Proved Reserves and production volumes, including the impact of SEC Release No., 33-8995 effective December 31, 2009, and their impact on depletion;

 

   

a ceiling test write-down in the first quarter of 2009; and

 

   

the equity method of accounting for our investment in TGGT.

The Appalachia JV closed on June 1, 2010. Future comparability of our results of operations will be impacted by this transaction.

 

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General

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

 

   

the level of domestic production and economic activity, particularly the recent worldwide economic slowdown which continues to put downward pressure on natural gas prices and demand;

 

   

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

 

   

the availability of imported oil and natural gas;

 

   

actions taken by foreign oil producing nations;

 

   

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

 

   

the cost and availability of other competitive fuels;

 

   

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

 

   

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

 

   

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

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.

Marketing arrangements

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

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

We may be unable to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

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

 

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Summary

For the three months ended June 30, 2010, we reported net income of $564.3 million, compared to a net loss of $72.0 million for the three months ended June 30, 2009. For the six months ended June 30, 2010, we reported net income of $679.9 million, compared to a net loss of $1.172 billion for the six months ended June 30, 2009.

During 2009 we completed a divestiture program to sell certain non-strategic properties and also entered into the East Texas/North Louisiana JV and TGGT. Proceeds from the 2009 divestitures and joint venture transactions, along with the non-strategic asset sales, were approximately $2.1 billion, resulting in decreases in our full cost pool, gathering assets, operating assets and liabilities, and gains totaling approximately $691.9 million. In addition, 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 for approximately $835.2 million, subject to final closing adjustments, plus a $150.0 million deep drilling carry. As a result, when comparing the first half and second quarter of 2010 to the first half and second quarter of 2009, these transactions result in significant declines in our production of oil and natural gas revenues and operating costs. These divestitures will impact comparability of our 2010 and 2009 results of operations throughout 2010. Accordingly, we are presenting certain pro forma comparisons to facilitate understanding of operating data.

Upon closing TGGT, we adopted the equity method of accounting for our investment in TGGT and discontinued reporting our midstream operations as a separate business segment. Results of operations from our Vernon gathering system, which was not part of TGGT, are now recorded net in “Gathering and transportation” on our Condensed Consolidated Statement of Operations.

Offsetting declines in 2010 production and revenues arising from 2009 divestitures is a $575.0 million gain associated with the Appalachia JV, along with a $9.9 million quarterly reduction and $52.8 million year-to-date reduction in our depletion and depreciation expense. During the first quarter of 2009, we recorded a $1.3 billion non-cash ceiling test write-down, which significantly impacted 2009’s net income.

Derivative financial instruments, which we use to mitigate price volatility, also have a significant impact on our results of operations since we do not designate our derivative financial instruments as hedges and are required to mark the non-cash changes in the fair value of our derivatives to market at the end of each reporting period.

Oil and natural gas production, revenues, and prices

Total equivalent production volumes were 26.5 Bcfe for the three months ended June 30, 2010, a 27.3% decrease from the prior year’s comparable period production of 36.5 Bcfe, and 50.3 Bcfe for the six months ended June 30, 2010, a 30.9% decrease from the prior year’s comparable period production of 72.9 Bcfe. While these declines are a result of the 2009 divestitures, the East Texas/North Louisiana JV and the Appalachia JV, as discussed above, management believes that analyzing the production on a pro forma basis, assuming the divestitures and joint venture transactions had occurred on January 1, 2009, provides a more meaningful analysis of the on-going production activity.

 

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Table of Contents
     Three months ended June 30,       
     2010    2009    Quarter to quarter change  

(in Mmcfe)

   Actual
production
   Pro forma
adjustment (1)
    Pro forma
production
   Actual
production
   Pro forma
adjustment (2)
    Pro forma
production
   Actual
production
    Pro forma
production
 

Producing region:

                    

East Texas/North Louisiana

   22,097    —        22,097    23,341    (7,973   15,368    (1,244   6,729   

Appalachia

   2,669    (1,085   1,584    5,025    (3,244   1,781    (2,356   (197

Permian and other

   1,781    —        1,781    2,402    (388   2,014    (621   (233

Mid-Continent

   —      —        —      5,750    (5,750   —      (5,750   —     
                                            

Total

   26,547    (1,085   25,462    36,518    (17,355   19,163    (9,971   6,299   
                                            
     Six months ended June 30,       
     2010    2009    Period to period change  

(in Mmcfe)

   Actual
production
   Pro forma
adjustment (1)
    Pro forma
production
   Actual
production
   Pro forma
adjustment (2)
    Pro forma
production
   Actual
production
    Pro forma
production
 

Producing region:

                    

East Texas/North Louisiana

   40,850    —        40,850    45,957    (15,219   30,738    (5,107   10,112   

Appalachia

   6,010    (2,707   3,303    10,150    (6,544   3,606    (4,140   (303

Permian and other

   3,478    —        3,478    5,255    (888   4,367    (1,777   (889

Mid-Continent

   —      —        —      11,502    (11,502   —      (11,502   —     
                                            

Total

   50,338    (2,707   47,631    72,864    (34,153   38,711    (22,526   8,918   
                                            

 

(1) The pro forma adjustments reduce production volumes attributable to the properties affected by the Appalachia JV as if the sale had occurred on January 1, 2010.
(2) The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by both the East Texas/North Louisiana JV and the Appalachia JV as if these sales had occurred on January 1, 2009.

On a pro forma basis, production in our East Texas/North Louisiana region for the three and six months ended June 30, 2010 increased by 6.7 Bcfe and 10.1 Bcfe, or 43.8% and 32.9%, respectively, from the same periods in the prior year. These increases were a result of the continued successful development of our Haynesville shale, which resulted in a production increase of 9.7 Bcfe for the three months ended June 30, 2010 and production increases of 17.5 Bcfe for the six months ended June 30, 2010, when compared to the same period in the prior year. These increases were offset by production declines of 0.8 Bcfe in our Cotton Valley area and 2.2 Bcfe in our Vernon Field for the three months ended June 30, 2010 and declines of 2.2 Bcfe in our Cotton Valley area and 5.2 Bcfe in our Vernon Field for the six months ended June 30, 2010, when compared to the same period in the prior year. These declines are primarily the result of the suspension of vertical drilling operations in 2009 and normal production declines. The Appalachia and Permian divisions also experienced production declines due primarily to suspension of certain drilling programs in both areas during 2009. Our Mid-Continent division was sold during 2009.

The following table presents our revenues, production and prices by major producing areas, based on historical data, for the three and six months ended June 30, 2010 and 2009:

 

<
     Three months ended June 30,                   
     2010    2009    Quarter to quarter change  

(in thousands, except per unit rate)

   Production
(Mcfe)
   Revenue    $/Mcfe    Production
(Mcfe)
   Revenue    $/Mcfe    Production
(Mcfe)
    Revenue     $/Mcfe  

Producing region:

                        

East Texas/North Louisiana

   22,097    $ 90,354    $ 4.09    23,341    $ 82,778    $ 3.55    (1,244   $ 7,576      $ 0.54   

Appalachia

   2,669      11,912      4.46    5,025      21,930      4.36    (2,356     (10,018     0.10   

Permian and other

   1,781      16,078      9.03    2,402      15,185      6.32    (621     893        2.71   

Mid-Continent

   —        —        —      5,750      26,359      4.58    (5,750     (26,359     (4.58
                                              

Total

   26,547    $ 118,344      4.46    36,518    $ 146,252      4.00    (9,971   $ (27,908     0.46   
                                              
     Six months ended June 30,                   
     2010    2009    Year to year change  

(in thousands, except per unit rate)

   Production
(Mcfe)
   Revenue    $/Mcfe    Production
(Mcfe)
   Revenue    $/Mcfe    Production
(Mcfe)
    Revenue     $/Mcfe  

Producing region: