Attached files

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EX-32.1 - CERTIFICATION OF CEO AND CFO PURSUANT TO SECTION 906 - EXCO RESOURCES INCdex321.htm
EX-2.10 - PURCHASE AND SALE AGREEMENT BETWEEN EXCO RESOURCES AND SHERIDAN HOLDING COMPANY - EXCO RESOURCES INCdex210.htm
EX-31.2 - CERTIFICATION OF CFO PURSUANT TO SECTION 302 - EXCO RESOURCES INCdex312.htm
EX-31.3 - CERTIFICATION OF CAO PURSUANT TO SECTION 302 - EXCO RESOURCES INCdex313.htm
EX-31.1 - CERTIFICATION OF CEO PURSUANT TO SECTION 302 - EXCO RESOURCES INCdex311.htm
EX-2.9 - PURCHASE AND SALE AGREEMENT BETWEEN EXCO RESOURCES AND NORTH COAST ENERGY, INC. - EXCO RESOURCES INCdex29.htm
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 September 30, 2009

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 0-9204

 

 

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  ¨    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 October 30, 2009 was 211,677,939.

 

 

 


Table of Contents

EXCO RESOURCES, INC.

INDEX

 

PART I.    FINANCIAL INFORMATION    3
Item 1.    Financial Statements    3
   Condensed Consolidated Balance Sheets at September 30, 2009 and December 31, 2008    3
   Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008    5
   Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008    6
   Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2009 and 2008    7
   Notes to Condensed Consolidated Financial Statements    8
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    31
Item 3.    Quantitative and Qualitative Disclosures About Market Risk    54
Item 4.    Controls and Procedures    55
PART II.    OTHER INFORMATION    55
Item 1A.    Risk Factors    55
Item 6.    Exhibits    57
   Signatures    57
   Index to Exhibits    58

 

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Table of Contents

PART I—FINANCIAL INFORMATION

 

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

(in thousands)

   September 30,
2009
    December 31,
2008
 
     (Unaudited)        

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 55,681      $ 57,139   

Restricted cash

     69,983        —     

Accounts receivable:

    

Oil and natural gas

     40,356        130,970   

Joint interest

     35,070        22,807   

Interest and other

     6,545        5,895   

Inventory

     28,864        42,479   

Derivative financial instruments

     203,641        247,614   

Deferred income taxes

     —          —     

Other

     8,578        6,136   
                

Total current assets

     448,718        513,040   
                

Equity investment in TGGT Holdings, LLC

     216,631        —     

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

    

Unproved oil and natural gas properties

     246,272        481,596   

Proved developed and undeveloped oil and natural gas properties

     2,200,915        3,578,344   

Accumulated depletion

     (1,103,901     (936,088
                

Oil and natural gas properties, net

     1,343,286        3,123,852   
                

Gas gathering assets

     188,648        485,201   

Accumulated depreciation and amortization

     (21,885     (32,232
                

Gas gathering assets, net

     166,763        452,969   
                

Office and field equipment, net

     30,390        25,647   

Derivative financial instruments

     85,943        173,003   

Deferred financing costs, net

     12,356        62,884   

Other assets

     2,653        880   

Goodwill

     324,756        470,077   
                

Total assets

   $ 2,631,496      $ 4,822,352   
                

See accompanying notes.

 

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Table of Contents

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

(in thousands, except per share and share data)

   September 30,
2009
    December 31,
2008
 
     (Unaudited)        

Liabilities and shareholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 78,914      $ 172,400   

Accrued interest payable

     8,173        28,746   

Revenues and royalties payable

     79,323        108,130   

Income taxes payable

     1,060        160   

Current portion of asset retirement obligations

     16        1,830   

Derivative financial instruments

     13,772        11,607   
                

Total current liabilities

     181,258        322,873   
                

Long-term debt, net of current maturities

     1,689,277        3,019,738   

Asset retirement obligations and other long-term liabilities

     116,251        125,279   

Deferred income taxes

     8,661        9,371   

Derivative financial instruments

     24,386        12,590   

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 - 211,508,191 at September 30, 2009 and 210,968,931 at December 31, 2008

     212        211   

Additional paid-in capital

     3,088,200        3,070,766   

Accumulated deficit

     (2,476,749     (1,738,476
                

Total shareholders’ equity

     611,663        1,332,501   
                

Total liabilities and shareholders’ equity

   $ 2,631,496      $ 4,822,352   
                

See accompanying notes.

 

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Table of Contents

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

     Three months ended
September 30,
    Nine months ended
September 30,
 

(in thousands, except per share data)

   2009     2008     2009     2008  

Revenues:

        

Oil and natural gas

   $ 125,493      $ 402,407      $ 443,953      $ 1,155,986   

Midstream

     5,375        27,004        35,330        61,852   
                                

Total revenues

     130,868        429,411        479,283        1,217,838   
                                

Costs and expenses:

        

Oil and natural gas production

     43,026        63,002        144,538        177,526   

Midstream operating expenses

     5,411        28,820        35,580        59,671   

Gathering and transportation

     4,927        3,672        12,879        10,503   

Depreciation, depletion and amortization

     50,709        126,207        187,683        346,705   

Write-down of oil and natural gas properties

     —          1,193,105        1,293,579        1,193,105   

Gain on divestitures

     (460,626     —          (460,626     —     

Accretion of discount on asset retirement obligations

     1,767        1,482        5,856        4,271   

General and administrative

     21,647        21,002        64,682        63,286   
                                

Total costs and expenses

     (333,139     1,437,290        1,284,171        1,855,067   
                                

Operating income (loss)

     464,007        (1,007,879     (804,888     (637,229

Other income (expense):

        

Interest expense

     (46,737     (44,874     (129,760     (101,167

Gain (loss) on derivative financial instruments

     14,518        900,313        204,885        (103,534

Other income (expense)

     47        1,820        (7,895     5,496   

Equity method loss in TGGT Holdings, LLC

     (426     —          (426     —     
                                

Total other income (expense)

     (32,598     857,259        66,804        (199,205
                                

Income (loss) before income taxes

     431,409        (150,620     (738,084     (836,434

Income tax expense (benefit)

     (1,921     (4,291     189        (264,352
                                

Net income (loss)

     433,330        (146,329     (738,273     (572,082

Preferred stock dividends

     —          (6,997     —          (76,997
                                

Net income (loss) available to common shareholders

   $ 433,330      $ (153,326   $ (738,273   $ (649,079
                                

Earnings (loss) per common share:

        

Basic

        

Net income (loss) available to common shareholders

   $ 2.05      $ (0.80   $ (3.50   $ (4.84
                                

Weighted average number of common shares outstanding

     211,266        191,452        211,118        134,006   
                                

Diluted

        

Net income (loss) available to common shareholders

   $ 2.03      $ (0.80   $ (3.50   $ (4.84
                                

Weighted average common and common equivalent shares outstanding

     213,235        191,452        211,118        134,006   
                                

See accompanying notes.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

     Nine months ended
September 30,
 

(in thousands)

   2009     2008  

Operating Activities:

    

Net loss

   $ (738,273   $ (572,082

Adjustments to reconcile net loss to net cash provided by operating activities:

    

Loss (gain) on sale of other assets

     —          20   

Depreciation, depletion and amortization

     187,683        346,705   

Stock option compensation expense

     9,863        10,842   

Write-down of oil and natural gas properties

     1,293,579        1,193,105   

Gain on divestitures

     (460,626     —     

Equity method loss in TGGT Holdings, LLC

     426        —     

Accretion of discount on asset retirement obligations

     5,856        4,271   

Non-cash change in fair value of derivatives

     144,996        (59,004

Cash settlements of assumed derivatives

     (141,782     96,504   

Deferred income taxes

     (711     (264,657

Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt

     44,327        6,527   

Effect of changes in:

    

Accounts receivable

     66,961        (27,569

Other current assets

     (5,094     570   

Accounts payable and other current liabilities

     (57,348     76,785   
                

Net cash provided by operating activities

     349,857        812,017   
                

Investing Activities:

    

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

     (388,859     (741,654

Property and midstream acquisitions

     (67,774     (745,219

Net proceeds from disposition of property and equipment and other

     60,774        —     

Restricted cash

     (69,983     —     

Equity investment in TGGT Holdings, LLC

     (47,500     —     

Deposit on pending divestitures

     14,500        —     

Net proceeds from disposition of oil and natural gas properties, gathering systems and equipment

     1,348,604        1,736   
                

Net cash provided by (used in) investing activities

     849,762        (1,485,137
                

Financing Activities:

    

Borrowings under credit agreements

     52,949        1,065,185   

Repayments under credit agreements

     (1,080,740     (476,200

Borrowings under senior unsecured credit term agreement

     —          300,000   

Repayments under senior unsecured credit term agreement

     (300,000     —     

Proceeds from issuance of common stock

     5,400        14,465   

Payment of preferred stock dividends

     —          (82,827

Settlements of derivative financial instruments with a financing element

     141,782        (96,504

Deferred financing costs

     (20,468     (11,374
                

Net cash provided by (used in) financing activities

     (1,201,077     712,745   
                

Net increase (decrease) in cash

     (1,458     39,625   

Cash at beginning of period

     57,139        55,510   
                

Cash at end of period

   $ 55,681      $ 95,135   
                

Supplemental Cash Flow Information:

    

Interest paid

   $ 90,010      $ 109,017   
                

Supplemental non-cash investing and financing activities:

    

Capitalized stock option compensation

   $ 2,122      $ 2,263   
                

Capitalized interest

   $ 3,937      $ 1,925   
                

Issuance of common stock for director services

   $ 50      $ 120   
                

See accompanying notes.

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

 

               Additional
paid-in
capital
   Accumulated
deficit
    Total
shareholders’
equity
 
     Common Stock        

(in thousands)

   Shares    Amount        

Balance at December 31, 2008

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

Issuance of common stock

   539      1      5,450      —          5,451   

Share-based compensation

   —        —        11,984      —          11,984   

Net loss

   —        —        —        (738,273     (738,273
                                   

Balance at September 30, 2009

   211,508    $ 212    $ 3,088,200    $ (2,476,749   $ 611,663   
                                   

Balance at December 31, 2007

   104,579    $ 105    $ 1,043,645    $ 71,992      $ 1,115,742   

Issuance of common stock

   1,084      1      14,584      —          14,585   

Preferred stock conversion

   105,263      105      1,992,170      —          1,992,275   

Preferred stock dividends

   —        —        —        (76,997     (76,997

Share-based compensation

   —        —        13,105      —          13,105   

Net loss

   —        —        —        (572,082     (572,082
                                   

Balance at September 30, 2008

   210,926    $ 211    $ 3,063,504    $ (577,087   $ 2,486,628   
                                   

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.

EXCO Resources, Inc., a Texas corporation, is an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, as of August 14, 2009, we hold a 50% equity interest in a midstream joint venture which owns gathering systems and pipelines in East Texas and North Louisiana. Our assets in East Texas/North Louisiana, including our equity interest in the midstream operations, are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries, collectively, EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt.

The accompanying condensed consolidated balance sheets as of September 30, 2009 and December 31, 2008, the statements of operations for the three and nine months ended September 30, 2009 and 2008, the statements of cash flows for the nine months ended September 30, 2009 and 2008 and the changes in shareholders’ equity for the nine months ended September 30, 2009 and 2008, are for EXCO and its subsidiaries. The condensed 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 September 30, 2009 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, 2008.

Beginning in the fourth quarter of 2008, we reclassified our derivative financial instrument activities and other income items to the other income (expense) caption on our Consolidated Statements of Operations. Previously, we reported these items as a component of revenues. We have reclassified prior year amounts to conform to current year reporting. Additionally, as a result of our midstream transaction on August 14, 2009 as discussed in “Note 2. Significant recent activities,” we no longer report our midstream operations as a separate business segment. Effective August 14, 2009, we account for our midstream operations as an equity method investment. Our gathering system in Louisiana that supports our Vernon Field operations, which was previously reported within our midstream segment, is now reported in “Gathering and transportation” on the Condensed Consolidated Statement of Operations.

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.

 

2. Significant recent activities

On August 11, 2009, we closed a sale of properties located in East Texas, or the East Texas Transaction, with Encore Operating, LP, or Encore. Pursuant to the East Texas Transaction, we sold all of our interests in certain oil and natural gas properties located in our Overton Field and Gladewater area of East Texas. We received $156.7 million in cash at closing, after customary preliminary closing adjustments.

Also on August 11, 2009, we closed a sale of properties located in Texas and Oklahoma, or the Mid-Continent Transaction, with Encore. Pursuant to the Mid-Continent Transaction, we sold all of our interests in certain oil and gas properties located in our Mid-Continent operating area. We received $199.4 million in cash at closing, after customary preliminary closing adjustments.

Proceeds from the transactions pursuant to the East Texas Transaction and the Mid-Continent Transaction were used to repay a portion of our revolving credit agreements.

 

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On August 14, 2009, we closed a sale and joint development transaction with BG Group, plc, or BG Group, for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which included most of our oil and natural gas assets in East Texas/North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), or the BG Upstream Transaction. The BG Upstream Transaction includes agreements for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We received $727.0 million in cash at closing, after closing adjustments and the adjustments necessary to reflect the January 1, 2009 effective date. Pursuant to this transaction, BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, BG Group funding of the $400.0 million commitment will be satisfied solely through drilling of deep right wells as defined in the agreement.

The transactions with BG Group and Encore caused a significant alteration to our full cost pool and a gain of $362.3 million was recorded as a result of these transactions.

In addition, on August 14, 2009, we closed the sale to an affiliate of BG Group of a 50% interest in a newly formed company, TGGT Holdings, LLC, or TGGT, which now holds most of our East Texas and North Louisiana midstream assets, or the BG Midstream Transaction. Our Vernon Field midstream assets were excluded from the BG Midstream Transaction. Pursuant to the contribution agreement, we contributed TGG Pipeline, Ltd., or TGG, which owns intrastate pipelines in East Texas and North Louisiana, and Talco Midstream Assets, Ltd., or Talco, which owns gathering assets in East Texas and North Louisiana, to TGGT. BG Group contributed $269.2 million in cash to TGGT and we received those funds from TGGT as a special distribution at closing. EXCO Operating now owns 50% of TGGT and an affiliate of BG Group owns 50% of TGGT. The effective date of this transaction was also January 1, 2009. We adopted the equity method of accounting for our interest in TGGT upon its formation. The BG Midstream Transaction resulted in recognition of a gain of $98.3 million.

The total cash proceeds of $996.2 million from the BG Upstream Transaction and the BG Midstream Transaction were used to repay EXCO Operating’s $300.0 million senior unsecured term credit agreement, creation of an evergreen escrow funding account to develop the Haynesville operations, and a working capital contribution to TGGT, with the remainder applied to the outstanding balances under the EXCO Operating credit agreement.

On September 29, 2009, we reached an agreement with EV Energy Partners, L.P., along with certain institutional partnerships managed by EnerVest, Ltd. to sell our Ohio and certain Northwestern Pennsylvania producing assets for $145.0 million, subject to customary purchase price adjustments. The sale is expected to close in November 2009 and is effective as of September 1, 2009.

On September 30, 2009, we reached an agreement with Sheridan Holding Company I, LLC to sell all of our remaining assets in Oklahoma for $540.0 million, subject to customary purchase price adjustments. The sale is expected to close in November 2009 and is effective as of October 1, 2009.

 

3. Recent accounting pronouncements

On June 30, 2009, the Financial Accounting Standards Board, or the FASB, issued Update No. 2009-01-Topic 105-Generally Accepted Accounting Principles-amendments based on-Statement of Financial Accounting Standards No. 168-The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or ASU 2009-01. ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. ASU 2009-01 superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification became nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009.

On June 12, 2009, the FASB issued FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R),” or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of September 30, 2009, we do not have any variable interest entities and as such, the final rule will not have an effect on our financial statements and disclosures.

On June 12, 2009, the FASB issued FASB Statement No. 166, “Accounting for Transfers of Financial Assets,” or SFAS No. 166. SFAS No. 166 is a revision to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and will require more information about transfers of financial assets, including securitization

 

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transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

On May 28, 2009, the FASB issued FASB Accounting Standards Codification, or ASC Subtopic 855-10 for Subsequent Events. ASC 855-10 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. ASC 855-10 is effective for interim and annual periods ending after June 15, 2009.

On April 9, 2009, the FASB issued FASB ASC paragraph 820-10-65-4 for Fair Value Measurements and Disclosures. ASC 820-10-65-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. ASC 820-10-65-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph FASB ASU Section 320-10-50 for the Scope Section of Subtopic 305-10 for Investments – Debt and Equity Securities. ASC 820-10-65-4 is effective for interim periods ending after June 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 9, 2009, the FASB issued FASB ASC Section 825-10-65 for Derivatives and Hedging. ASC 825-10-65 amended Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. ASC 825-10-65 also amends APB Opinion No. 28, “Interim Financial Reporting,” to require fair value disclosures in summarized financial information at interim reporting periods. ASC 825-10-65 was effective for interim periods ending after June 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 1, 2009, the FASB issued FASB ASC Subtopic 805-20 for Business Combinations. ASC 805-20 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business Combinations,” to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted ASC 805-20 on January 1, 2009.

In March 2008, the FASB issued FASB ASC Section 815-10-65 for Derivatives and Hedging. ASC 815-10-65 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. ASC 815-10-65 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:

 

   

Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

 

   

Permits the use of new technologies for determining oil and natural gas reserves;

 

   

Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

 

   

Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

 

   

Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

 

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Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

We are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and 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 are summarized in our Annual Report on Form 10-K for the year ended December 31, 2008.

In addition, as a result of our 50% ownership interest in TGGT, we have adopted the equity method of accounting. See “Note 13. Equity investment.”

 

5. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, 2009:

 

(in thousands)

      

Asset retirement obligation at January 1, 2009

   $ 120,671   

Activity during the nine months ended September 30, 2009:

  

Liabilities incurred during the period

     721   

Liabilities settled during the period

     (2,696

Reduction to retirement obligations due to divestitures

     (23,513

Accretion of discount

     5,856   
        

Asset retirement obligations at September 30, 2009

     101,039   

Less current portion

     16   
        

Long-term portion

   $ 101,023   
        

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 requires that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs. 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 $246.3 million and $481.6 million as of September 30, 2009 and December 31, 2008, respectively, are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to the depletable full cost pool as a result of extensions or discoveries from drilling operations. We expect these costs to be evaluated in one to ten 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.

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 related to Proved Reserves is divided by the total quantities of Proved Reserves to determine the unit amortization rate. This rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, which is attributable to our acquisition, exploration, exploitation and development activities.

Sales, dispositions 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 amortization rate and/or the relationship between capitalized costs and Proved Reserves. Our BG Upstream Transaction, East Texas Transaction and Mid-Continent Transaction divestiture transactions were considered significant and we recognized gains on these sales of $362.3 million.

 

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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, computed as the sum of the estimated future net revenues from our Proved Reserves using current period-end prices, discounted at 10%, and adjusted for related income tax effects (ceiling test). When computing our ceiling test, we evaluate the limitation at the end of each reporting period. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting period, we subsequently evaluate the limitation based on price changes that occur after the balance sheet date to assess impairment as currently permitted by Staff Accounting Bulletin Topic 12—Oil and Gas Producing Activities. 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.

We recognized a ceiling test write-down of $1.3 billion for the nine months ended September 30, 2009 to our proved oil and natural gas properties. For the three months ended September 30, 2009, we would have incurred an after-tax ceiling test write-down of $43.5 million. However, subsequent price increases for natural gas eliminated the need for a write-down. For the three and nine months ended September 30, 2008, we recognized a ceiling test write-down of $1.2 billion to our proved oil and natural gas properties.

Under the present full cost accounting rules, we are required to compute the after-tax present value of our proved oil and natural gas properties using spot market prices for oil and natural gas at our balance sheet date. The base for our spot prices for natural gas is Henry Hub and for oil is Cushing, Oklahoma. On September 30, 2009, the spot price for natural gas at Henry Hub was $3.30 per Mmbtu and the spot oil price at Cushing, Oklahoma was $70.43 per Bbl. On September 30, 2008, the spot price for natural gas at Henry Hub was $7.12 per Mmbtu and the spot oil price at Cushing, Oklahoma was $100.67 per Bbl. Natural gas, which is sold at other natural gas marketing hubs where we conduct operations, is subject to prices which reflect variables that can increase or decrease spot natural gas prices at these hubs such as market demand, transportation costs and quality of the natural gas being sold. Those differences are referred to as the basis differentials. Typically, basis differentials result in natural gas prices which are lower than Henry Hub, except in Appalachia, where we have typically received a premium to Henry Hub. There can be no assurance that basis premiums in Appalachia will continue. We may face further ceiling test write-downs in future periods, depending on level of commodity prices, drilling results and well performance.

The calculation of the ceiling test 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, production and changes in economics related to the properties 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 nine months ended September 30, 2009 and 2008 equals the net income (loss) available to common shareholders divided by the weighted average common shares outstanding during the period. Diluted earnings (loss) per common share for the three and nine months ended September 30, 2009 and 2008 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, including our preferred stock outstanding during the first half of 2008, whether exercisable or not. Since we incurred net losses for the nine months ended September 30, 2009 and the three and nine months ended September 30, 2008, we have excluded the potential common stock equivalents from the assumed exercise of stock options of 14,677,233 for the nine months ended September 30, 2009, and 12,353,376 and 12,387,593 for the three and nine months ended September 30, 2008, respectively, as they were antidilutive. We have also excluded 19,439,891 and 76,336,899 shares of common stock equivalents from the assumed conversion of the preferred stock from the computation of loss per share for the three and nine months ended September 30, 2008, respectively, as they were antidilutive. As a result of the preferred stock converting to common stock during the third quarter of 2008, there was no impact to 2009.

 

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

 

     Three months ended September 30,     Nine months ended September 30,  

(in thousands, except per share amounts)

   2009    2008     2009     2008  

Basic income (loss) per common share:

         

Net income (loss)

   $ 433,330    $ (146,329   $ (738,273   $ (572,082

Preferred stock dividends

     —        6,997        —          76,997   
                               

Net income (loss) available to common shareholders

   $ 433,330    $ (153,326   $ (738,273   $ (649,079
                               

Shares:

         

Weighted average number of common shares outstanding

     211,266      191,452        211,118        134,006   
                               

Basic income (loss) per common share:

         

Net income (loss) available to common shareholders per common share

   $ 2.05    $ (0.80   $ (3.50   $ (4.84
                               

Diluted income (loss) per share:

         

Net income (loss) available to common shareholders

   $ 433,330    $ (153,326   $ (738,273   $ (649,079
                               

Shares:

         

Weighted average number of common shares outstanding

     211,266      191,452        211,118        134,006   

Dilutive effect of stock options

     1,969      —          —          —     
                               

Weighted average common shares and common stock equivalent shares outstanding

     213,235      191,452        211,118        134,006   
                               

Diluted income (loss) per share:

         

Net income (loss) available to common shareholders per common share

   $ 2.03    $ (0.80   $ (3.50   $ (4.84
                               

 

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 daily closing prices 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 September 30, 2009 is $18.5 million over a weighted average period of 0.91 years.

The following is a reconciliation of our stock option expense for the three and nine months ended September 30, 2009 and 2008:

 

     Three months ended September 30,    Nine months ended September 30,
     2009    2008    2009    2008

General and administrative expense

   $ 2,764    $ 2,985    $ 7,865    $ 7,553

Lease operating expense

     619      1,169      1,998      3,289
                           

Total share-based compensation expense

     3,383      4,154      9,863      10,842

Share-based compensation capitalized

     942      987      2,122      2,263
                           

Total share-based compensation

   $ 4,325    $ 5,141    $ 11,985    $ 13,105
                           

During the nine months ended September 30, 2009, options to purchase 317,600 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. During the nine months ended September 30, 2008, options to purchase 1,360,600 shares were granted under the 2005 Incentive Plan at prices ranging from $15.15 to $38.01 per share with fair values ranging from $5.39 to $14.27 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. On June 4, 2009, our shareholders approved an amendment to the 2005 Incentive Plan to increase the number of shares authorized for issuance by an additional 3,000,000 shares. The number of shares available to be granted under the 2005 Incentive Plan as of September 30, 2009 was 6,612,175 shares. At December 31, 2008, there were 3,342,450 shares available to be granted under the 2005 Incentive Plan.

 

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

 

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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

   September 30,
2009
    December 31,
2008
 

Commodity contracts

   Derivative financial instruments - Current assets    $ 203,641      $ 247,614   

Commodity contracts

   Derivative financial instruments - Long-term assets      85,943        173,003   

Commodity contracts

   Derivative financial instruments - Current liabilities      (8,144     (2,734

Commodity contracts

   Derivative financial instruments - Long-term liabilities      (24,386     (11,585

Interest rate contracts

   Derivative financial instruments - Current liabilities      (5,628     (8,873

Interest rate contracts

   Derivative financial instruments - Long-term liabilities      —          (1,005
                   

Net derivatives

      $ 251,426      $ 396,420   
                   

The Effect of Derivative Financial Instruments

 

          Three months ended September 30,     Nine months ended September 30,  

(in thousands)

  

Statement of Operations location

   2009     2008     2009     2008  

Commodity contracts (1)

  

Gain (loss) on derivative financial instruments

   $ 14,518      $ 900,313      $ 204,885      $ (103,534

Interest rate contracts (2)

  

Interest (expense) income

     (3,304     (2,052     (3,785     6,079   
                                   

Net gain (loss)

      $ 11,214      $ 898,261      $ 201,100      $ (97,455
                                   

 

(1) Included in these amounts are cash settlements, including net cash receipts of $113,563 and $354,131 for the three and nine months ended September 30, 2009, respectively, and net cash payments of $70,019 and $157,383 for the three and nine months ended September 30, 2008, respectively.
(2) Included in these amounts are cash settlements, including net cash payments of $3,550 and $8,036 for the three and nine months ended September 30, 2009, respectively, and net cash receipts of $163 and $924 for the three and nine months ended September 30, 2008, respectively.

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 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 on the Condensed Consolidated Statements of Operations, which do not impact cash flows, were a loss of $99.0 million and a gain of $970.3 million for the three months ended September 30, 2009 and 2008, respectively, and were a loss of $149.2 million and a gain of $53.9 million for the nine months ended September 30, 2009 and 2008, respectively. Unrealized fair value adjustments included in Interest expense on the Condensed Consolidated Statements of Operations, which do not impact cash flows, were a gain of $0.2 million and a loss of $2.2 million for the three months ended September 30, 2009 and 2008, respectively, and were gains of $4.3 million and $5.2 million for the nine months ended September 30, 2009 and 2008, respectively.

We place our derivative financial instruments with financial institutions and other firms that we believe 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 September 30, 2009 and December 31, 2008, we had a net asset position of $251.4 million and $396.4 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.

 

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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 for the nine months ended September 30, 2009 and the year ended December 31, 2008:

 

     For the nine months ended September 30, 2009  

(in thousands)

   Level 1    Level 2     Level 3    Total  

Oil and natural gas derivative financial instruments

   $ —      $ 257,054      $ —      $ 257,054   

Interest rate swaps

     —        (5,628     —        (5,628
                              
   $ —      $ 251,426      $ —      $ 251,426   
                              
     For the year ended December 31, 2008  

(in thousands)

   Level 1    Level 2     Level 3    Total  

Oil and natural gas derivative financial instruments

   $ —      $ 406,298      $ —      $ 406,298   

Interest rate swaps

     —        (9,878     —        (9,878
                              
   $ —      $ 396,420      $ —      $ 396,420   
                              

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, in part by utilization of the derivative counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, 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, natural gas basis swap and natural gas collar 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 gas at posted price indexes, including NYMEX Henry Hub (HH) swap contracts coupled with basis swap contracts that convert the HH price index point to the Panhandle Eastern Pipe Line index (PEPL). 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 HH for natural gas swaps and PEPL index quotes for our existing basis swaps and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

Appalachia derivatives. In connection with our September 29, 2009 sales agreement with EnerVest, we entered into Appalachian basin swaps, natural gas collars and basis swaps on behalf of EnerVest. Pursuant to the sales agreement, EXCO has certain rights, which eliminate our exposure to gains or losses on these derivative financial instruments in the event the transaction does not close.

 

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The following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value as of September 30, 2009:

 

(in thousands, except prices)

   Volume
Mmbtu/Bbl
   Floor and ceiling,
weighted average
strike price
    Fair value at
September 30, 2009
 

Natural gas:

       

Remainder of 2009

   23,450    $ 8.08      $ 77,469   

2010

   66,298      7.62        92,472   

2011

   12,775      7.48        7,691   

2012

   5,490      5.91        (5,524

2013

   5,475      5.99        (5,256
               

Total natural gas

   113,488        166,852   
               

Basis swaps:

       

Remainder of 2009

   920      (1.10     (773
               

Total basis swaps

   920        (773
               

Oil:

       

Remainder of 2009

   398      80.66        3,780   

2010

   1,568      104.64        46,723   

2011

   1,095      112.99        37,876   

2012

   92      109.30        2,596   
               

Total oil

   3,153        90,975   
               

Total oil and natural gas derivatives

        $ 257,054   
             

At December 31, 2008, we had outstanding derivative contracts to mitigate price volatility covering 168,658 Mmcf of natural gas and 4,335 Mbbls of oil. At September 30, 2009, the average forward NYMEX natural gas price per Mmbtu for the remainder of 2009 and for 2010 were $4.75 and $6.21, respectively, and the average forward NYMEX oil prices per Bbl for the remainder of 2009 and for 2010 were $71.08 and $74.38, respectively.

Our derivative financial instruments used to mitigate price volatility covered 80.9% and 76.8% of our total equivalent Mcfe production for the three and nine months ended September 30, 2009, respectively, and 80.0% and 79.7% of our total equivalent Mcfe production for the three and nine months ended September 30, 2008, respectively.

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 have classified our interest rate swaps and their related fair value tier as Level 2.

During the three and nine months ended September 30, 2009, we recognized increases of $3.3 million and $3.8 million, respectively, in interest expense related to our interest rate swaps. For the three and nine months ended September 30, 2008, we recognized an increase of $2.1 million and a decrease of $6.1 million, respectively, in interest expense related to our interest rate swaps. As of September 30, 2009 and December 31, 2008, the fair value of our interest rate swaps was a liability of $5.6 million and $9.9 million, respectively.

 

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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 7 1/4% senior notes due January 15, 2011, or Senior Notes, is $442.5 million with a carrying amount of $449.6 million as of September 30, 2009. The estimated fair value has been calculated based on market quotes.

 

10. Current and long-term debt

Our total debt is summarized as follows:

 

(in thousands)

   September 30,
2009
   December 31,
2008

EXCO Resources Credit Agreement

   $ 751,430    $ 1,048,951

EXCO Operating Credit Agreement

     488,215      1,218,485

Term Credit Agreement

     —        300,000

7 1/4% senior notes due 2011

     444,720      444,720

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

     4,912      7,582
             

Total debt

     1,689,277      3,019,738

Less current maturities

     —        —  
             

Total long term debt

   $ 1,689,277    $ 3,019,738
             

Credit agreements

EXCO Resources credit agreement

The EXCO Resources credit agreement, as amended, or the EXCO Resources Credit Agreement, currently has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At September 30, 2009, we had $751.4 million of outstanding indebtedness under the EXCO Resources Credit Agreement. As of October 2, 2009, after the borrowing base redetermination discussed below, the available borrowing capacity was $83.4 million, net of outstanding letters of credit. The borrowing base is redetermined semi-annually, with EXCO and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. Borrowings under the EXCO Resources Credit Agreement are collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. EXCO may have in place derivative financial instruments covering no more than 80% of its forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO is required to have in place mortgages covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Resources Credit Agreement matures on March 30, 2012.

On October 2, 2009, we entered into a fifth amendment to the EXCO Resources Credit Agreement which, among other things, modified the terms and conditions under which EXCO is permitted to pay a cash dividend on its common stock. Pursuant to the fifth 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 borrowing base availability under the EXCO Resources Credit Agreement and (iii) payment of such dividend is permitted under EXCO’s 7 1/4% Senior Notes Indenture.

Also on October 2, 2009, the lenders agreed to consents which (i) established the borrowing base under the EXCO Resources Credit Agreement at $850.0 million, (ii) approved the proposed sale of certain Appalachia properties and extended the deadline for consummation of the sale transaction to November 30, 2009, (iii) set the estimated loan value for the Appalachia properties proposed sale at $100.0 million with reduction in the borrowing base effective with the closing of such transaction and (iv) permit EXCO to receive non-cash consideration from the proposed sale of the Appalachia properties in an amount not to exceed 5.0% of the value of total sales consideration received from such sale. In addition to the Appalachia properties, the lenders assigned a $300.0 million loan value to certain Mid-Continent properties which are being sold and provided for requirements to unwind certain hedges under the EXCO Resources Credit Agreement in connection with the pending sales.

 

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The interest rate ranges from LIBOR plus 175 basis points, or bps, to LIBOR plus 250 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps depending upon borrowing base usage. At September 30, 2009, the one month LIBOR was 0.25%, which would result in an interest rate of approximately 2.5% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

As of September 30, 2009, EXCO was in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that EXCO Resources:

 

   

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

 

   

not permit our ratio of consolidated funded indebtedness (as defined) to consolidated EBITDAX (as defined) to be greater than (i) 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2008 up to and including December 31, 2009, (ii) 3.75 to 1.0 at the end of the fiscal quarter ending on March 31, 2010 and (iii) 3.50 to 1.0 beginning with the quarter ending June 30, 2010 and each quarter end thereafter; and

 

   

maintain a consolidated EBITDAX to consolidated interest expense (as defined) ratio of at least 2.5 to 1.0 at the end of any fiscal quarter ending on or after September 30, 2007.

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

EXCO Operating credit agreement

The EXCO Operating credit agreement, as amended, or the EXCO Operating Credit Agreement, currently has a borrowing base of $850.0 million with commitments spread among a consortium of banks, none of which have commitments exceeding 10% of the aggregate commitment amount. At September 30, 2009, we had $488.2 million of outstanding indebtedness and $361.8 million of available borrowing capacity under the EXCO Operating Credit Agreement. The borrowing base is redetermined semi-annually, with EXCO Operating and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations are made on or about April 1 and October 1 of each year. The EXCO Operating Credit Agreement is secured by a first priority lien on the assets of EXCO Operating, including 100% of the equity of EXCO Operating’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EXCO Operating. EXCO Operating may have in place derivative financial instruments covering no more than 80% of the forecasted production from total Proved Reserves (as defined) for each of the first two years of the five year period commencing on the date of incurrence on each new derivative financial instrument and 70% of the forecasted production from total Proved Reserves for each of the third through fifth years of the five year period thereafter. EXCO Operating is required to have mortgages in place covering 80% of the Engineered Value of its Borrowing Base Properties (as defined). The EXCO Operating Credit Agreement matures on March 30, 2012.

On October 16, 2009, the lenders agreed to consents which (i) confirmed the borrowing base under the EXCO Operating Credit Agreement at $850.0 million until the next borrowing base redetermination date, (ii) provide for EXCO Operating to grant to lenders a first priority lien and security interest in all of its equity interest in TGGT, representing EXCO Operating’s 50% interest in the midstream assets contributed in connection with the BG Midstream Transaction and (iii) by November 30, 2009, consummate transactions to unwind oil and natural gas derivatives with respect to notional volumes of oil and natural gas with respect to sold production volumes which had been waived under a consent granted on July 29, 2009.

The interest rate ranges from LIBOR plus 175 bps to LIBOR plus 250 bps depending on borrowing base usage. The facility also includes an ABR pricing alternative ranging from ABR plus 75 bps to ABR plus 150 bps, depending upon borrowing base usage. At September 30, 2009, the one month LIBOR was 0.25%, which would result in an interest rate of approximately 2.25% on any new indebtedness we may incur under the EXCO Operating Credit Agreement.

As of September 30, 2009, EXCO Operating was in compliance with the financial covenants contained in the EXCO Operating Credit Agreement, which require that EXCO Operating:

 

   

maintain a consolidated current ratio (as defined) of at least 1.0 to 1.0 at the end of any fiscal quarter, beginning with the quarter ended September 30, 2007;

 

   

not permit our ratio of consolidated indebtedness to consolidated EBITDAX (as defined) to be greater than 3.5 to 1.0 at the end of each fiscal quarter, beginning with the quarter ended September 30, 2007; and

 

   

not permit our interest coverage ratio (as defined) to be less than 2.5 to 1.0 at the end of each fiscal quarter, beginning with the quarter ended September 30, 2007.

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

 

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Term credit agreement

On December 8, 2008, EXCO Operating entered into a $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, with an aggregate balance of $300.0 million. Net proceeds from the loan of $274.4 million, after bank fees and expenses, were used to repay and terminate an original $300.0 million senior unsecured term credit agreement that was scheduled to mature on December 15, 2008. In addition to the fees incurred upon the closing of the Term Credit Agreement, EXCO Operating provided for additional fees on unpaid principal amounts, or duration fees, as defined in the agreement. These included a 5% fee on the unpaid principal on June 15, 2009 and an additional 3% fee on any unpaid outstanding balance as of September 15, 2009. On June 15, 2009 we remitted the first duration fee payment of $15.0 million.

In connection with the closings of the BG Upstream Transaction, the BG Midstream Transaction and the East Texas Transaction, EXCO Operating repaid the outstanding $300.0 million under the Term Credit Agreement. As a consequence of the early payment of the Term Credit Agreement, EXCO Operating avoided payment of a $9.0 million duration fee that would have been due on September 15, 2009.

The unamortized balance of deferred financing costs attributable to the Term Credit Agreement of approximately $11.6 million was written off and is included in interest expense in the quarter ended September 30, 2009.

7 1/4% Senior Notes due January 15, 2011

As of September 30, 2009 and December 31, 2008, $444.7 million in principal was outstanding on our Senior Notes. The unamortized premium on the Senior Notes at September 30, 2009 and December 31, 2008 was $4.9 million and $7.6 million, respectively. The estimated fair value of the Senior Notes, based on quoted market prices for the Senior Notes, was $442.5 million on September 30, 2009. Interest is payable on the Senior Notes semi-annually in arrears on January 15 and July 15 of each year.

 

11. 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. As a result of these cumulative financial operating losses, we have provided valuation allowances of approximately $825.6 million 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.

 

12. Operating segments

We follow FASB ASC Topic 280 for Segment Reporting when reporting operating segments. Prior to the August 14, 2009 sale of a 50% interest in our midstream investment, as discussed below and in “Note 2. Significant recent activities,” our reportable segments consisted of exploration and production and midstream. Our exploration and production operational segment and midstream segment were managed 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 discussed in “Note 2. Significant recent activities,” on August 14, 2009 we closed the BG Midstream Transaction and contributed TGG and Talco to TGGT. We received net sales proceeds of $269.2 million at closing, including preliminary closing adjustments. We own 50% of TGGT and now account for our interest using the equity method (see “Note 13. Equity investment”).

As a result of this sale, 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.

Summarized financial information concerning our reportable segments is shown in the following table. 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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(in thousands)

   Exploration and
production
    Midstream    Intercompany
eliminations
    Consolidated
total

For the three months ended September 30, 2009:

         

Third party revenues

   $ 125,493      $ 5,375    $ —        $ 130,868

Intersegment revenues

     (4,324     8,896      (4,572     —  
                             

Total revenues

   $ 121,169      $ 14,271    $ (4,572   $ 130,868
                             

Segment profit

   $ 73,216      $ 4,288    $ —        $ 77,504
                             

For the three months ended September 30, 2008:

         

Third party revenues

   $ 402,407      $ 27,004    $ —        $ 429,411

Intersegment revenues

     (9,664     22,254      (12,590     —  
                             

Total revenues

   $ 392,743      $ 49,258    $ (12,590   $ 429,411
                             

Segment profit

   $ 326,069      $ 7,848    $ —        $ 333,917
                             

For the nine months ended September 30, 2009:

         

Third party revenues

   $ 443,953      $ 35,330    $ —        $ 479,283

Intersegment revenues

     (20,356     41,148      (20,792     —  
                             

Total revenues

   $ 423,597      $ 76,478    $ (20,792   $ 479,283
                             

Segment profit

   $ 266,180      $ 20,106    $ —        $ 286,286
                             

For the nine months ended September 30, 2008:

         

Third party revenues

   $ 1,155,986      $ 61,852    $ —        $ 1,217,838

Intersegment revenues

     (24,734     44,063      (19,329     —  
                             

Total revenues

   $ 1,131,252      $ 105,915    $ (19,329   $ 1,217,838
                             

Segment profit

   $ 943,223      $ 26,915    $ —        $ 970,138
                             

As of September 30, 2009:

         

Total assets

   $ 2,631,496      $ —      $ —        $ 2,631,496
                             

As of December 31, 2008:

         

Total assets

   $ 4,392,218      $ 430,134    $ —        $ 4,822,352
                             

 

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

 

     Three months ended
September 30,
    Nine months ended
September 30,
 

(in thousands)

   2009     2008     2009     2008  

Segment profits

   $ 77,504      $ 333,917      $ 286,286      $ 970,138   

Depreciation, depletion and amortization

     (50,709     (126,207     (187,683     (346,705

Write-down of oil and natural gas properties

     —          (1,193,105     (1,293,579     (1,193,105

Gain on divestitures

     460,626        —          460,626        —     

Accretion of discount on asset retirement obligations

     (1,767     (1,482     (5,856     (4,271

General and administrative

     (21,647     (21,002     (64,682     (63,286

Interest expense

     (46,737     (44,874     (129,760     (101,167

Gain (loss) on derivative financial instruments

     14,518        900,313        204,885        (103,534

Other income (loss)

     47        1,820        (7,895     5,496   

Equity method loss on TGGT Holdings, LLC

     (426     —          (426     —     
                                

Income (loss) before income taxes

   $ 431,409      $ (150,620   $ (738,084   $ (836,434
                                

 

13. Equity investment

In connection with the sale of 50% of our interest in our midstream assets to BG Group, as discussed in “Note 2. Significant recent activities” and “Note 12. Operating segments,” TGGT now holds substantially all of our East Texas/North Louisiana midstream assets. Our 50% ownership interest in TGGT is accounted for under the equity method. As a result, the midstream assets were recorded as an investment in TGGT at our historical cost of $158.1 million plus a $20.0 million working capital contribution upon TGGT’s formation. In September 2009, we made an additional $27.5 million working capital contribution to TGGT to fund its expansion of gathering and treating facilities.

At September 30, 2009, our equity investment in TGGT exceeded our book value of assets by $44.1 million, of which $55.5 million represents the difference in the historical basis of our contribution and the fair value of BG Group’s contribution. The $55.5 million is being amortized over the life of the underlying assets, offset by $11.4 million of goodwill included in our investment.

The following table presents summarized financial information of TGGT:

 

(in thousands)

   As of
September 30, 2009
 

Assets

  

Total current assets

     120,035   

Property and equipment, net

     438,137   
        

Total assets

   $ 558,172   
        

Liabilities and members’ equity

  

Total current liabilities

     36,640   

Members’ equity:

  

Total members’ equity

     521,532   
        

Total liabilities and members’ equity

   $ 558,172   
        
     For the 48 day period
from August 14, 2009
to September 30, 2009
 

Revenues

  

Gas sales

   $ 5,304   

Condensate, shrinkage and loss revenues

     1,288   

Gathering, compression and other services

     3,087   
        

Total revenues

     9,679   
        

Costs and expenses:

  

Gas purchases

     5,495   

Operating expenses

     2,784   

Depreciation expense

     1,524   

Other operating expenses

     728   
        

Total costs and expenses

     10,531   
        

Net income (loss)

   $ (852
        

EXCO’s equity in TGGT earnings (loss)

   $ (426
        

 

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14. Dividends

On October 1, 2009 our Board of Directors approved the commencement of a dividend program at an initial quarterly cash dividend rate of $0.025 per share of EXCO’s common stock. The first quarterly dividend of $0.025 per share was paid on October 26, 2009 to holders of record on October 12, 2009. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to the approval of EXCO’s Board of Directors.

 

15. Subsequent events

We evaluated our activity after September 30, 2009 until the date of issuance, November 4, 2009, for recognized and unrecognized subsequent events not discussed elsewhere in these footnotes and determined there were none.

 

16. Condensed consolidating financial statements

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The Senior Notes are jointly and severally guaranteed by some of our subsidiaries (referred to collectively as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of EXCO Resources, or Resources, and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries.

EXCO Operating and its subsidiaries are designated as “Non-Guarantor Subsidiaries” in the accompanying condensed consolidating financial statements. There are no other Non-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 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)

September 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations     Consolidated  

Assets

          

Current assets:

          

Cash and cash equivalents

   $ 32,201      $ 2,849      $ 20,631      $ —        $ 55,681   

Restricted cash

     —          14,500        55,483        —          69,983   

Other current assets

     136,295        21,048        165,711          323,054   
                                        

Total current assets

     168,496        38,397        241,825        —          448,718   
                                        

Equity investment in TGGT Holdings, LLC

     —          —          216,631        —          216,631   

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

          

Unproved oil and natural gas properties

     60,817        112,185        73,270        —          246,272   

Proved developed and undeveloped oil and natural gas properties

     579,331        427,928        1,193,656        —          2,200,915   

Accumulated depletion

     (273,466     (168,302     (662,133     —          (1,103,901
                                        

Oil and natural gas properties, net

     366,682        371,811        604,793        —          1,343,286   
                                        

Gas gathering, office and field equpment, net

     8,901        54,122        134,130        —          197,153   

Investments in and advances to affiliates

     171,974        —          —          (171,974     —     

Derivative financial instruments

     67,500        —          18,443        —          85,943   

Deferred financing costs, net

     7,427        —          4,929        —          12,356   

Other assets

     2        1,050        1,601        —          2,653   

Goodwill

     93,200        164,469        67,087        —          324,756   
                                        

Total assets

   $ 884,182      $ 629,849      $ 1,289,439      $ (171,974   $ 2,631,496   
                                        

Liabilities and shareholders’ equity

          

Current liabilities

   $ 54,632      $ 34,855      $ 91,771      $ —        $ 181,258   

Long-term debt

     1,201,062        —          488,215        —          1,689,277   

Deferred income taxes

     8,661        —          —          —          8,661   

Other liabilities

     28,821        82,617        29,199        —          140,637   

Payable to parent

     (1,020,657     975,552        45,105        —          —     

Total shareholders’ equity

     611,663        (463,175     635,149        (171,974     611,663   
                                        

Total liabilities and shareholders’ equity

   $ 884,182      $ 629,849      $ 1,289,439      $ (171,974   $ 2,631,496   
                                        

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2008

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations     Consolidated  

Assets

          

Current assets:

          

Cash and cash equivalents

   $ 8,618      $ 12,360      $ 36,161      $ —        $ 57,139   

Other current assets

     162,607        29,935        263,359        —          455,901   
                                        

Total current assets

     171,225        42,295        299,520        —          513,040   
                                        

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

          

Unproved oil and natural gas properties

     85,061        119,940        276,595        —          481,596   

Proved developed and undeveloped oil and natural gas properties

     940,529        673,814        1,964,001        —          3,578,344   

Accumulated depletion

     (232,261     (145,103     (558,724     —          (936,088
                                        

Oil and natural gas properties, net

     793,329        648,651        1,681,872        —          3,123,852   
                                        

Gas gathering, office and field equipment, net

     8,582        55,404        414,630        —          478,616   

Investments in and advances to affiliates

     802,902        —          —          (802,902     —     

Derivative financial instruments

     120,097        —          52,906        —          173,003   

Deferred financing costs, net

     6,414        —          56,470        —          62,884   

Other assets

     2        678        200        —          880   

Goodwill

     110,800        164,469        194,808        —          470,077   
                                        

Total assets

   $ 2,013,351      $ 911,497      $ 2,700,406      $ (802,902   $ 4,822,352   
                                        

Liabilities and shareholders’ equity

          

Current liabilities

   $ 66,871      $ 50,256      $ 205,746      $ —        $ 322,873   

Long-term debt

     1,501,253        —          1,518,485        —          3,019,738   

Deferred income taxes

     9,371        —          —          —          9,371   

Other liabilities

     27,065        78,316        32,488        —          137,869   

Payable to parent

     (923,710     948,463        (24,753     —          —     

Commitments and contingencies

     —          —          —          —          —     

Total shareholders’ equity

     1,332,501        (165,538     968,440        (802,902     1,332,501   
                                        

Total liabilities and shareholders’ equity

   $ 2,013,351      $ 911,497      $ 2,700,406      $ (802,902   $ 4,822,352   
                                        

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations     Consolidated  

Revenues:

          

Oil and natural gas

   $ 37,260      $ 18,981      $ 69,252      $ —        $ 125,493   

Midstream

     —          —          5,375        —          5,375   
                                        

Total revenues

     37,260        18,981        74,627        —          130,868   
                                        

Costs and expenses:

          

Oil and natural gas production

     10,992        7,987        24,047        —          43,026   

Midstream operating expenses

     —          —          5,411        —          5,411   

Gathering and transportation

     —          751        4,176        —          4,927   

Depreciation, depletion and amortization

     12,819        7,424        30,466        —          50,709   

Write-down of oil and natural gas properties

     —          —          —          —          —     

Gain on divestitures

     (98,581     —          (362,045     —          (460,626

Accretion of discount on asset retirement obligations

     422        853        492        —          1,767   

General and administrative

     6,472        1,675        13,500        —          21,647   
                                        

Total costs and expenses

     (67,876     18,690        (283,953     —          (333,139
                                        

Operating income

     105,136        291        358,580        —          464,007   

Other income (expense):

          

Interest expense

     (17,025     —          (29,712     —          (46,737

Gain (loss) on derivative financial instruments

     7,053        (548     8,013        —          14,518   

Other income (expense)

     6,809        (5,734     (1,028     —          47   

Equity method loss in TGGT Holdings, LLC

     —          —          (426     —          (426

Equity in earnings of subsidiaries

     329,436        —          —          (329,436     —     
                                        

Total other income (expense)

     326,273        (6,282     (23,153     (329,436     (32,598
                                        

Income (loss) before income taxes

     431,409        (5,991     335,427        (329,436     431,409   

Income tax expense (benefit)

     (1,921     —          —          —          (1,921
                                        

Net income (loss)

     433,330        (5,991     335,427        (329,436     433,330   

Preferred stock dividends

     —          —          —          —          —     
                                        

Net income (loss) available to common shareholders

   $ 433,330      $ (5,991   $ 335,427      $ (329,436   $ 433,330   
                                        

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2008

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations    Consolidated  

Revenues:

           

Oil and natural gas

   $ 116,326      $ 58,473      $ 227,608      $ —      $ 402,407   

Midstream

     —          —          27,004        —        27,004   
                                       

Total revenues

     116,326        58,473        254,612        —        429,411   
                                       

Costs and expenses:

           

Oil and natural gas production

     19,625        9,473        33,904        —        63,002   

Midstream operating expenses

     —          —          28,820        —        28,820   

Gathering and transportation

     56        832        2,784        —        3,672   

Depreciation, depletion and amortization

     39,919        16,856        69,432        —        126,207   

Write-down of oil and natural gas properties

     198,440        359,350        635,315        —        1,193,105   

Accretion of discount on asset retirement obligations

     417        723        342        —        1,482   

General and administrative

     11,688        4,814        4,500        —        21,002   
                                       

Total costs and expenses

     270,145        392,048        775,097        —        1,437,290   
                                       

Operating income (loss)

     (153,819     (333,575     (520,485     —        (1,007,879

Other income (expense):

           

Interest expense

     (19,530     —          (25,344     —        (44,874

Gain on derivative financial instruments

     385,132        50,456        464,725        —        900,313   

Other income (expense)

     7,157        (6,217     880        —        1,820   

Equity in earnings of subsidiaries

     (255,828     —          —          255,828      —     
                                       

Total other income (expense)

     116,931        44,239        440,261        255,828      857,259   
                                       

Income (loss) before income taxes

     (36,888     (289,336     (80,224     255,828      (150,620

Income tax expense (benefit)

     109,441        (113,732     —          —        (4,291
                                       

Net income (loss)

     (146,329     (175,604     (80,224     255,828      (146,329

Preferred stock dividends

     (6,997     —          —          —        (6,997
                                       

Net income (loss) available to common shareholders

   $ (153,326   $ (175,604   $ (80,224   $ 255,828    $ (153,326
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations    Consolidated  

Revenues:

           

Oil and natural gas

   $ 116,885      $ 70,940      $ 256,128      $ —      $ 443,953   

Midstream

     —          —          35,330        —        35,330   
                                       

Total revenues

     116,885        70,940        291,458        —        479,283   
                                       

Costs and expenses:

           

Oil and natural gas production

     38,367        24,726        81,445        —        144,538   

Midstream operating expenses

     —          —          35,580        —        35,580   

Gathering and transportation

     87        2,789        10,003        —        12,879   

Depreciation, depletion and amortization

     43,782        26,962        116,939        —        187,683   

Write-down of oil and natural gas properties

     279,632        282,073        731,874        —        1,293,579   

Gain on divestitures

     (98,581     —          (362,045     —        (460,626

Accretion of discount on asset retirement obligations

     1,444        2,661        1,751        —        5,856   

General and administrative

     12,186        11,996        40,500        —        64,682   
                                       

Total costs and expenses

     276,917        351,207        656,047        —        1,284,171   
                                       

Operating loss

     (160,032     (280,267     (364,589     —        (804,888

Other income (expense):

           

Interest expense

     (45,161     —          (84,599     —        (129,760

Gain on derivative financial instruments

     78,059        6,551        120,275        —        204,885   

Other income (expense)

     19,977        (23,921     (3,951     —        (7,895

Equity method loss in TGGT Holdings, LLC

     —          —          (426     —        (426

Equity in earnings of subsidiaries

     (630,927     —          —          630,927      —     
                                       

Total other income (expense)

     (578,052     (17,370     31,299        630,927      66,804   
                                       

Income (loss) before income taxes

     (738,084     (297,637     (333,290     630,927      (738,084

Income tax expense

     189        —          —          —        189   
                                       

Net income (loss)

     (738,273     (297,637     (333,290     630,927      (738,273

Preferred stock dividends

     —          —          —          —        —     
                                       

Net income (loss) available to common shareholders

   $ (738,273   $ (297,637   $ (333,290   $ 630,927    $ (738,273
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2008

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations    Consolidated  

Revenues:

           

Oil and natural gas

   $ 336,290      $ 167,819      $ 651,877      $ —      $ 1,155,986   

Midstream

     —          —          61,852        —        61,852   
                                       

Total revenues

     336,290        167,819        713,729        —        1,217,838   
                                       

Costs and expenses:

           

Oil and natural gas production

     57,734        26,653        93,139        —        177,526   

Midstream operating expenses

     —          —          59,671        —        59,671   

Gathering and transportation

     173        2,246        8,084        —        10,503   

Depreciation, depletion and amortization

     91,456        48,966        206,283        —        346,705   

Write-down of oil and natural gas properties

     198,440        359,350        635,315        —        1,193,105   

Accretion of discount on asset retirement obligations

     1,232        2,014        1,025        —        4,271   

General and administrative

     36,543        13,243        13,500        —        63,286   
                                       

Total costs and expenses

     385,578        452,472        1,017,017        —        1,855,067   
                                       

Operating loss

     (49,288     (284,653     (303,288     —        (637,229

Other income (expense):

           

Interest expense

     (51,525     —          (49,642     —        (101,167

Gain (loss) on derivative financial instruments

     (28,618     (9,478     (65,438     —        (103,534

Other income (expense)

     22,294        (18,865     2,067        —        5,496   

Equity in earnings of subsidiaries

     (606,593     —          —          606,593      —     
                                       

Total other income (expense)

     (664,442     (28,343     (113,013     606,593      (199,205
                                       

Income (loss) before income taxes

     (713,730     (312,996     (416,301     606,593      (836,434

Income tax expense (benefit)

     (141,648     (122,704     —          —        (264,352
                                       

Net income (loss)

     (572,082     (190,292     (416,301     606,593      (572,082

Preferred stock dividends

     (76,997     —          —          —        (76,997
                                       

Net income (loss) available to common shareholders

   $ (649,079   $ (190,292   $ (416,301   $ 606,593    $ (649,079
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2009

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations    Consolidated  

Operating Activities:

           

Net cash provided by operating activities

   $ 165,582      $ 10,649      $ 173,626      $ —      $ 349,857   
                                       

Investing Activities:

           

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

     (40,053     (44,402     (372,178     —        (456,633

Restricted cash

     —          (14,500     (55,483     —        (69,983

Equity investment in TGGT Holdings, LLC

     —          —          (47,500     —        (47,500

Deposit on pending property divestitures

     —          14,500        —          —        14,500   

Net proceeds from dispositions

     262,808        (46     1,146,616        —        1,409,378   

Advances/investments with affiliates

     (113,107     24,287        88,820        —        —     
                                       

Net cash provided by (used in) investing activities

     109,648        (20,161     760,275        —        849,762   
                                       

Financing Activities:

           

Borrowings under credit agreements

     14,979        —          37,970        —        52,949   

Repayments under credit agreements

     (312,500     —          (768,240     —        (1,080,740

Repayments under senior unsecured credit term agreement

     —          —          (300,000     —        (300,000

Proceeds from issuance of common stock, net

     5,400        —          —          —        5,400   

Settlement of derivative financial instruments with a financing element

     45,859        —          95,923        —        141,782   

Deferred financing costs and other

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

Net cash used in financing activities

     (251,648     —          (949,429     —        (1,201,077
                                       

Net increase (decrease) in cash

     23,582        (9,512     (15,528     —        (1,458

Cash at the beginning of the period

     8,617        12,360        36,162        —        57,139   
                                       

Cash at end of period

   $ 32,199      $ 2,848      $ 20,634      $ —      $ 55,681   
                                       

 

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2008

 

(in thousands)

   Resources     Guarantor
Subsidiaries
    Non-Guarantor
Subsidiaries
    Eliminations    Consolidated  

Operating Activities:

           

Net cash provided by operating activities

   $ 219,779      $ 89,856      $ 502,382      $ —      $ 812,017   
                                       

Investing Activities:

           

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

     (160,259     (156,431     (424,964     —        (741,654

Property and midstream acquisitions

     (400,660     (437     (344,122     —        (745,219

Advance on pending acquisition

     —          —          —          —        —     

Proceeds from dispositions of property and equipment

     1,288        282        166        —        1,736   

Advances/investments with affiliates

     3,179        64,439        (67,618     —        —     
                                       

Net cash used in investing activities

     (556,452     (92,147     (836,538     —        (1,485,137
                                       

Financing Activities:

           

Borrowings under credit agreements

     750,000        —          315,185        —        1,065,185   

Repayments under credit agreements

     (296,500     —          (179,700     —        (476,200

Borrowings under senior unsecured credit term agreement

     —          —          300,000        —        300,000   

Proceeds from issuance of common stock

     14,465        —          —          —        14,465   

Payment of preferred stock dividends

     (82,827     —          —          —        (82,827

Settlements of derivative financial instruments with a financing element

     (51,399     —          (45,105     —        (96,504

Deferred financing costs

     (707     —          (10,667        (11,374
                                       

Net cash provided by financing activities

     333,032        —          379,713        —        712,745   
                                       

Net increase (decrease) in cash

     (3,641     (2,291     45,557        —        39,625   

Cash at beginning of the period

     23,069        7,250        25,191        —        55,510   
                                       

Cash at end of period

   $ 19,428      $ 4,959      $ 70,748      $ —      $ 95,135   
                                       

 

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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 Haynesville/Bossier shale play in East Texas/North Louisiana and the Marcellus and Huron shale plays in Appalachia;

 

   

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;

 

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Table of Contents
   

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;

 

   

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;

 

   

events similar to those of September 11, 2001;

 

   

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, 2008.

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

Overview

We are an independent oil and natural gas company engaged in the acquisition, development and exploitation of onshore North American oil and natural gas properties. Our principal operations are located in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian producing areas. In addition to our oil and natural gas producing operations, we hold a 50% equity interest in a joint venture which owns gathering systems and pipelines in East Texas and North Louisiana. Our assets in East Texas and North Louisiana, including our equity interest in midstream operations, are owned by our subsidiary, EXCO Operating Company, LP, and its subsidiaries, collectively, EXCO Operating. Organizationally, EXCO Operating is an indirect wholly-owned subsidiary of EXCO Resources. EXCO Operating’s debt is not guaranteed by EXCO Resources and EXCO Operating does not guarantee EXCO Resources’ debt.

We currently have two credit agreements: one at EXCO Resources, or the EXCO Resources Credit Agreement, which currently has a borrowing base of $850.0 million and one at EXCO Operating, or the EXCO Operating Credit Agreement, which currently has a borrowing base of $850.0 million. 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 exploitation projects and entering into beneficial joint development agreements. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. We also have an asset divestiture program to supplement our development programs and enhance concentration on core operating areas, particularly the Haynesville and Marcellus shale resource plays. 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.

 

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Oil and natural gas prices have historically been volatile. On September 30, 2009, the spot market price for natural gas at Henry Hub was $3.30 per Mmbtu, a 53.7% decrease from September 30, 2008. The price of oil has also shown significant volatility, with a $70.43 per Bbl spot market price for oil at Cushing, Oklahoma at September 30, 2009, a 30.0% decrease from September 30, 2008. During the nine months ended September 30, 2009, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $50.89 per Bbl and $3.88 per Mcf, respectively, compared with the nine months ended September 30, 2008 average realized prices of $111.66 per Bbl and $9.96 per Mcf, respectively. It is impossible to predict the duration or outcome of these price declines, their long-term impact on drilling and operating costs and their impacts, whether favorable or unfavorable, to our results of operations and liquidity.

Like other 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 adding additional reserves through acquisitions.

At the end of the first quarter of 2009, we revised our expected capital expenditure estimate to approximately $500.0 million in response to price declines which affected our vertical drilling economics. We do not budget for acquisitions as these transactions are opportunistic in nature. Presently, our focus is on drilling and leasing activities in our Haynesville shale area in East Texas/North Louisiana. We expect our capital expenditures for 2009 will be approximately $535 million. If the estimated purchase price adjustment for capital expenditures since the effective date of the transactions with BG Group, plc, or BG Group, is considered, our 2009 capital expenditures would be approximately $400 million. Our future growth will depend upon our ability to continue to identify and add oil and natural gas reserves in excess of production at a reasonable cost. We plan to maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

In line with management’s divestiture goals established in the fourth quarter of 2008, we have completed the sale of certain assets, including our joint venture transactions with BG Group, resulting in net cash proceeds of approximately $1.4 billion after customary closing and post closing adjustments during the nine months ended September 30, 2009. We have reached agreements to close asset sales in the fourth quarter of 2009 for total proceeds of approximately $685.0 million, subject to customary closing adjustments.

On August 11, 2009, we closed a sale of properties located in East Texas, or the East Texas Transaction, to an affiliate of Encore Acquisition Company, or Encore. Pursuant to the East Texas Transaction, we sold all of our interests in certain oil and natural gas properties located in our Overton Field and Gladewater area of East Texas. We received $156.7 million in cash at closing, including customary preliminary closing adjustments.

Also on August 11, 2009, we closed a sale of properties located in Texas and Oklahoma, or the Mid-Continent Transaction, with Encore. Pursuant to the Mid-Continent Transaction, we sold all of our interests in certain oil and gas properties located in our Mid-Continent operating area. We received $199.4 million in cash at closing, after customary preliminary closing adjustments.

The proceeds from the East Texas Transaction and the Mid-Continent Transaction were used to pay down a portion of our revolving credit agreements.

On August 14, 2009, we closed a sale and joint development transaction with BG Group for the sale of an undivided 50% of our interest in an area of mutual interest, or AMI, which included most of our oil and natural gas assets in East Texas and North Louisiana (excluding the Vernon Field, Gladewater area, Overton Field and Redland Field), or the BG Upstream Transaction. The transaction with BG Group includes agreements for the joint development and operation of our Haynesville shale and certain other related natural gas assets located in the AMI. We received $727.0 million in cash at closing, including customary preliminary closing adjustments. Pursuant to this transaction, BG Group will also fund $400.0 million of capital development attributable to our 50% interest, with BG Group paying 75% of our share of drilling and completion costs on the deep rights (Haynesville and Bossier shales) until the $400.0 million commitment is satisfied. Under the terms of the agreement, BG Group funding of the $400.0 million commitment will be earned solely through drilling of deep right wells as defined in the agreement. There is no obligation by us to repay any of the $400.0 million commitment to BG Group. The joint development transaction had an effective date of January 1, 2009.

The transactions with Encore and BG Group caused a significant alteration to our full cost pool and a gain of $362.3 million was recorded as a result of these transactions.

In addition, on August 14, 2009, we also closed a sale to an affiliate of 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, or the BG Midstream Transaction. Our Vernon Field midstream assets were excluded from the BG Midstream Transaction. Pursuant to the contribution agreement, we contributed TGG Pipeline, Ltd., or TGG, which owns intrastate pipelines in East Texas and North

 

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Louisiana, and Talco Midstream Assets, Ltd., or Talco, which owns gathering assets in East Texas and North Louisiana, to TGGT. BG Group contributed $269.2 million in cash to TGGT and we received a special distribution from TGGT of the same amount at closing. EXCO Operating now owns 50% of TGGT and the affiliate of BG Group owns 50% of TGGT. We adopted the equity method of accounting for our interest in TGGT upon formation. The BG Midstream Transaction resulted in recognition of a gain of $98.3 million.

The total aggregate cash proceeds of $996.2 million from the BG Upstream Transaction and the BG Midstream Transaction were used to repay EXCO Operating’s $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, creation of an evergreen escrow funding account to develop the Haynesville operations, and a working capital contribution to TGGT, with the remainder applied to the outstanding balances under the EXCO Operating credit agreement.

On September 29, 2009 we reached an agreement with EV Energy Partners, L.P., along with certain institutional partnerships managed by EnerVest, Ltd., or EnerVest, to sell our Ohio and certain Northwestern Pennsylvania producing assets for $145.0 million, subject to customary purchase price adjustments. The sale is expected to close in November 2009 and is effective as of September 1, 2009.

On September 30, 2009 we reached an agreement with Sheridan Holding Company I, LLC to sell all of our remaining assets in Oklahoma for $540.0 million. The sale is expected to close in November 2009, after customary closing adjustments, and is effective as of October 1, 2009.

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, accounting for income taxes, and our equity investment 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, 2008, except for the policy related to our equity investment, which is addressed “Note 13. Equity investment” in our Notes to the Condensed Consolidated Financial Statements.

Recent accounting pronouncements

On June 30, 2009, the Financial Accounting Standards Board, or the FASB, issued Update No. 2009-01-Topic 105-Generally Accepted Accounting Principles-amendments based on-Statement of Financial Accounting Standards No. 168-The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, or ASU 2009-01. ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date ASU 2009-01 the Codification superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009.

On June 12, 2009, the FASB issued FASB Statement No. 167, “Amendments to FASB Interpretation No. 46(R),” or SFAS No. 167. SFAS No. 167 is a revision to FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and changes how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The statement will be effective for the first fiscal year beginning after November 15, 2009. As of September 30, 2009, we do not have any variable interest entities and as such, the final rule does not have an effect on our financial statements and disclosures.

On June 12, 2009, the FASB issued FASB Statement No. 166, “Accounting for Transfers of Financial Assets,” or SFAS No. 166. SFAS No. 166 is a revision to FASB Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and will require more information about transfers of financial assets, including securitization transactions, and where companies have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity,” changes the requirements for derecognizing financial assets, and requires additional disclosures. The statement will be effective for the first fiscal year beginning after November 15, 2009. We do not believe the adoption of this pronouncement will have a material impact on our financial statements.

 

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On May 28, 2009, the FASB issued FASB Accounting Standards Codification, or ASC Subtopic 855-10 for Subsequent Events. ASC 855-10 establishes general standards of accounting for and disclosure of transactions and events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It also requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. ASC 855-10 is effective for interim and annual periods ending after June 15, 2009.

On April 9, 2009, the FASB issued FASB ASC paragraph 820-10-65-4 for Fair Value Measurements and Disclosures. ASC 820-10-65-4 provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased and provides guidance on identifying circumstances that indicate a transaction is not orderly. ASC 820-10-65-4 also requires disclosures on inputs and valuation techniques used to measure fair value, along with any changes in valuation techniques and related inputs, and to define the major category for debt and equity securities to be majority security types as described in paragraph FASB ASU Section 320-10-50 for the Scope Section of Subtopic 305-10 for Investments – Debt and Equity Securities. ASC 820-10-65-4 is effective for interim periods ending after June 15, 2009. See “–Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 9, 2009, the FASB issued FASB ASC Section 825-10-65 for Derivatives and Hedging. ASC 825-10-65 amended Statement of Financial Accounting Standards, or SFAS, No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as annual financial statements. ASC 825-10-65 also amends APB Opinion No. 28, “Interim Financial Reporting” to require fair value disclosures in summarized financial information at interim reporting periods. ASC 825-10-65 was effective for interim periods ending after June 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

On April 1, 2009, the FASB issued FASB ASC Subtopic 805-20 for Business Combinations. ASC 805-20 amends and clarifies FASB SFAS No. 141 (revised 2007), “Business Combinations,” to give guidance on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This pronouncement was effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted ASC 805-20 on January 1, 2009.

In March 2008, the FASB issued FASB ASC Section 815-10-65 for Derivatives and Hedging. ASC 815-10-65 requires enhanced disclosure about the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk, and the company’s strategies and objectives for using derivative instruments. ASC 815-10-65 is effective for financial statements issued for fiscal years beginning after November 15, 2008, and as such, was adopted by us on January 1, 2009. See “Note 9. Derivative financial instruments and fair value measurements” in the Notes to Condensed Consolidated Financial Statements included in this Form 10-Q for the impact to our disclosures.

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. The effective date of the new accounting and disclosure requirements is for annual reports filed for fiscal years ending on or after December 31, 2009. Companies are not permitted to comply at an earlier date. Among other things, Release No. 33-8995:

 

   

Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

 

   

Permits the use of new technologies for determining oil and natural gas reserves;

 

   

Requires the use of average prices for the trailing twelve-month period in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

 

   

Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

 

   

Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

 

   

Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

We are currently evaluating the effect of adopting the final rule on our financial statements and oil and natural gas reserve estimates and disclosures.

 

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Our results of operations

A summary of key financial data for the three and nine months ended September 30, 2009 and 2008 related to our results of operations is presented below:

 

     Three months ended
September 30,
    Quarter change     Nine months ended
September 30,
    Year to date
change
 

(dollars in thousands, except per unit prices)

   2009     2008     2009-2008     2009     2008     2009-2008  

Production:

            

Oil (Mbbls)

     355        590        (235     1,367        1,643        (276

Natural gas (Mmcf)

     29,806        33,017        (3,211     96,598        97,687        (1,089

Total production (Mmcfe) (1)

     31,936        36,557        (4,621     104,800        107,545        (2,745

Oil and natural gas revenues before derivative financial instrument activities:

            

Oil

   $ 22,678      $ 68,456      $ (45,778   $ 69,571      $ 183,454      $ (113,883

Natural gas

     102,815        333,951        (231,136     374,382        972,532        (598,150
                                                

Total oil and natural gas

   $ 125,493      $ 402,407      $ (276,914   $ 443,953      $ 1,155,986      $ (712,033
                                                

Midstream operations: (2)

            

Midstream revenues (before intersegment eliminations)

   $ 14,271      $ 49,258      $ (34,987   $ 76,478      $ 105,915      $ (29,437

Midstream operating expenses (before intersegment eliminations)

     9,983        41,410        (31,427     56,372        79,000        (22,628
                                                

Midstream operating profit (before intersegment eliminations)

     4,288        7,848        (3,560     20,106        26,915        (6,809

Intersegment eliminations

     (4,324     (9,664     5,340        (20,356     (24,734     4,378   
                                                

Midstream operating income (loss) (after intersegment eliminations)

   $ (36   $ (1,816   $ 1,780      $ (250   $ 2,181      $ (2,431
                                                

Oil and natural gas derivative financial instruments:

            

Cash settlements (payments) on derivative financial instruments

   $ 113,563      $ (70,019   $ 183,582      $ 354,131      $ (157,383   $ 511,514   

Non-cash change in fair value of derivative financial instruments

     (99,045     970,332        (1,069,377     (149,246     53,849        (203,095
                                                

Total derivative financial instrument activities

   $ 14,518