ITEM 1. BUSINESS
General
Unless the context requires otherwise, references in this annual report to “EXCO,” “we,” “us,” and “our” are to EXCO Resources, Inc., or EXCO Resources, its consolidated subsidiaries and EXCO Holdings Inc., or EXCO Holdings, our former parent company, which merged into and was acquired by EXCO Holdings II, Inc., or Holdings II, in October 2005. On February 14, 2006, EXCO Holdings merged with and into EXCO Resources concurrent with our initial public offering, or IPO. As such, all periods presented reflect the merger and include EXCO Holdings.
The year ended December 31, 2004 and the period beginning January 1, 2005 and ending on October 2, 2005 are referred to as predecessor. The predecessor period represents the accounting period up to the Equity Buyout. For more information about the Equity Buyout, see “-Significant transactions during 2005.” The period beginning October 3, 2005 and ending on December 31, 2006 is referred to as successor.
We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of selected oil and natural gas terms” beginning on page 26.
EXCO Resources, a Texas corporation incorporated in October 1955, 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 operations are focused in key North American oil and natural gas areas including East Texas/North Louisiana, Appalachia, Mid-Continent and Permian. As of December 31, 2006, our Proved Reserves were approximately 1.2 Tcfe, of which 92% were natural gas and 60% were Proved Developed Reserves. As of December 31, 2006, the related PV-10 of our Proved Reserves was $1.6 billion, and the Standardized Measure of our Proved Reserves was $1.3 billion (see “-Summary of geographic areas of operation” for a reconciliation of PV-10 to Standardized Measure of Proved Reserves). For the twelve months ended December 31, 2006, we produced 49.6 Bcfe of oil and natural gas. Based on our December 2006 average daily production, this translates to a reserve life of approximately 16.8 years. For the twelve month period ended December 31, 2006, we generated $355.8 million of oil and natural gas revenues.
We are a party to two pending acquisitions from Anadarko Petroleum Corporation and its affiliates, or Anadarko, that we expect will have a significant impact on our results of operations and financial condition during 2007. In January 2007, we sold our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado for $131.9 million. For more information about the pending acquisitions from Anadarko and the sale of our Wattenberg Field operations, see “-Significant subsequent events.” On February 14, 2007, we issued a press release pursuant to Rule 135c of the Securities Act of 1933 to announce a proposed private placement of up to $2.0 billion of preferred stock. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity, capital resources and capital commitments-Proposed recapitalization.”
Our business strategy
We plan to achieve reserve, production, and cash flow growth by executing our strategy as highlighted below:
· Exploit our multi-year, development inventory
We have a multi-year inventory of development drilling locations and exploitation projects. This inventory consists of step-out drilling, infill drilling, workovers, and recompletions. From January 1, 2004 to December 31, 2006, we drilled 584 wells and completed 572 wells resulting in a 98% drilling
success rate. We have identified over 6,225 drilling locations and exploitation projects across our properties.
· Seek acquisitions that meet our strategic and financial objectives
We maintain a disciplined acquisition process to seek and acquire properties that have established production histories and value enhancement potential through development drilling and exploitation projects. Our acquisitions of North Coast Energy, Inc., or North Coast, in the Appalachian Basin, TXOK Acquisition, Inc., or TXOK, in the East Texas and the Mid-Continent areas and Winchester Energy Company, Ltd., or Winchester, in the East Texas and North Louisiana areas and our pending acquisitions from Anadarko are examples of this strategy.
· Actively manage our portfolio and associated costs
We review our properties to identify cost savings opportunities and divestiture candidates. We actively seek to dispose of properties with higher operating costs and properties that are not within our core geographic operating areas. We also seek to opportunistically divest properties in areas in which acquisitions and investment economics no longer meet our objectives, most notably evidenced by the sale of our Canadian operations for $443.4 million in February 2005 and the sale of our Wattenberg Field operations in Colorado for $131.9 million in January 2007.
· Maintain financial flexibility
We employ the use of debt and equity along with a comprehensive derivative financial instrument program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure.
Our strengths
We have a number of strengths that we believe will help us successfully execute our strategy.
· Experienced management team with significant employee ownership
Our management team has led both public and private oil and natural gas companies over the past 20 years and has an average of over 26 years of industry experience in acquiring, developing, and exploiting oil and natural gas properties. Our management team first purchased a significant ownership interest in us in December 1997, and since then we have achieved substantial growth in reserves and production. Since the beginning of 1998, we have increased our Proved Reserves from 4.7 Bcfe to 1.2 Tcfe at December 31, 2006, and our average daily production increased from less than 1 Mmcfe per day in 1997 to 200.0 Mmcfe per day in December 2006. Importantly, as of March 1, 2007, our management team and employees (excluding our outside directors) own approximately 9.3% of our fully-diluted capital stock and our outside directors or their affiliates own approximately 15.4% of our fully-diluted capital stock, which aligns their objectives with those of our shareholders.
· High quality asset base in attractive regions
We own and plan to maintain a geographically diversified reserve base. Our principal operations are in the East Texas/North Louisiana, Appalachia, Mid-Continent and Permian areas. Our properties are generally characterized by:
· long reserve lives;
· a multi-year inventory of development drilling and exploitation projects;
· high drilling success rates; and
· a high natural gas concentration.
· Operational control
We operate a significant portion of our properties, which permits us to manage our operating costs and better control capital expenditures as well as the timing of development and exploitation activities. As of December 31, 2006, we were the operator of 7,794 gross wells which represented 90% of our Proved Reserves.
Significant transactions during 2005
Sale of Addison. On February 10, 2005, we sold Addison Energy Inc., or Addison, our former wholly-owned subsidiary through which all of our Canadian operations were conducted, for an aggregate sales price of Cdn. $551.3 million ($443.4 million). Of this amount, Cdn. $90.1 million ($72.1 million) was used to repay in full all outstanding balances under Addison’s credit facility, while Cdn. $56.2 million ($45.2 million) was withheld and was remitted to the Canadian government for estimated income taxes resulting from the sale of the stock. Prior to the sale of Addison, on February 9, 2005, Addison made an earnings and profits dividend (as calculated under U.S. tax law) to us in an amount of Cdn. $74.5 million ($59.6 million). The dividend was subject to Canadian tax withholding of Cdn. $3.7 million ($3.0 million). See “Note 5. Sale of Addison Energy Inc.” of the notes to our consolidated financial statements for additional information.
TXOK acquisition. On September 16, 2005, Holdings II formed TXOK for the purpose of acquiring ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C., collectively ONEOK Energy. Prior to TXOK’s acquisition of ONEOK Energy, we owned all of the issued and outstanding common stock of TXOK and BP EXCO Holdings LP, an entity controlled by Mr. Boone Pickens, one of our directors, held all of the outstanding shares of TXOK preferred stock. On September 27, 2005, TXOK completed the acquisition of ONEOK Energy for an aggregate purchase price of approximately $634.8 million after contractual adjustments. Effective upon closing, ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C. became wholly-owned subsidiaries of TXOK. We purchased an additional $20.0 million of common stock of TXOK on October 7, 2005, which investment represented an 11% equity interest and a 10% voting interest in TXOK. The preferred stock of TXOK held by BP EXCO Holdings LP represented the remaining 89% equity interest and 90% voting interest of TXOK.
TXOK funded the acquisition of ONEOK Energy with (i) $20.0 million in private debt financing, $15.0 million of which was provided by Mr. Boone Pickens, one of our directors, which has since been repaid; (ii) the issuance of $150.0 million of the 15% Series A Convertible Preferred Stock of TXOK, or the TXOK preferred stock, to BP EXCO Holdings LP, an entity controlled by Mr. Pickens; (iii) approximately $308.8 million of borrowings under the revolving credit facility of TXOK, or the TXOK credit facility; and (iv) $200.0 million of borrowings under the second lien term loan facility of TXOK, or the TXOK term loan.
Concurrent with our IPO on February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights of TXOK. The redemption price for the TXOK preferred stock was (a) cash in the amount of approximately $158.8 million and (b) 388,889 shares of common stock of EXCO Resources. Once the TXOK preferred stock was redeemed, our acquisition of TXOK, or the TXOK acquisition, was complete and it became our wholly-owned subsidiary. The properties TXOK acquired in the TXOK acquisition included 1,057 gross (453.1 net) producing oil and natural gas wells in Texas and Oklahoma at December 31, 2005. TXOK had Proved Reserves, estimated as of December 31, 2005, of approximately 223.7 Bcfe of oil and natural gas, and 151 miles of natural gas gathering lines. The acquired properties produced an average of 970 Bbls of oil per day and 46.9 Mmcf of natural gas per day during 2005. For more information about the TXOK acquisition, see “Note 16. Related party transactions” of the notes to our consolidated financial statements.
Equity Buyout. On October 3, 2005, Holdings II, an entity formed by our management, purchased 100% of the outstanding equity securities of EXCO Holdings in an equity buyout, or the Equity Buyout, for an aggregate price of approximately $699.3 million, resulting in a change of control and a new basis of accounting. To fund the Equity Buyout, Holdings II raised $350.0 million in interim debt financing, including $0.7 million for working capital, from a group of lenders and $183.1 million of equity financing from new institutional and other investors as well as stockholders of EXCO Holdings. In addition, management and other stockholders of EXCO Holdings exchanged $166.9 million of their EXCO Holdings common stock for Holdings II common stock. EXCO Holdings’ majority stockholder sold all of its EXCO Holdings common stock for cash. Promptly following the completion of the Equity Buyout, Holdings II merged with and into EXCO Holdings. As a result of the merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of EXCO Holdings common stock and all shares of EXCO Holdings common stock held by Holdings II were cancelled. For more information about the Equity Buyout, see “Note 1. Organization-The Equity Buyout” of the notes to our consolidated financial statements.
Repurchase of senior notes pursuant to a change of control tender offer. In connection with the Equity Buyout, we were required to offer to repurchase our 7¼% Senior Notes due 2011, or senior notes, for a purchase price of 101%. As a result, we repurchased $5.3 million principal amount of senior notes on December 13, 2005.
Significant transactions during 2006
Initial public offering. On February 14, 2006, EXCO Resources completed its IPO of 50,000,000 shares of its common stock for aggregate net proceeds to EXCO Resources of $617.5 million after underwriters’ discount. J.P. Morgan Securities Inc., Bear, Stearns & Co. Inc. and Goldman, Sachs & Co. acted as joint book running managers for the IPO.
The net proceeds from the IPO, together with cash on hand and additional borrowings under EXCO’s credit agreement, were used as follows:
· $360.0 million to repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred in connection with the Equity Buyout;
· $158.8 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends and redemption premium, issued to a related party in connection with the acquisition of ONEOK Energy;
· $375.5 million to repay $171.8 million in principal plus accrued and unpaid interest of $0.9 million under the TXOK credit facility and $200.0 million in principal plus accrued and unpaid interest of $2.8 million under the TXOK term loan, both loans having been incurred in connection with the acquisition of ONEOK Energy; and
· $6.0 million to pay fees and expenses in connection with the IPO.
Concurrent with the consummation of the IPO, including the redemption of the TXOK preferred stock, EXCO Holdings merged with and into EXCO Resources, with EXCO Resources as the surviving corporation. The outstanding shares of EXCO Holdings common stock were cancelled as a result of the merger and such shares were exchanged for the same number of shares of EXCO Resources common stock. As a result of the merger, TXOK became a wholly-owned subsidiary of EXCO Resources and TXOK and its subsidiaries became guarantors under the indenture governing our senior notes, or the Indenture. EXCO Resources also became a guarantor under the TXOK credit facility and TXOK likewise became a guarantor under EXCO Resources’ credit agreement.
On February 21, 2006, EXCO Resources issued 3,615,200 additional shares of its common stock pursuant to an exercise by the underwriters of their over-allotment option for net proceeds to EXCO Resources of approximately $44.7 million. The net proceeds were used to reduce outstanding indebtedness under EXCO Resources’ credit agreement.
Summary of 2006 acquisition activity. During 2006, we completed the following acquisitions of oil and natural gas properties and undeveloped acreage, including the acquisition of Winchester, our largest acquisition to date. A summary of these acquisitions and the values allocated to oil and natural gas properties and gathering facilities, net of contractual adjustments, is presented on the following table.
Details of the components of the purchase price and related allocation of the purchase price to the acquired assets and liabilities of our corporate acquisitions in 2006 are as follows:
Redemption of preferred stock and acquisition of TXOK. On February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights and an 89% economic interest in TXOK. The redemption price for the TXOK preferred stock was cash in the amount of $150.0 million plus $8.8 million of unpaid dividends at a rate of 15% and 388,889 shares of our common stock. The EXCO common stock issued in connection with the preferred redemption represented the value necessary to produce an overall 23% annualized rate of return on the stated value of the TXOK preferred stock as of the date of redemption pursuant to the terms of the preferred stock agreement. For purposes of calculating the rate of return, the common stock of EXCO was valued at $12.00 as required by the terms of the TXOK preferred stock. Once the TXOK preferred stock was redeemed, our acquisition of TXOK was complete and it became our wholly-owned subsidiary. We accounted for the acquisition of TXOK as a step acquisition using the purchase method of accounting and began consolidating its operations effective February 14, 2006. As a result, 89% of the fair value of the assets and liabilities of TXOK was recorded at the redemption date and the remaining 11% was recorded as an adjustment to book value as of the date of the initial investment. The total purchase price of TXOK was $665.1 million representing the redemption of the TXOK preferred stock, the initial investment in TXOK common stock and the assumption of liabilities.
Acquisition of Power Gas Marketing & Transmission, Inc. On April 28, 2006, our wholly-owned subsidiary, North Coast, closed an acquisition of 100% of the common stock of Power Gas Marketing & Transmission, Inc., or PGMT, for a purchase price of $115.0 million before contractual adjustments, and a net purchase price of $113.0 million. The purchase price included the assumption of $13.1 million of debt and $38.1 million of derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under the EXCO Resources credit agreement, we paid the assumed debt and terminated the assumed derivative financial instruments. The acquisition was accounted for as a purchase in accordance with Statement of Financial Accounting Standards, or SFAS, No. 141 “Accounting for Business Combinations,” or SFAS No. 141.
Winchester acquisition. On October 2, 2006, our wholly-owned subsidiary, Winchester Acquisition, LLC, or Winchester Acquisition, acquired Winchester and its affiliated entities from Progress Fuels Corporation, or PFC, for approximately $1.1 billion in cash. The acquisition consisted of producing and undeveloped oil and natural gas properties located in East Texas and North Louisiana, six gathering systems with approximately 300 miles of pipe and a 53 mile pipeline system. The average acquired working interest was 76% with an average 58% net revenue interest. The properties are located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. As of the closing date, the properties included approximately 734 gross drilling locations, 48% of which were proved, and approximately 114,000 net acres of leasehold of which 63% was held by production.
Concurrent with the acquisition, we contributed Winchester Acquisition to our wholly-owned subsidiary, EXCO Partners, LP, or EXCO Partners. Accordingly, Winchester Acquisition is now an indirect subsidiary of EXCO Partners. In addition, we also contributed all of our East Texas oil and natural gas properties, related pipeline and gathering systems, compressors and other production related equipment, and contracts, including financial derivative instruments associated with our East Texas production, to EXCO Partners in exchange for a payment to EXCO Resources of $150.0 million in cash. The proceeds were applied to reduce indebtedness outstanding under the EXCO Resources credit agreement. Included in the assets conveyed to EXCO Partners were four of our subsidiaries, ROJO Pipeline, LP (f/k/a ROJO Pipeline, Inc.), TXOK Energy Resources Holdings, LLC, TXOK Texas Energy Holdings, LLC and TXOK Texas Energy Resources, L.P. Following the equity contribution, these entities are no longer guarantors or restricted subsidiaries under the EXCO Resources credit agreement or the Indenture. EXCO Partners, its subsidiaries and its general partners are deemed unrestricted subsidiaries under the Indenture and the EXCO Resources credit agreement.
To finance the acquisition and the $150.0 million payment to EXCO Resources for our East Texas assets, EXCO Partners’ wholly-owned subsidiary, EXCO Partners Operating Partnership, LP, or EPOP, entered into a Senior Revolving Credit Agreement, or EPOP Revolving Credit Facility, and a Senior Term Credit Agreement, or EPOP Senior Term Credit Agreement with a group of lenders led by JPMorgan Chase Bank, N.A. In connection with the arrangement of the EPOP Senior Term Credit Agreement, the lenders required us to enter into an Equity Contribution Agreement, or Contribution Agreement, dated October 2, 2006, as amended and restated on October 4, 2006 and October 13, 2006. For more information about the EPOP Revolving Credit Facility, the EPOP Senior Term Credit Agreement and the Contribution Agreement, see “Item 7. Management’s discussion and analysis of financial condition and results of operations-Our liquidity, capital resources and capital commitments.”
Significant subsequent events
Pending acquisition of Vernon Assets
On December 22, 2006, Vernon Holdings, LLC, or Vernon, our wholly-owned subsidiary, entered into a Purchase and Sale Agreement, or the Vernon Purchase Agreement, with Anadarko Petroleum Corporation and Anadarko Gathering Company. Subject to the terms and conditions in the Vernon Purchase Agreement, Vernon will acquire substantially all of the oil and natural gas properties and related assets, including derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009, or collectively the Vernon Assets, of Anadarko in the Vernon and Ansley Fields located in Jackson Parish, Louisiana.
Vernon will pay Anadarko a purchase price of approximately $1.6 billion in cash for the Vernon Assets, subject to certain purchase price adjustments. The purchase price will be: (i) reduced by proceeds earned (including, from the sale of hydrocarbons), and increased by costs incurred, with respect to the operation of the Vernon Assets during the period from 7:00 a.m., local time, on November 1, 2006, or the Effective Time, to the closing date, (ii) reduced by the aggregate amount of material title defects and material environmental defects exceeding $32.0 million, (iii) increased by the aggregate amount of material aggregate title benefits exceeding $32.0 million, (iv) reduced by the aggregate amounts payable to owners of working interests and other interests in the Vernon Assets held in suspense as of the closing date, (v) increased or reduced by the net amount of any gas imbalances as of the Effective Time, and (vi) increased by the value of merchantable stored hydrocarbons attributable to the Vernon Assets as of the Effective Time. In connection with the acquisition, derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009 were entered into by the seller and will be assumed by EXCO.
The Vernon Purchase Agreement contains customary representations, warranties and covenants. The acquisition is expected to close on or about March 30, 2007, subject to the satisfaction of various closing conditions, including, among others, (i) the aggregate amount of uncured title defects, environmental defects and casualty losses, net of title benefits, not exceeding $160.0 million and (ii) the sum of allocated values not exceeding $32.0 million for any Vernon Assets that are retained by Anadarko because of the failure to obtain, prior to closing, third-party consents required to transfer such Vernon Assets.
Concurrently with the execution of the Vernon Purchase Agreement, Vernon deposited with Anadarko an earnest money deposit in the amount of $80.0 million to be applied against the purchase price at closing or, if Anadarko terminates the Vernon Purchase Agreement because Vernon has materially breached Vernon’s representations, warranties or covenants under the Vernon Purchase Agreement, to be retained by Anadarko, as its sole and exclusive remedy, as liquidated damages. If the Vernon Purchase Agreement is terminated for any reason other than as stated in the preceding sentence, Anadarko is obligated to return the deposit to Vernon.
Anadarko has agreed to indemnify Vernon after the closing, subject to certain limitations, for losses incurred by Vernon to the extent resulting from, arising out of or relating to (i) Anadarko’s breach of any representation or warranty of Anadarko contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (ii) Anadarko’s failure to perform any covenant or agreement contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (iii) liabilities associated with assets or properties not part of the Vernon Assets, (iv) scheduled litigation and other proceedings and other litigation and other proceedings that arise out of or are attributable to Anadarko’s ownership or operation of the Vernon Assets after December 22, 2006 but before the closing, (v) litigation and other proceedings that arise after closing for personal injury or death arising and occurring before the closing which is attributable to Anadarko’s ownership or operation of the Vernon Assets, (vi) obligations or liabilities attributable to scheduled incidences of noncompliance with laws by Anadarko, (vii) certain retained employee liabilities, and (viii) any off-site environmental liabilities occurring prior to the closing that relate to the Vernon Assets. Vernon has agreed to indemnify Anadarko after the closing, subject to certain limitations, for losses incurred by Anadarko to the extent resulting from, arising out of or relating to (a) Vernon’s breach of any representation or warranty of Vernon contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (b) Vernon’s failure to perform any covenant or agreement contained in the Vernon Purchase Agreement or in any certificates furnished in connection therewith, (c) the ownership, use or operation of the Vernon Assets after the Effective Time, (d) other than off-site environmental liabilities retained by Anadarko, any environmental liabilities associated with the Vernon Assets, and (e) certain obligations and liabilities of Anadarko with respect to the Vernon Assets that will be assumed by Vernon at the closing. Neither Anadarko, on the one hand, nor Vernon, on the other hand, will be obligated to indemnify the other (and other related indemnified persons specified in the Vernon Purchase Agreement) for losses until the amount of all losses incurred by such person and such other indemnified persons exceeds, in the aggregate, $40.0 million, in which event the party seeking indemnification may recover all losses incurred in excess of $40.0 million, up to a maximum liability of $400.0 million.
On December 22, 2006, in connection with the Vernon Purchase Agreement, EXCO entered into a guaranty agreement, or Vernon Guaranty, with Anadarko to guarantee Vernon’s payment obligations and Vernon’s performance of all covenants required to be performed by it pursuant to the terms of the Vernon Purchase Agreement and ancillary documents delivered in connection therewith. EXCO is the primary obligor under the Vernon Guaranty and must pay or perform, or cause the payment or performance, of any obligation not punctually paid or performed when due by Vernon. EXCO is not obligated to pay or perform any obligation to the extent that Vernon would not be required to pay or perform such obligation due to any defenses available to Vernon.
Pending acquisition of Southern Gas Assets
On February 1, 2007, EXCO Resources entered into a Purchase and Sale Agreement, or the Southern Gas Purchase Agreement, with Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, whereby, subject to the terms and conditions in the Southern Gas Purchase Agreement, EXCO Resources will acquire substantially all of the oil and natural gas properties and related assets, including derivative financial instruments in respect of a significant portion of estimated production for 2007, 2008 and 2009, or collectively the Southern Gas Assets, of Anadarko in multiple fields located in the Mid-Continent, South Texas and Gulf Coast areas, which fields are primarily located in Oklahoma, Texas and Louisiana.
EXCO Resources will pay Anadarko a purchase price of approximately $860.0 million in cash for the Southern Gas Assets, subject to certain purchase price adjustments. The purchase price will be: (i) reduced by proceeds earned (including, from the sale of hydrocarbons), and increased by costs incurred, with respect to the operation of the Southern Gas Assets during the period from 7:00 a.m., local time, on
January 1, 2007, or the Effective Date, to the closing date, (ii) reduced by the value of any Southern Gas Asset not conveyed to EXCO in the event a required preference right or transfer requirement has not been satisfied or waived as of the closing, (iii) reduced by the aggregate amount of material title defects and material environmental defects exceeding $17.0 million, (iv) increased by the aggregate amount of material aggregate title benefits exceeding $17.0 million, (v) reduced by the aggregate amounts payable to owners of working interests and other interests in the Southern Gas Assets held in suspense as of the closing date, (vi) reduced by the net amount of any gas imbalances as of the Effective Date, and (vii) increased by the value of merchantable stored hydrocarbons attributable to the Southern Gas Assets as of the Effective Date.
The Southern Gas Purchase Agreement contains customary representations, warranties and covenants. The acquisition is expected to close on or about May 2, 2007, subject to the satisfaction of various closing conditions, including, among others, (i) the termination of any applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (ii) the aggregate amount of uncured title defects, environmental defects and casualty losses, net of title benefits, not exceeding $86.0 million, and (iii) the sum of allocated values not exceeding $17.2 million for any Southern Gas Assets that are retained by Anadarko because of the failure to obtain, prior to closing, third-party consents required to transfer such Southern Gas Assets.
In connection with the execution of the Southern Gas Purchase Agreement, EXCO Resources deposited with Anadarko an earnest money deposit in the amount of $43.0 million to be applied against the purchase price at closing or, if Anadarko terminates the Southern Gas Purchase Agreement because EXCO Resources has materially breached its representations, warranties or covenants under the Southern Gas Purchase Agreement, to be retained by Anadarko, as its sole and exclusive remedy, as liquidated damages. If the Southern Gas Purchase Agreement is terminated for any reason other than as stated in the preceding sentence, Anadarko is obligated to return the deposit to EXCO Resources.
Anadarko has agreed to indemnify EXCO Resources after the closing, subject to certain limitations, for losses incurred by EXCO Resources to the extent resulting from, arising out of or relating to (i) Anadarko’s breach of any representation or warranty of Anadarko contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (ii) Anadarko’s failure to perform any covenant or agreement contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (iii) liabilities associated with assets or properties not part of the Southern Gas Assets, (iv) certain scheduled litigation and other proceedings and other litigation and other proceedings that arise out of or are attributable to Anadarko’s ownership or operation of the Southern Gas Assets after February 1, 2007 but before the closing, (v) litigation and other proceedings that arise after closing for personal injury or death arising and occurring before the closing which is attributable to Anadarko’s ownership or operation of the Southern Gas Assets, (vi) obligations or liabilities attributable to scheduled incidences of noncompliance with laws by Anadarko, (vii) certain retained employee liabilities, and (viii) any off-site environmental liabilities occurring prior to the closing that relate to the Southern Gas Assets. EXCO Resources has agreed to indemnify Anadarko after the closing, subject to certain limitations, for losses incurred by Anadarko to the extent resulting from, arising out of or relating to (a) EXCO Resources’ breach of any representation or warranty contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (b) EXCO Resources’ failure to perform any covenant or agreement contained in the Southern Gas Purchase Agreement or confirmed in any certificate furnished in connection therewith, (c) the ownership, use or operation of the Southern Gas Assets after the Effective Date, (d) other than off-site environmental liabilities retained by Anadarko, any environmental liabilities associated with the Southern Gas Assets, and (e) certain obligations and liabilities of Anadarko with respect to the Southern Gas Assets that will be assumed by EXCO Resources at the closing. Neither Anadarko, on the one hand, nor EXCO Resources, on the other hand, will be obligated to indemnify the other (and other related indemnified persons
specified in the Southern Gas Purchase Agreement) for losses until the amount of all losses incurred by such person and such other indemnified persons exceeds, in the aggregate, $21.5 million, in which event the party seeking indemnification may recover all losses incurred in excess of $21.5 million, up to a maximum liability of $215.0 million.
In connection with the pending acquisitions, the following derivative financial instruments covering estimated production for 2007, 2008 and 2009 were entered into by the seller and will be assumed by us:
Vernon Assets
Southern Gas Assets
To ensure that EXCO has sufficient financing to complete the acquisitions from Anadarko of oil and natural gas properties in the Vernon and Ansley Fields in Jackson Parish, Louisiana, EXCO received a revised commitment letter dated as of February 1, 2007, from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A. This commitment letter supersedes and replaces the commitment letter we received on December 22, 2006, in conjunction with our entering into the Vernon Purchase Agreement. The new commitment letter, as subsequently supplemented, provides for a senior secured revolving credit facility commitment in the amount of $1.8 billion and an undertaking to arrange a bridge loan facility in the amount of $1.1 billion if requested, or collectively the new credit facilities. If used to finance these acquisitions, the new credit facilities will contain customary representations, warranties and covenants, and the closing of the new credit facilities will be subject to the satisfaction of customary closing conditions. EXCO is also pursuing other financing alternatives, including a proposed private placement of preferred stock. For a discussion of the proposed terms of the preferred stock, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity, capital resources and capital commitments-Proposed recapitalization.”
Sale of Wattenberg Field
In January 2007, we completed the sale of our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. The transaction included substantially all of our assets in the area. Proved reserves sold were approximately 55.7 Bcfe. The adjusted purchase price paid at closing was $131.9 million.
Summary of geographic areas of operation
The following tables set forth summary operating information attributable to our principal geographic areas of operation as of December 31, 2006:
(1) The total Proved Reserves and PV-10 of the Proved Reserves as used in this table were prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. For each area set forth in the table, the Proved Reserves and PV-10 were determined by our internal engineers.
(2) The PV-10 data used in this table is based on December 31, 2006 spot prices of $5.64 per Mmbtu for natural gas and $60.82 per Bbl for oil, in each case adjusted for historical differentials. Market prices for oil and natural gas are volatile. See “Item 1A.
ITEM 1A. RISK FACTORS
The risk factors noted in this section and other factors noted throughout this annual report, including those risks identified in “Item 7. Management’s discussion and analysis of financial condition and results of
operations,” describe examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this annual report.
Risks relating to our business
Fluctuations in oil and natural gas prices, which have been volatile at times, may adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or future indebtedness and obtain additional capital on attractive terms.
Our future financial condition, access to capital, cash flow and results of operations depend upon the prices we receive for our oil and natural gas. We are particularly dependent on prices for natural gas. As of December 31, 2006, 92% of our Proved Reserves were natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Factors that affect the prices we receive for our oil and natural gas include:
· the level of domestic production;
· the availability of imported oil and natural gas;
· political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
· the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
· the cost and availability of transportation and pipeline systems with adequate capacity;
· the cost and availability of other competitive fuels;
· fluctuating and seasonal demand for oil and natural gas;
· conservation and the extent of governmental price controls and regulation of production;
· weather;
· foreign and domestic government relations; and
· overall economic conditions.
Our revenues and our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms depend substantially upon oil and natural gas prices.
Our use of derivative financial instruments may cause us to forego additional future profits or result in our making cash payments.
To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into derivative financial instrument arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Derivative financial instruments expose us to the risk of financial loss and may limit our ability to benefit from increases in oil and natural gas prices in some circumstances, including the following:
· the counterparty to the derivative financial instrument contract may default on its contractual obligations to us;
· there may be a change in the expected differential between the underlying price in the derivative financial instrument agreement and actual prices received; or
· market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments.
Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our common stock, and making it more difficult for us to pay dividends on our common stock. During the year ended December 31, 2005, we made cash settlement payments on our derivative financial instrument contracts totaling $85.0 million. During the year ended December 31, 2006, we received cash settlements from our counterparties totaling $29.4 million. For the year ended December 31, 2006, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments (or a decrease in settlements received) of approximately $30.0 million. As of December 31, 2006, the net unrealized gains on our derivative financial instrument contracts was $96.4 million. The ultimate settlement amount of these unrealized derivative financial instrument contracts is dependent on future commodity prices. In connection with the acquisitions of TXOK and Winchester, we assumed additional derivative financial instruments that TXOK and Winchester had entered into covering a significant portion of their estimated future production. In connection with the pending acquisitions of the Vernon Assets and the Southern Gas Assets, we expect to assume additional derivative financial instruments from Anadarko covering a significant portion of estimated future production. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place. See “Item 7. Management’s discussion and analysis of financial condition and results of operations-Our liquidity, capital resources and capital commitments-Derivative financial instruments.”
We will face risks associated with our recent and pending acquisitions relating to difficulties in integrating operations, potential disruptions of operations, and related negative impact on earnings.
The acquisitions of TXOK and Winchester represented a significant increase in our reserves and production. These acquisitions are the largest acquisitions that we have completed to date. As a result of the TXOK and Winchester acquisitions, as of December 31, 2006, we added 1,751 gross (1,042.7 net) wells to our consolidated portfolio of wells, including approximately 1,083 gross operated wells, which materially increased the number of wells we currently operate. If the pending acquisitions of the Vernon Assets for $1.6 billion in cash, subject to post-closing purchase price adjustments, and the Southern Gas Assets for $860.0 million in cash, subject to post-closing purchase price adjustments, are consummated, they will be significant acquisitions for us. We expect to add approximately 1,677 gross wells in connection with the pending acquisitions from Anadarko.
All of these factors present significant integration challenges for us. In addition to the other general acquisition risks described elsewhere in this section, the magnitude of theses acquisitions could strain our managerial, financial, accounting, technical, operational and administrative resources, disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards as well as our internal controls and procedures. We may not be successful in overcoming these risks or any other problems encountered in connection with these acquisitions, all of which could negatively impact our results of operations and our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.
We incurred a substantial amount of indebtedness to fund the acquisition of Winchester, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.
Concurrent with the acquisition of Winchester, we contributed Winchester Acquisition to our wholly-owned subsidiary, EXCO Partners. In addition, we also contributed all of our East Texas oil and natural gas properties, related pipeline and gathering systems, compressors and other production related equipment, and contracts, including financial derivative instruments associated with our East Texas production, to EXCO Partners in exchange for a payment to us of $150.0 million in cash. To finance the acquisition and the $150.0 million payment to us for our East Texas assets, EXCO Partners’ wholly-owned subsidiary, EPOP, entered into the EPOP Revolving Credit Facility. The initial amount borrowed under this facility was $651.0 million at closing of the acquisition of Winchester. As of December 31, 2006, $643.5 million was outstanding under the EPOP Revolving Credit Facility. In connection with the acquisition and our asset contribution, EPOP also entered into the EPOP Senior Term Credit Agreement. The aggregate principal amount of the Senior Term Credit Agreement is $650.0 million.
In connection with the arrangement of the Senior Term Credit Agreement, the lenders required us to enter into the Contribution Agreement. The Contribution Agreement generally provides that on the date 18 months from the Equity Contribution Date, we will make a cash common equity contribution to EPOP in an amount equal to the lesser of (i) $150.0 million or (ii) the aggregate amount then outstanding under the Senior Term Credit Agreement; provided, that in no event can this obligation exceed during the term of the Contribution Agreement the maximum amount that we could contribute under the terms of the Indenture governing our senior notes. Alternatively, we can cause EXCO Partners to make the equity contribution to EPOP in the amount of $150.0 million to satisfy this obligation. In lieu of requiring the equity contribution to be made, the lenders can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become “Restricted Subsidiaries” under our credit agreement and require us to provide and cause all then Restricted Subsidiaries as defined and constituted under our credit agreement to provide guarantees and collateral in respect of the Senior Term Credit Agreement on terms substantially consistent with the guarantees and collateral provided under our credit agreement. This requirement is subject to compliance with our credit agreement. Any cash so contributed shall be used by EPOP to prepay loans under the Senior Term Credit Agreement. EXCO Resources and its subsidiaries are prohibited from making restricted payments (as defined in the Indenture) that would constitute a utilization of the Indenture restricted payment baskets, other than Restricted Payments not to exceed $5.0 million. In addition, we have covenanted to redeem or defease our senior notes if the Indenture would not permit the equity contribution or the lenders’ election to cause us to designate EPOP and its subsidiaries as Restricted Subsidiaries under our credit agreement (subject to certain restrictions on the indebtedness that may be incurred for any such redemption or defeasance if the election to cause the designation of EPOP as a Restricted Subsidiary is chosen).
The success of our natural gas gathering and transportation business depends upon our ability to continually obtain new sources of natural gas supply, and any decrease in supplies of natural gas could reduce our transportation revenues.
Our gathering and transportation pipelines are connected to natural gas reserves and wells, for which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our pipelines, we must continually obtain new natural gas supplies. We may not be able to obtain additional third party contracts for natural gas supplies. The primary factors affecting our ability to connect new supplies of gas and attract new customers to our gathering and transportation pipelines include: (1) the level of successful drilling activity near our gathering systems and (2) our ability to compete for the commitment of such additional volumes to our systems.
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations other than our own drilling, the amount of reserves underlying the wells or the rate at which production from a well will decline. In addition, we have no control over third party producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.
We face strong competition in acquiring new natural gas supplies. Competitors to our pipeline operations include major interstate and intrastate pipelines, and other natural gas gatherers. Competition for natural gas supplies is primarily based on the location of pipeline facilities, pricing arrangements, reputation, efficiency, flexibility and reliability. Many of our competitors have greater financial resources than we do.
If we are unable to maintain or increase the throughput on our gathering and transportation pipelines because of decreased drilling activity in the areas in which we operate or because of an inability to connect new supplies of gas and attract new customers to our gathering and transportation pipelines, then our business and financial results could be materially adversely affected.
If third-party pipelines and other facilities interconnected to our gathering and transportation pipelines become unavailable to transport or process natural gas, our revenues and cash could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options from our transportation and gathering pipelines for the benefit of our customers. All of the natural gas transported by Winchester’s pipeline must be processed by processing plants before delivery into a pipeline for natural gas. Winchester does not own or control any of these processing plants. If the processing plants to which we deliver natural gas were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers would be unable to deliver natural gas to end markets. Either of such events could materially and adversely affect our business, results of operations and financial condition.
We do not own all of the land on which our transportation and gathering pipelines and gathering system are located, which could disrupt our operations.
We do not own all of the land on which our transportation and gathering pipelines have been constructed, and we are therefore subject to the possibility of increased costs to retain necessary land use. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition.
We expect to incur a substantial amount of indebtedness to fund the acquisitions of the Vernon Assets and the Southern Gas Assets, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.
To finance the acquisitions of the Vernon Assets and the Southern Gas Assets, we received a Commitment Letter from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A., providing for a senior secured revolving credit facility commitment in the amount of $1.8 billion and an undertaking to arrange a bridge loan facility in the amount of $1.1 billion, if requested. If used to finance the acquisitions, the new credit facilities will contain customary representations, warranties and covenants, and the closing
of the new credit facilities will be subject to the satisfaction of customary closing conditions. To service this indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on commercially reasonable terms, or at all. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt under the new credit facilities, which could cause us to default on our obligations and could impair our liquidity. We are also pursuing other financing alternatives.
We may be unable to acquire or develop additional reserves, which would reduce our revenues and access to capital.
Our success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are profitable to produce. Factors that may hinder our ability to acquire additional oil and natural gas reserves include competition, access to capital, prevailing oil and natural gas prices and the number and attractiveness of properties for sale. If we are unable to conduct successful development activities or acquire properties containing Proved Reserves, our total Proved Reserves will generally decline as a result of production. Also, our production will generally decline. In addition, if our reserves and production decline, then the amount we are able to borrow under our credit agreement will also decline. We may be unable to locate additional reserves, drill economically productive wells or acquire properties containing Proved Reserves.
We may not identify all risks associated with the acquisition of oil and natural gas properties, which may result in unexpected liabilities and costs to us.
Generally, it is not feasible for us to review in detail every individual property involved in an acquisition. Our business strategy focuses on acquisitions of producing oil and natural gas properties. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and other similar factors. Ordinarily, our review efforts are focused on the higher-valued properties. For example, in the TXOK and Winchester acquisitions we did not review title or production data for, or physically inspect, every well we acquired. Even a detailed review of properties and records may not reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect every well that we acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we inspect a well. Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.
Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems. Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable and may be limited by floors and caps on such indemnity. The indemnifications we received in the TXOK and Winchester acquisitions are subject to floors and caps and do not cover all these types of risks.
We may be unable to obtain additional financing to implement our growth strategy.
The growth of our business will require substantial capital on a continuing basis. Because of our issuance of the senior notes and the pledge of substantially all of our assets as collateral under our credit agreements, it may be difficult for us in the foreseeable future to obtain debt financing on an unsecured basis or to obtain additional secured financing other than purchase money indebtedness. If we are unable
to obtain additional capital on satisfactory terms and conditions, we may lose opportunities to acquire oil and natural gas properties and businesses and, therefore, unable to implement our growth strategy.
We may not be successful in managing our growth, which could adversely affect our operations and net revenues.
The pursuit of additional acquisitions is a key part of our strategy. We face challenges in growing our managerial, financial, accounting, technical, operational and administrative resources to keep up with the pace of the growth of our business and our significant corporate transactions such as the Equity Buyout and our IPO. For example, our rapid growth and significant transactions over the past two years have strained, and could continue to strain, our financial, tax and accounting staff. The size and scope of our business from an operational, personnel, financial reporting and accounting perspective has substantially increased due to the TXOK and Winchester acquisitions and will further increase due to the pending acquisitions of the Vernon Assets and the Southern Gas Assets. Our growth could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards as well as internal controls and procedures. Failure to manage our growth successfully could adversely affect our operations and net revenues through increased operating costs and revenues that do not meet our expectations, as well as adversely affect our ability to satisfy our disclosure and other obligations. We may also be unable to successfully integrate acquired oil and natural gas properties into our operations or achieve desired profitability.
If we are unable to successfully prevent or address material weaknesses in our internal control over financial reporting, or any other control deficiencies, our ability to report our financial results on a timely and accurate basis and to comply with disclosure and other requirements may be adversely affected.
We are not currently required to comply with Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make an assessment of the effectiveness of our internal control over financial reporting for that purpose. However, in connection with the 2004 and the 2005 audits of the financial statements of EXCO Resources, we reported a material weakness in Item 9A of our Annual Report on Form 10-K. In addition, prior to the quarter ended September 30, 2006, our management concluded that our disclosure controls and procedures were not effective due to a material weakness relating to accounting for income taxes.
A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Our management concluded that as of December 31, 2005, we did not maintain effective controls over the preparation and review of the quarterly and annual tax provision and the related financial statement presentation and disclosure of income tax matters. Specifically, our controls were not adequate to ensure the completeness and accuracy of the tax provision and the deferred tax balances, including the timing and classification of recording the tax impact of an extraordinary dividend. This control deficiency resulted in the restatement of our consolidated financial statements for the quarters ended June 30, 2005 and September 30, 2005 and audit adjustments to the consolidated financial statements for the years ended December 31, 2004 and 2005, affecting income tax expense and the deferred tax liability accounts. Additionally, this control deficiency could have resulted in a misstatement in the aforementioned tax accounts that would result in a material misstatement to the annual or interim financial statements that would not have been prevented or detected. Accordingly, management concluded that this deficiency in internal control over financial reporting was a material weakness. Although we believe we have taken the necessary steps to remediate this material weakness, as described in Item 9A of this Annual Report on Form 10-K, we may identify additional material weaknesses or other deficiencies in our internal control over financial reporting in the future.
We will continue to monitor the effectiveness of these and other processes, procedures and controls and will make any further changes management determines appropriate, including to effect compliance
with Section 404 of the Sarbanes-Oxley Act of 2002 when we are required to make an assessment of internal control over financial reporting under Section 404 for fiscal 2007.
Any material weaknesses or other deficiencies in our internal control over financial reporting may affect our ability to comply with SEC reporting requirements and New York Stock Exchange, or NYSE, listing standards or cause our financial statements to contain material misstatements, which could negatively affect the market price and trading liquidity of our common stock, cause investors to lose confidence in our reported financial information, as well as subject us to civil or criminal investigations and penalties.
There are inherent limitations in all internal control systems over financial reporting, and misstatements due to error or fraud may occur and not be detected.
While we have taken actions designed to address compliance with the internal control, disclosure control and other requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated by the SEC implementing these requirements, there are inherent limitations in our ability to control all circumstances. Our management, including our Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, does not expect that our internal controls and disclosure controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.
Our ability to market our oil and natural gas production will depend upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities. We are primarily dependent upon third parties to transport our products. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. We experienced production curtailments in the Appalachian Basin during 2004, 2005 and 2006 resulting from capacity restraints and short term shutdowns of certain pipelines for maintenance purposes. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas, the value of our common stock and our ability to pay dividends on our company stock.
There are risks associated with our drilling activity that could impact the results of our operations.
Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment. We have experienced some delays in contracting for drilling rigs and increasing costs to drill wells. All of these risks could adversely affect our results of operations and financial condition.
We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, development, and exploitation activities.
Our future success will depend on the success of our acquisition, development, and exploitation activities. Our decisions to purchase, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Our estimates regarding the increase in our reserves and production resulting from the Winchester and TXOK acquisitions may prove to be incorrect, which could significantly reduce our ability to generate cash needed to service our debt and fund our capital program and other working capital requirements.
We cannot control the development of the properties we own but do not operate, which may adversely affect our production, revenues and results of operations.
As of December 31, 2006, third parties operate wells that represent approximately 10% of our Proved Reserves. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:
· the timing and amount of capital expenditures;
· the operators’ expertise and financial resources;
· the approval of other participants in drilling wells; and
· the selection of suitable technology.
If drilling and development activities are not conducted on these properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, which may adversely affect our production, revenues and results of operations.
Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported reserves and our financial condition.
Numerous uncertainties are inherent in estimating quantities of proved oil and natural gas reserves, including many factors beyond our control. This annual report contains estimates of our proved oil and natural gas reserves and the PV-10 of our proved oil and natural gas reserves. These estimates are based upon reports of our own engineers and our independent petroleum engineers. These reports rely upon various assumptions, including assumptions required by the SEC as to constant oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. These estimates should not be construed as the current market value of our estimated Proved Reserves. The process of
estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. As a result, the estimates are inherently imprecise evaluations of reserve quantities and future net revenue. Our actual future production, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we have assumed in the estimates. Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 described in this annual report, and our financial condition. In addition, our reserves or PV-10 may be revised downward or upward, based upon production history, results of future exploitation and development activities, prevailing oil and natural gas prices and other factors. A material decline in prices paid for our production can adversely impact the estimated volumes of our reserves. Similarly, a decline in market prices for oil or natural gas may adversely affect our PV-10. Any of these negative effects on our reserves or PV-10 may decrease the value of our common stock.
We are exposed to operating hazards and uninsured risks that could adversely impact our results of operations and cash flow.
Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:
· fires, explosions and blowouts;
· pipe failures;
· abnormally pressured formations; and
· environmental accidents such as oil spills, gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).
We have in the past experienced some of these events during our drilling operations. These events may result in substantial losses to us from:
· injury or loss of life;
· severe damage to or destruction of property, natural resources and equipment;
· pollution or other environmental damage;
· environmental clean-up responsibilities;
· regulatory investigation;
· penalties and suspension of operations; or
· attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.
As is customary in our industry, we maintain insurance against some, but not all, of these risks. Our insurance may not be adequate to cover these potential losses or liabilities. Furthermore, insurance coverage may not continue to be available at commercially acceptable premium levels or at all. Due to cost considerations, from time to time we have declined to obtain coverage for certain drilling activities and have therefore been restricted from conducting these types of drilling activities during the period we were uninsured. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our results of operations and cash flow.
Our business exposes us to liability and extensive regulation on environmental matters, which could result in substantial expenditures.
Our operations are subject to numerous U.S. federal, state and local laws and regulations relating to the protection of the environment, including those governing the discharge of materials into the water and air, the generation, management and disposal of hazardous substances and wastes and the clean-up of contaminated sites. We could incur material costs, including clean-up costs, fines and civil and criminal sanctions and third-party claims for property damage and personal injury as a result of violations of, or liabilities under, environmental laws and regulations. Such laws and regulations not only expose us to liability for our own activities, but may also expose us to liability for the conduct of others or for actions by us that were in compliance with all applicable laws at the time those actions were taken. In addition, we could incur substantial expenditures complying with environmental laws and regulations, including future environmental laws and regulations which may be more stringent.
Our business substantially depends on Douglas H. Miller, our CEO.
We are substantially dependent upon the skills of Mr. Douglas H. Miller. Mr. Miller has extensive experience in acquiring, financing and restructuring oil and natural gas companies. We do not have an employment agreement with Mr. Miller or maintain key man insurance. The loss of the services of Mr. Miller could hinder our ability to successfully implement our business strategy.
We may have write-downs of our asset values, which could negatively affect our results of operations and net worth.
Depending upon oil and natural gas prices in the future, we may be required to write-down the value of our oil and natural gas properties if the present value of the after-tax future cash flows from our oil and natural gas properties falls below the net book value of these properties. We have in the past experienced ceiling test writedowns with respect to our oil and natural gas properties. Future non-cash ceiling test write-downs could negatively affect our results of operations and net worth.
We also test goodwill for impairment annually or when circumstances indicate that an impairment may exist. If the book value of our reporting units, as defined, exceeds the fair value of those reporting units, an impairment charge will occur, which could negatively impact our net worth.
We may experience a financial loss if any of our significant customers fail to pay us for our oil or natural gas.
Our ability to collect the proceeds from the sale of oil and natural gas from our customers depends on the payment ability of our customer base, which includes several significant customers. If any one or more of our significant customers fails to pay us for any reason, we could experience a material loss. In addition, in recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our oil and natural gas production. This reduction in potential customers has reduced market liquidity and, in some cases, has made it difficult for us to identify creditworthy customers. We also sell a portion of our natural gas directly to end users. We may experience a material loss as a result of the failure of our customers to pay us for prior purchases of our oil or natural gas.
We may experience a temporary decline in revenues if we lose one of our significant customers.
For the year ended December 31, 2006, sales of natural gas to one interstate pipeline company accounted for 11.6% of our total oil and natural gas revenues. For the years ended December 31, 2005 and 2004, sales of natural gas to one industrial customer accounted for 10.1% and 10.6%, respectively, of our total oil and natural gas revenues. In 2006, our top eight customers accounted for approximately 38.2% of our total oil and natural gas revenues. To the extent any significant customer reduces the volume of its
natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas.
Competition in our industry is intense and we may be unable to compete in acquiring properties, contracting for drilling equipment and hiring experienced personnel.
The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are currently experiencing difficulties in obtaining drilling rigs and other services in certain areas as well as an increase in the cost for these services and related material and equipment. We are unable to predict how such shortages and price increases will affect our development and exploitation program. Competition has also been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We are often outbid by competitors in our attempts to acquire properties or companies. All of these challenges could make it more difficult to execute our growth strategy and increase our costs.
Risks relating to our indebtedness
We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.
As of March 1, 2007, we had approximately $2.1 billion of indebtedness, including $1.7 billion of indebtedness which is subject to variable interest rates. Our total interest expense on an annual basis would be approximately $180.0 million and would change by approximately $17.0 million for every 1% change in interest rates.
Our level of debt could have important consequences, including the following:
· it may be more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the Indenture governing our senior notes and the agreements governing our other indebtedness;
· we may have difficulty borrowing money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;
· the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest;
· we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;
· we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;
· we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in oil and natural gas prices; and
· our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.
Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will be unable to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our earnings will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money to service our debt, we may be required but unable to refinance all or part of our existing debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. Further, failing to comply with the financial and other restrictive covenants in our credit agreements and the Indenture governing our senior notes could result in an event of default, which could adversely affect our business, financial condition and results of operations.
We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.
Together with our subsidiaries, we may incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. The restrictions in our debt agreements on our incurrence of additional indebtedness are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially increase.
To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.
Our ability to make payments on and to refinance our indebtedness, including our senior notes and loans under our credit agreements, and to fund planned capital expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas.
Our business may not generate sufficient cash flow from operations and future borrowings may not be available to us in an amount sufficient to enable us to pay our indebtedness, including our senior notes and loans under our credit agreements, or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. None of these remedies may, if necessary, be effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, which could cause us to default on our obligations and could impair our liquidity.
Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Our credit agreements and the Indenture governing our senior notes contain a number of significant covenants that, among other things, restrict our ability to:
· dispose of assets;
· incur or guarantee additional indebtedness and issue certain types of preferred stock;
· pay dividends on our capital stock;
· create liens on our assets;
· enter into sale or leaseback transactions;
· enter into specified investments or acquisitions;
· repurchase, redeem or retire our capital stock or subordinated debt;
· merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;
· engage in specified transactions with subsidiaries and affiliates; or
· pursue other corporate activities.
Also, our credit agreements require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our credit agreements and the Indenture governing our senior notes.
A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our credit arrangements and our senior notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our credit arrangements and our senior notes. The accelerated debt would become immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. We amended certain financial covenants under the EPOP Revolving Credit Facility due to our inability to meet certain financial covenants associated with our EPOP Revolving Credit Facility (-See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity, capital resources and commitments-EPOP Revolving Credit Facility.”)
Risks relating to our common stock
Our stock price may fluctuate significantly.
Our common stock began trading on the NYSE on February 9, 2006. An active trading market may not be sustained. The market price of our common stock could fluctuate significantly as a result of:
· actual or anticipated quarterly variations in our operating results;
· changes in expectations as to our future financial performance or changes in financial estimates of public market analysis;
· announcements relating to our business or the business of our competitors;
· conditions generally affecting the oil and natural gas industry;
· the success of our operating strategy; and
· the operating and stock price performance of other comparable companies.
Many of these factors are beyond our control and we cannot predict their potential effects on the price of our common stock. In addition, the stock markets in general can experience considerable price and volume fluctuations.
Future sales of our common stock may cause our stock price to decline.
Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock.
As of March 1, 2007, we had 104,221,015 shares of common stock outstanding. Of these shares, 70,628,370 shares are freely tradable, unless any of these shares are held by our affiliates.
Many of our shareholders, including our executive officers and directors, are subject to agreements that limit their ability to sell our common stock held by them. On October 3, 2005, we entered into a registration rights agreement with all of the holders of our common stock, which agreement was amended by the First Amended and Restated Registration Rights Agreement. A total of 50,388,889 shares of common stock were covered by this agreement. Any holder who is a party to this agreement has the right, commencing 180 days after completion of the IPO on February 14, 2006, to require us to register for resale up to one-third of their shares of common stock. All other parties to the registration rights agreement would then have the right to require us to register for resale up to one-third of their shares of common stock on the same registration statement. On January 17, 2007, our registration statement covering 16,796,244 shares was declared effective by the SEC.
The same rights exist commencing 365 days and 540 days after February 14, 2006 for an additional one-third of their shares at each such anniversary. These time and volume restrictions on resale registrations may be waived by J.P. Morgan Securities Inc. based on its evaluation of market and other conditions. On January 11, 2007, J.P. Morgan Securities Inc. and EXCO executed a waiver letter that allows selling shareholders to request that we register for resale the remaining two-thirds of their shares at any time after February 14, 2007. On February 15, 2007, we received a request from one of our shareholders to register the remaining two-thirds of his shares in accordance with the registration rights agreement. We expect to register 33,592,645 shares, the remaining two-thirds of the shares subject to the registration rights agreement, as soon as practicable after the filing of this annual report. In addition, at any time that we file a registration statement registering other shares, the holders of shares subject to the registration rights agreement can require that we include their shares in such registration statement, subject to certain exceptions. The filing of any resale registration statement and the sale of shares thereunder may have a material adverse effect on the market price of our common stock.
The equity trading markets may be volatile, which could result in losses for our shareholders.
The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.
Our articles of incorporation permit us to issue preferred stock that may restrict a takeover attempt that you may favor.
Our articles of incorporation permit our board to issue up to 10,000,000 shares of preferred stock and to establish, by resolution, one or more series of preferred stock and the powers, designations, preferences and participating, optional or other special rights of each series of preferred stock. The preferred stock may be issued on terms that are unfavorable to the holders of our common stock, including the grant of
superior voting rights, the grant of preferences in favor of preferred shareholders in the payment of dividends and upon our liquidation and the designation of conversion rights that entitle holders of our preferred stock to convert their shares into our common stock on terms that are dilutive to holders of our common stock. The issuance of preferred stock in future offerings may make a takeover or change in control of us more difficult. We are considering the issuance of up to $2.0 billion of preferred stock to institutional accredited investors in a private placement under the Securities Act of 1933. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity, capital resources and capital commitments-Proposed recapitalization.” We have not entered into definitive agreements with potential investors to issue any preferred stock. As a result, we may never issue any preferred stock. In addition, any preferred stock that we ultimately issue may contain terms different from those provided in this annual report.
We have not paid dividends in the past and do not expect to pay dividends in the future, and any return on investment may be limited to the value of our stock.
We have never paid cash dividends on our common stock and do not anticipate paying cash dividends on our common stock in the foreseeable future. The payment of dividends will depend on our earnings, capital requirements, financial condition, prospects and other factors our board of directors may deem relevant. If we do not pay dividends, our stock may be less valuable because a return on your investment will only occur if our stock price appreciates. In addition, our credit agreements and the Indenture governing our senior notes restrict the payment of dividends.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES
Corporate offices
We lease approximately 33,500 square feet of office space in Dallas, Texas, for our corporate offices. On February 27, 2006 we amended this lease effective July 1, 2006 to obtain additional square footage and extend the expiration date from June 30, 2011 to June 30, 2013. The lease requires monthly rental payments of approximately $48,300. We lease an office in Akron, Ohio. The Akron office contains approximately 17,000 square feet and requires monthly rental payments of approximately $23,700. The Akron office lease expires December 15, 2012. TXOK has entered into a lease agreement effective March 1, 2006, for approximately 22,700 square feet of office space in Tulsa, Oklahoma. The lease expires May 31, 2011, and requires monthly rental payments of approximately $24,500. We lease 15,246 square feet of office space in Shreveport, Louisiana. The lease expires September 30, 2008. This lease requires monthly rental payments of approximately $12,100 per month. We also have small offices for technical and field operations in Texas, Oklahoma, Colorado, Nebraska, Ohio and West Virginia.
Other
We have described our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling activity in “Item 1. Business” beginning on page 1 of this annual report.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styled PRC Holdings, LLC, et al. v. North Coast Energy, Inc. and was filed in the Circuit Court of Roane County, West Virginia. This action has been removed to the United States District Court for the Southern District of West Virginia. The action has been brought by certain landowners and lessors in West
Virginia for themselves and on behalf of other similarly situated landowners and lessors in West Virginia. The lawsuit alleges that North Coast Energy, Inc. has not been paying royalties to the plaintiffs in the manner required under the applicable leases, has provided misleading documentation to the plaintiffs regarding the royalties due, and has breached various other contractual, statutory and fiduciary duties to the plaintiffs with regard to the payment of royalties. In a case styled The Estate of Garrison Tawney v. Columbia Natural Resources, LLC announced in June 2006, the West Virginia Supreme Court held that language such as “at the wellhead” and similar language contained in leases when used in describing how to calculate royalties due lessors was ambiguous and, therefore, should be construed strictly against the lessee. Accordingly, in the absence of express language in a lease that is intended to allocate between a lessor and lessee post-production costs such as the costs of marketing the product and transporting it to the point of sale, no post-production costs may be deducted from the lessor’s royalty payment due from the lessee. The claims alleged by the plaintiffs in the lawsuit filed against us are similar to the claims alleged in the Tawney case. Plaintiffs are seeking common law and statutory compensatory and punitive damages, interest and costs and other remedies. We are vigorously defending the existing lawsuit. The action is in a very preliminary stage. The preliminary status of the lawsuit leaves the ultimate outcome of this litigation uncertain. We believe that we have substantial defenses to this lawsuit and that the adverse affects from this litigation, if any, are reflected in our financial statements and we do not expect the ultimate outcome of the lawsuit to have a material effect on our financial position, results of operations or cash flows.
In the ordinary course of business, we are periodically a party to lawsuits and claims. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a materially adverse effect on our results of operations or financial condition.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market information for our common stock
Prior to February 14, 2006, we were 100% owned by EXCO Holdings. Effective February 9, 2006, our common stock began trading on a “when issued” basis on the NYSE under the symbol “XCO”.
The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the NYSE:
Our shareholders
According to our transfer agent, Continental Stock Transfer & Trust Company, there were approximately 147 holders of record of our common stock on March 1, 2007 (including nominee holders such as banks and brokerage firms who hold shares for beneficial holders).
Our dividend policy
We have not paid any cash dividends on our common stock, and do not anticipate paying cash dividends on our common stock in the foreseeable future. In addition, our credit agreements currently prohibit us from paying dividends on our common stock and the Indenture governing our senior notes contains restrictions on our payment of dividends. Even if our credit agreement permitted us to pay cash dividends, we can make those payments only from our surplus (the excess of the fair value of our total assets over the sum of our liabilities plus our total paid-in share capital). In addition, we can pay cash dividends only if after paying those dividends we would be able to pay our liabilities as they become due.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents our selected historical financial and operating data. You should read this financial data in conjunction with our “Management’s discussion and analysis of financial condition and results of operations,” our consolidated financial statements, the notes to our consolidated financial statements and the other financial information, included in this annual report. This information does not replace the consolidated financial statements. We have completed numerous acquisitions and dispositions since 2002 that materially impact the comparability of this data between periods.
The selected financial data for the twelve months ended December 31, 2002 and the 209 day period from January 1, 2003 to July 28, 2003 is referred to as public predecessor and represents accounting periods when EXCO was a publicly traded company on the Nasdaq. On July 29, 2003, EXCO completed a going private transaction which resulted in a change of accounting basis. The selected financial data for the 156 day period from July 29, 2003 to December 31, 2003, the twelve months ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005 is referred to as predecessor and represents the period of time when EXCO was privately held. The period from the Equity Buyout on October 3, 2005, which resulted in an additional change in accounting basis, through December 31, 2006 is referred to as successor.
Selected consolidated financial and operating data (continued)
(1) We have completed numerous acquisitions and dispositions since January 1, 2002 that materially impact the comparability the selected financial data between periods.
(2) On July 28, 2003, EXCO completed a going private transaction which resulted in a change of control and a new basis of accounting. Upon consummation of the going private transaction, we discontinued the designation of our derivative financial instruments as hedges. Beginning with July 29, 2003, changes in the fair value of our derivative financial instruments are recognized directly in our statement of operations. See “Item 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this annual report. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors including those discussed under “risk factors” and elsewhere in this annual report.
Overview and history
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 and, until February 10, 2005, in Canada. We expect to continue to grow by leveraging our management team’s experience, exploiting our multi-year inventory of development drilling locations and exploitation projects, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive derivative financial instrument program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. On February 14, 2006, we acquired TXOK for approximately $665.1 million and on October 2, 2006, we completed the acquisition of Winchester for approximately $1.1 billion in cash after closing adjustments. The Winchester acquisition was completed within our newly-formed subsidiary, EXCO Partners. Concurrent with the closing of this acquisition we contributed to EXCO Partners all of our East Texas assets, including four of our subsidiaries that own or operate certain of our East Texas assets, in exchange for $150.0 million of cash and additional equity interests in EXCO Partners. EPOP borrowed $1.3 billion to fund these transactions. Our 2006 acquisitions, including TXOK and Winchester, totaled in excess of $2.1 billion. In addition, we spent $214.3 million for development drilling, acreage and related oil and natural gas facilities during 2006. For a discussion of these acquisitions as well as other transactions that we completed during 2005 and 2006, see “Item 1. Business-Significant transactions during 2005” and “Item 1. Business-Significant transactions during 2006.” We expect that our pending acquisitions with Anadarko will have a significant impact on our results of operations, liquidity and financial condition during 2007. For a discussion of these pending acquisitions, see “Item 1. Business-Significant subsequent events.”
Oil and natural gas prices have historically been volatile. During 2006, the NYMEX price for natural gas has fluctuated from a high of $10.63 per Mmbtu to a low of $4.20 per Mmbtu. On December 31, 2006, the spot market price for natural gas at Henry Hub was $5.64 per Mmbtu, a 45% decrease from December 31, 2005. The price of oil has shown similar volatility. In 2006, our average realized prices (before the impact of derivative financial instruments) for oil and natural gas were $62.27 per Bbl and $6.77 per Mcf compared with 2005 prices of $53.35 per Bbl and $8.58, respectively. The volatile commodity price environment from 2004 through 2006, which was accentuated in 2005 by historical high prices for natural gas after the hurricanes in the third quarter of 2005, caused an increase in demand for drilling rigs, field supplies and related oil field service costs. EXCO, as well as other producers of oil and natural gas, experienced some difficulty in timely scheduling drilling and related services during this period. However, we did not encounter any significant operational problems or operational delays as a result of these scheduling difficulties. We cannot predict the impact that the recent declines in oil and natural gas prices could cause to our operating revenues, results of operations, or capital budgets nor can we predict the impact on the pricing for drilling rigs and related oil field services. Management continuously monitors its operations and capital budget and employs the use of derivative financial instruments to lessen the impact of fluctuating prices for oil and natural gas.
Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to overcome this natural decline by drilling to develop and identify additional reserves and by acquisitions. 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 will maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.
We also face the challenge of financing future acquisitions. Following completion of our IPO in February 2006, we amended our revolving credit agreement with our banking syndicate which provided for a borrowing base of $750.0 million with an aggregate commitment of $500.0 million. As a result of the acquisition of Winchester on October 2, 2006, and the contribution of our East Texas assets to EXCO Partners, our credit agreement was further amended to reflect the contribution of these assets by reducing the borrowing base to $600.0 million with a $500.0 million aggregate commitment. EPOP has a separate $750.0 million credit agreement with a $650.0 conforming borrowing base and $650.0 million term loan which was used to finance the acquisition of Winchester. We believe we will have adequate unused borrowing capacity under our credit agreements and available cash flow from operations to fund capital development and working capital needs for the next 12 months. Funding for future acquisitions may require additional sources of financing, which may not be available.
Critical accounting policies
In response to the SEC’s Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve the most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our Proved Reserves, accounting for business combinations, derivatives accounting, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.
We prepared our consolidated financial statements for inclusion in this report in accordance with accounting principles that are generally accepted in the United States, or GAAP. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. Upon closing of the Equity Buyout, we adopted SFAS No. 123(R), “Share-Based Payment,” or SFAS No. 123(R). The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.
Estimates of Proved Reserves
The Proved Reserves data included in this annual report was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:
· the quality and quantity of available data;
· the interpretation of that data;
· the accuracy of various mandated economic assumptions; and
· the judgment of the persons preparing the estimate.
Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
You should not assume that the present value of future net cash flows is the current market value of our estimated Proved Reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from Proved Reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Further, a discount rate of 10% may not be an accurate assumption of future interest rates.
Proved Reserves quantities directly and materially impact depletion expense. If the Proved Reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of Proved Reserves may result from lower market prices, and a decline may make it uneconomical to drill or produce from higher cost fields. In addition, a decline in Proved Reserves may impact the outcome of our assessment of our oil and natural gas properties for impairment.
Proved Reserves are defined as the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Estimates of Proved Reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil and natural gas, that may occur in undrilled prospects; and (D) crude oil and natural gas that may be recovered from oil shales, coal, gilsonite and other such sources.
Business combinations
We follow SFAS No. 141 to record our acquisitions of oil and natural gas properties or entities which we acquire. SFAS No. 141 requires that acquired assets, identifiable intangible assets and liabilities be recorded at their fair value, with any excess purchase price being recognized as goodwill. Application of SFAS No. 141 requires significant estimates to be made by management using information available at the time of acquisition. Since these estimates require the use of significant judgment, actual results could vary as the estimates are subject to changes as new information becomes available.
Accounting for derivatives
We use derivative financial instruments to protect against commodity price fluctuations and in connection with the incurrence of debt related to our acquisition activities. Our objective in entering into these derivative financial instruments is to manage price fluctuations and achieve a more predictable cash flow to fund our development, acquisition activities and support debt incurred with our acquisitions. These derivative financial instruments are not held for trading purposes. We do not designate our derivative
financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value as a component of current earnings.
Share-based payments
Prior to October 3, 2005, we accounted for share-based payments to employees using the intrinsic value method prescribed by APB No. 25, “Accounting for Stock Issued to Employees” and related interpretations. As such, we did not recognize compensation expense associated with employee stock options, as the options were granted at fair market value on the date of grant. Holdings II adopted the provisions of SFAS No. 123(R) upon its formation in August 2005. Upon closing of the Equity Buyout, we adopted SFAS No. 123(R). At December 31, 2006, our employees and directors held options under EXCO’s 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, to purchase 8,267,373 shares of EXCO common stock at prices ranging from $7.50 per share to $14.62 per share. The options expire ten years from 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 grant. We use the Black-Scholes model to calculate the fair value of issued options. The gross fair value of the granted options using the Black-Scholes model range from $2.29 per share to $5.01 per share. SFAS No. 123(R) requires share-based compensation be recorded with cost classifications consistent with cash compensation. EXCO uses the full cost method to account for its oil and natural gas properties. As a result, part of our share-based payments are capitalized. Total share-based compensation for 2006 was $7.9 million, of which $1.4 million was capitalized to the full cost pool. In 2005, a total of $3.2 million of share-based compensation was incurred, of which $1.0 million was capitalized to the full cost pool.
For the 275 day period ended October 2, 2005, a non-recurring $44.1 million share-based compensation expense was recognized as a result of the Equity Buyout. This compensation charge was attributable to the Class B common shares of EXCO Holdings purchased by Holdings II.
Accounting for oil and natural gas properties
The accounting for, and disclosure of, oil and natural gas producing activities requires that we choose between GAAP alternatives and that we make judgments regarding estimates of future uncertainties.
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 full cost pool or in unevaluated properties. Unevaluated property costs are not subject to depletion. We review our unevaluated oil and natural gas property costs on an ongoing basis, and we expect these costs to be evaluated in one to five years and transferred to 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 leaseholds.
We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total amount of Proved Reserves. 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 that is attributable to our acquisition, exploration, exploitation and development activities.
At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). Until February 10, 2005, this ceiling test calculation was done separately for the United States and for the Canadian full cost pools. When computing our full cost ceiling limitation, we evaluate the limitation at the end of each reporting period date. In the event our capitalized costs exceed the ceiling limitation at the end of the reporting date, we subsequently evaluate the limitation for price changes that
occur after the balance sheet to assess impairment as permitted by Staff Accounting Bulletin Topic 12-Oil and Gas Producing Activities. In addition, in February 2007, we sought, and received an exemption from the SEC to exclude our 2006 acquisitions of oil and natural gas properties from our ceiling test for a period of 12 months, provided that we could demonstrate beyond a reasonable doubt that the fair value of the oil and natural gas reserves acquired in 2006 exceeded their unamortized carrying costs. Assuming we can demonstrate the fair value exceeds the carrying costs for the next 12 months, we will initially test the 2006 acquisitions at December 31, 2007.
The quarterly 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 and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
In September 2004, the SEC released SAB No. 106 concerning the application of SFAS No. 143 “Accounting for Asset Retirement Obligations,” or SFAS No. 143, by oil and natural gas producing companies following the full cost method of accounting. In SAB No. 106, the SEC addressed the impact of SFAS No. 143 on the ceiling test calculation and on the calculation of depreciation, depletion and amortization. SAB No. 106 became effective for us on January 1, 2005 and has not had a significant impact on our ceiling test calculation. Also, as a result of SAB No. 106, we now include the estimated asset retirement obligation that will result from future development activity in our calculation of depreciation, depletion and amortization. This change has not had a significant impact on our depreciation, depletion and amortization expense.
Prior to the issuance of SFAS No. 143, we included expected future cash flows related to the asset retirement obligations from certain properties in our ceiling test calculation. Under SFAS No. 143, we must now initially capitalize asset retirement costs by increasing long-lived oil and natural gas assets by the same amount as the asset retirement liability before discount. After adoption of SFAS No. 143, if we were to continue to calculate the full cost ceiling test by reducing expected future net revenues by the cash flows required to settle the asset obligation, then the effect would be to “double-count” such costs in the ceiling test.
Goodwill
As a result of the Equity Buyout on October 3, 2005, which required the application of the purchase method of accounting pursuant to SFAS No. 141, goodwill of $220.0 million was recognized. Additional goodwill in 2006 of $64.9 million, $21.2 million and $163.9 million was recognized from the acquisitions of TXOK, PGMT and Winchester, respectively. As of December 31, 2006, our consolidated goodwill totals $470.1 million. Our strategy is to concentrate on accumulating assets in East Texas, North Louisiana, the Mid-Continent region and Appalachia. We believe the strategic value paid for the assets substantiates the goodwill we have incurred.
None of the goodwill is currently deductible for income tax purposes. Furthermore, in accordance with SFAS No. 142, “Goodwill and Intangible Assets,” or SFAS No. 142, goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with which goodwill is associated, subject to various assumptions and judgments. Actual future results of these assumptions could differ as a result of economic changes which are not within our control. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations.
Asset retirement obligations
In June 2001, the Financial Accounting Standards Board, or FASB, issued SFAS No. 143. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. We adopted SFAS No. 143 on January 1, 2003. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. Recent cost increases have impacted our evaluation of asset retirement obligations. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.
Accounting for income taxes
Income taxes are accounted for using the liability method of accounting in accordance with SFAS No. 109, “Accounting for Income Taxes,” or SFAS No. 109. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. As a result of the Equity Buyout, our book basis of assets increased by approximately $380.3 million, while our tax basis carried over. The result was an increase to our deferred tax liability. Deferred taxes are recorded to reflect the tax benefit and consequences of future years’ differences between the tax basis of assets and liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized. Prior to the planned disposition of Addison, we considered Addison’s earnings to be permanently reinvested for use in those operations and, consequently, deferred federal income taxes, net of applicable foreign tax credits, had not been provided on the undistributed earnings of Addison that were reinvested. As a result of the sale of Addison, we provided for deferred federal income taxes in the fourth quarter of 2004 on the undistributed earnings of Addison which is reflected as income tax expense of discontinued operations.
Recent accounting pronouncements
In July 2006, the FASB issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. FIN 48 is effective as of January 1, 2007. The adoption of FIN 48 did not have a material impact on our financial statements.
In September 2006, the SEC Staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” or SAB 108, in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We adopted SAB 108 in the fourth quarter of 2006. The adoption of SAB 108 did not have a material impact on our financial statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will be required to adopt SFAS No. 157 in the first quarter of fiscal year 2008. We are currently evaluating the impact of SFAS No. 157 on our financial statements.
Our results of operations
Due to the application of purchase accounting for the Equity Buyout in October 2005, our results of operations contain predecessor and successor periods. Because the application of purchase accounting can inhibit meaningful comparison of historical results before and after such transactions, we analyzed the impact of the Equity Buyout on our statements of operations. We believe that our results of operations for 2004, 2005 and 2006 are comparable on an annual basis except as it relates to depreciation, depletion and amortization expenses resulting from a change in basis of the underlying properties in 2005. As a result we believe that the non-GAAP measurements for 2005, discussed below, provide a more meaningful basis for comparing our results of operations. A summary of key financial data for 2004, 2005 and 2006 related to our results of operations for the years then ended is presented below.
(a) Natural gas production and sales include volumes and values previously reported as natural gas liquids for 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the non-GAAP combined 2005. Barrels of natural gas liquids volumes have been calculated by converting one barrel of natural gas liquids to six Mcf of natural gas.
(b) Year to year changes relative to 2005 are calculated using non-GAAP combined 2005 totals.
The following is a discussion of our financial condition and results of operations for the years ended December 31, 2004, 2005 and 2006. Information presented for the year ended December 31, 2005 represents the non-GAAP combined total for the 275 day period from January 1, 2005 to October 2, 2005 (predecessor) and the 90 day period from October 3, 2005 to December 31, 2005 (successor).
The comparability of our results of operations from 2004, 2005 and 2006 is impacted by:
· the acquisition of North Coast on January 27, 2004;
· property acquisitions and dispositions, including the sale of Addison on February 10, 2005;
· significant changes in the amount of our long-term debt including the issuance of our senior notes on January 20, 2004 in the amount of $350.0 million and on April 13, 2004 in the amount of $103.3 million (including applicable premium);
· significant fluctuations in oil and gas prices which impact our oil and natural gas revenues;
· changes in our Proved Reserves and their impact on depreciation, depletion and amortization;
· fluctuations associated with use of mark-to-market for derivative financial instruments;
· the Equity Buyout that occurred on October 3, 2005, the significant amount of debt incurred to finance the Equity Buyout and the resulting step-up in accounting basis;
· compensation expenses related to the Equity Buyout and the adoption of SFAS No. 123(R);
· the IPO that closed on February 14, 2006;
· the acquisition of TXOK on February 14, 2006, PGMT on April 28, 2006 and Winchester on October 2, 2006; and
· the incurrence of $1.3 billion of debt incurred to finance the Winchester acquisition.
The availability of a ready market for oil and natural gas and the prices of oil and natural gas are dependent upon a number of factors that are beyond our control. These factors include, among other things:
· the level of domestic production and economic activity generally;
· the availability of imported oil and natural gas;
· actions taken by foreign oil producing nations;
· the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;
· the cost and availability of other competitive fuels, fluctuating and seasonal demand for oil, natural gas and refined products; and
· the extent of governmental regulation and taxation (under both present and future legislation) of the production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels.
Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of the oil and natural gas from any producing well in which we have or may acquire an interest.
Marketing arrangements and backlog
We produce oil and natural gas. We do not refine or process the oil we produce. With the exception of our Black Lake Field in Louisiana, which we sold in November 2004, we do not process a significant
portion of the natural gas or NGLs we produce. At the Black Lake Field, we operated a natural gas processing plant that was 100% dedicated to production from the field.
We sell the majority of the oil we produce under short-term contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each property. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.
We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our natural gas contracts vary in length from spot market sales of a single day to term agreements that may extend for a year or more. Our natural gas customers include utilities, natural gas marketing companies and a variety of commercial and industrial end users. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The prices received for natural gas sold on the spot market varies daily, reflecting changing market conditions. We also gather natural gas for other producers for which we are compensated.
During the year ended December 31, 2004, an industrial purchaser, Alliance Energy Services L.L.C., or Alliance, accounted for 10.6% of our total oil and natural gas revenues. Under our end user contract in 2004 with Alliance, the purchaser was obligated to take all of the natural gas we could produce from a specified gathering system of ours up to 10,000 gross Mmbtu per day (which includes natural gas of other interest owners in the affected wells). We were obligated to use commercially reasonable efforts to supply that volume of natural gas from our wells connected to the gathering system subject to production declines experienced by the affected wells. The sales were priced monthly at the Columbia Gas Transmission Corp. Appalachia Index plus a specified premium. Our revenues under this contract in 2004 aggregated $14.7 million. This contract was replaced with a contract with the actual end user, Alcan Rolled Products-Ravenswood, LLC, beginning January 1, 2005 through December 31, 2007. Under the new contract the end user will purchase all of the natural gas we can produce, subject to well production declines, from the specified gathering system up to 10,000 gross Mmbtu per day (which includes natural gas of other interest owners in the affected wells). The contract price is the monthly Columbia Gas Transmission Corp. Appalachia Index plus a specified premium. Our revenues under this contract in 2005 and 2006 aggregated $20.6 million and $17.5 million, respectively, or 10.1% and 4.9%, respectively, of our total oil and natural gas revenues. During 2006, oil and natural gas sales to Duke Energy and its affiliates totaled 11.6% of our total oil and natural gas revenues.
We may be unable to market all the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas contained in our properties. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.
We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated.
Summary
For purposes of comparative analysis, we have combined the predecessor and successor operating results for the 2005 periods and refer to the combined results as non-GAAP 2005.
For the year ended December 31, 2006, we had income from continuing operations of $139.0 million on consolidated revenues (before impacts of derivative financial instruments) of $355.8 million compared with a net loss from continuing operations of $120.9 million on consolidated revenues of $202.9 million for the non-GAAP combined 2005 period (before impacts of derivative financial instruments). Net income for the 2005 non-GAAP combined period was $1.2 million which reflects a $122.0 million gain from the sale of Addison in February 2005. For the year ended December 31, 2004, net income was $6.0 million on consolidated revenues (before impacts of derivative financial instruments) of $142.0 million. The impact of acquisitions and derivative financial instruments are significant to our results of operations. During 2006, we closed over $1.8 billion of acquisitions of oil and natural gas properties which significantly increased our revenues and related operating costs. In addition, we do not designate our derivative financial instruments as hedges. Therefore, we mark the changes in the fair value of our derivative financial instruments to market at the end of each reporting period. Due to significant fluctuations in the price of oil and natural gas during 2004, 2005 and 2006, the impacts of derivative financial instruments, including the mark-to-market impacts, totaled losses of $50.3 million and $177.5 million for 2004 and non-GAAP combined 2005, respectively, while 2006 activities resulted in derivative gains of $198.7 million, of which $169.2 million is unrealized.
Oil and natural gas sales, production and prices
Total oil and natural gas sales, excluding the impact of derivative financial instruments, for 2006 were $355.8 million compared with $202.9 million for non-GAAP combined 2005 and $142.0 million in 2004. For 2006, natural gas represented 84.0% of our revenues and 88.9% of equivalent production. Both 2005 and 2004 also have natural gas percentages in excess of 80.0% of total revenues and total production. Our equivalent sold production volumes for 2006 were 49.6 Bcfe compared with 23.5 Bcfe for non-GAAP combined 2005, an increase of 111.1%. Equivalent production from our 2006 acquisitions represented over 50% of 2006 total volumes. Sold production volumes for 2004 were 23.0 Bcfe, 2.1% less than non-GAAP combined 2005. The average price per Mcfe, before the impact of derivative financial instruments, was $7.17, $8.62 and $6.16 for 2006, non-GAAP combined 2005 and 2004, respectively.
For 2006, our average price received for natural gas, excluding the impact of derivative financial instruments, was $6.77 per Mcf compared with $8.58 per Mcf in non-GAAP combined 2005 and $6.10 in 2004. The average price received for oil, also excluding the impacts of derivative financial instruments was $62.27 per Bbl, or 16.7% higher than the non-GAAP combined 2005 price of $53.35 per Bbl. The average price per Bbl for 2004 was $38.71. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal condition, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows and related liquidity. Assuming our December 2006 production levels, a change of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues and cash flow of approximately $6.5 million and a change of $1.00 per Bbl of oil sold would result in an increase or decrease in revenues and cash flow of approximately $1.2 million without considering the effects of derivative financial instruments.
Changes in oil and natural gas volumes from our acquisitions, development drilling and exploitation projects combined with significant price fluctuations significantly impacted our operating revenues and
cash flows from operations. In 2006, our revenues (before the impact of derivative financial instruments) increased to $355.8 million from $202.9 million for non-GAAP combined 2005. The total increase of $152.9 million was attributable to an increase of $185.9 million from increased volumes primarily due to 2006 acquisitions. This increase was partially offset by a reduction in our realized price per Mcfe, which lowered revenue by $33.0 million.
During 2006, our acquisitions were focused on East Texas/North Louisiana and Appalachia regions of the United States. TXOK also significantly increased our presence in the Mid-Continent region. Following is a summary of production grouped by our significant producing regions for the years ended December 31, 2004, non-GAAP combined 2005 and 2006.
In January 2007, we completed the sale of our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. This transaction included substantially all of our assets in the Rockies area. If the pending acquisitions of the Vernon Assets and the Southern Gas Assets are consummated, we expect to significantly increase our production in the East Texas/North Louisiana and Mid-Continent areas during 2007.
Derivative financial instruments
Our objective in entering into derivative financial instrument contracts is to manage price 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, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses 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.
The following table presents our derivative financial instrument activities and components of other income. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments. As a result of the pending acquisitions from Anadarko, we will assume additional derivative financial instruments covering a substantial portion of the acquired production.
(a) Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.
Our cash settlements for 2006 increased revenue by $29.4 million compared with cash payments of $85.1 million for non-GAAP combined 2005. The cash payments in 2005 reduced revenue while the 2006 cash receipts increased revenue. The NYMEX oil and natural gas prices that we used to settle our derivative financial instruments varied significantly during 2005 and 2006. In 2005, the impacts of hurricanes caused natural gas prices to reach record highs which resulted in us making significant payments to our counterparties. Cash payments for the non-GAAP combined 2005 period includes payments totaling $52.6 million made in January and March 2005 to counterparties to terminate existing derivative contracts and enter into new derivative contracts at higher underlying product prices.
Our mark-to-market non-cash changes in the value of derivative financial instruments for 2006 resulted in a gain of $169.2 million compared with a $92.5 million loss in the prior year. The significant fluctuation was again attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.
We expect to continue our comprehensive derivative financial instrument program as part of our overall acquisition and financing strategy to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. In connection with our acquisitions, we typically hedge a portion of future production acquired in order to lessen the variability of our returns on shareholders’ equity and to protect our shareholders’ equity by supporting our ability to meet our debt service obligations and stabilize cash flows.
As of December 31, 2006, we had derivative financial instruments, excluding the pending acquisitions from Anadarko, in place hedging approximately 79% of our expected 2007 oil production and approximately 83% of our expected 2007 natural gas production . These levels are consistent with our acquisition and financing strategy and average historical levels of hedged production.
Oil and natural gas operating costs
Operating costs, which include labor, materials and supplies necessary to produce our oil and natural gas were $46.5 million, or $0.94 per Mcfe for 2006, compared with $20.1 million, or $0.85 per Mcfe for non-GAAP combined 2005. The increase of $26.5 million is due primarily to $21.9 million of costs associated with the 2006 acquisitions, including TXOK, PGMT and Winchester. The per unit increase in cost reflects a general increase in the cost of goods and services for all of our producing areas.
Operating costs for 2004 were $19.8 million, or $0.86 per Mcfe, compared with $20.1 million, or $0.85 per Mcfe, for non-GAAP 2005. Operating costs per unit outside of our Appalachia area decreased to $0.89 per Mcfe in non-GAAP combined 2005 from $0.97 in 2004. This decrease was due primarily to sales of producing properties in 2004 which had higher operating costs. Per unit costs in our Appalachia region increased to $0.82 per Mcfe in non-GAAP combined 2005 from $0.74 in 2004 due primarily to higher personnel related costs and increased costs of goods and services used in the operations.
Production and ad valorem taxes
Production and ad valorem taxes were $22.3 million, $11.0 million and $8.4 million for 2006, non-GAAP combined 2005 and 2004, respectively. Production taxes are set by state and local governments and vary as to the tax rate and the value to which the rate is applied. Further, ad valorem taxes in Texas, where a substantial amount of our oil and natural gas is produced, are based partially on the value of oil and natural gas reserves, which can fluctuate significantly depending on prices for these products. On a percentage of sales basis, our 2006 production and ad valorem taxes were 6.3% of oil and natural gas sales, excluding the impact of derivative financial instruments compared with 5.4% for non-GAAP combined 2005 and 5.9% in 2004. The change in the consolidated rate in 2006 compared with non-GAAP combined 2005 is due to a higher percentage of revenues from our East Texas, North Louisiana and Mid-Continent producing areas which have higher combined production and ad valorem tax rates than our Appalachia producing area.
Depreciation, depletion and amortization
The following table presents our depreciation, depletion and amortization expenses for 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, non-GAAP combined 2005 and 2006. The depreciation, depletion and amortization rate per Mcfe produced varies significantly for each of the periods presented due to the Equity Buyout on October 3, 2005 which resulted in a new stepped-up basis of accounting, which increased the calculated rate per Mcfe from $1.65 per Mcfe to $2.42 per Mcfe for the 90 day period from October 3, 2005 to December 31, 2005. During 2006, our acquisition of TXOK, PGMT and Winchester further increased the depreciation, depletion and amortization rate to $2.74 per Mcfe in 2006.
(a) Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.
Accretion of discount on asset retirement obligations increased to $2.0 million in 2006 from $0.8 million each in non-GAAP combined 2005 and the year ended December 31, 2004. The increase in 2006 is due to the combination of significant well additions and related plugging liabilities in connection with our 2006 acquisitions and increased estimates for the costs to plug and abandon properties. The increased estimates for plugging and abandoning properties reflect increased costs for labor, rig rates and materials used in those operations.
General and administrative expenses
The following table presents our general and administrative expenses for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from
October 3, 2005 to December 31, 2005, the twelve months non-GAAP combined 2005 and the year ended December 31, 2006 and changes for each of the years then ended. The table also reflects significant non-recurring expenses incurred in connection with the October 3, 2005 Equity Buyout.
(a) Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.
Net general and administrative expenses for the year ended December 31, 2006 were $41.2 million compared with $95.8 million in non-GAAP combined 2005, a decrease of $54.6 million. Each of the respective years contains significant and notable variances. In 2006, we experienced significant increases in personnel and related support facilities. These increased personnel related expenses totaled approximately $7.2 million of increased cash expenses and increases of approximately $4.3 million from share-based compensation. We also incurred approximately $9.2 million of legal and project-oriented costs including (i) audit and legal fees in connection with our 2006 acquisitions, (ii) fees associated with services related to the formation of EXCO Partners, (iii) costs for implementation and compliance with Section 404 of the Sarbanes-Oxley Act of 2002 and (iv) expenses incurred for conversion of our information technology systems to a common platform. General and administrative costs for 2005 included non-recurring costs of $73.7 million ($44.1 million of which was non-cash stock compensation) related to the Equity Buyout.
When comparing non-GAAP combined 2005 general and administrative costs to the year ended December 31, 2004, the most significant variances are related to the non-recurring costs related to the Equity Buyout in 2005 of $73.7 million. Other significant increases between the periods included increased costs in 2005 for share-based compensation resulting from the adoption of SFAS No. 123R in October 2005, increased personnel costs and higher legal and accounting expenses for the analysis of strategic alternatives considered in light of the sale of Addison.
Stock based and other compensation expense
We adopted the provisions of SFAS No. 123(R) on October 3, 2005 upon closing of the Equity Buyout. Upon closing of the IPO, Holdings merged with us and we assumed the EXCO Holdings 2005 Long-Term Incentive Plan, or the 2005 Long-Term Incentive Plan.
During 2006, we issued options to purchase approximately 3.6 million shares of common stock under our 2005 Long-Term Incentive Plan to our employees, which resulted in non-cash compensation expenses of $6.5 million to general and administrative expenses and $1.4 million of capital charges to our full cost pool.
Immediately prior to the closing of the Equity Buyout on October 3, 2005, we recorded stock based and other compensation expense for the following items, which are included as part of the 275 day period ended October 2, 2005:
· A non-cash charge of approximately $44.1 million as a result of the acquisition by Holdings II of all of the shares of Class B common stock of EXCO Holdings held by certain members of our management and other employees. The offset to this expense was to additional paid-in capital. The stockholder agreements governing the Class A and Class B common stock of EXCO Holdings provided that, upon the occurrence of certain specified events, including the change of control that occurred upon the Equity Buyout:
· the holders of the Class A shares would receive the first $175.0 million of proceeds, and
· the remaining proceeds in excess of the $175.0 million would be allocated on a pro-rata basis to the holders of the Class A shares and the Class B shares. For financial accounting purposes, the Class B shares were considered to be a “variable” plan since a holder of the shares had to be employed at the date of the change of control to receive fair value for the Class B shares. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.
· A charge of $17.8 million for payments made to holders of options to purchase Class A shares of EXCO Holdings less options held by the EXCO Holdings Employee Stock Participation Plan, or ESPP. This amount was paid to option holders at the time of the Equity Buyout by EXCO Holdings to purchase all stock options outstanding at that time. The amount represented the cumulative difference between the $5.197 per share proceeds for the Class A shares and the exercise price of the outstanding stock options times the number of stock options outstanding.
· A charge of $8.3 million for payments made to our employees who were participants in the ESPP. This amount was paid by EXCO Holdings at the time of the Equity Buyout and was based upon shares of EXCO Holdings Class A and Class B common stock that were reserved, but unissued, for the ESPP. All employees on the date of the Equity Buyout who were not direct owners of EXCO Holdings Class A or Class B common stock received payments under the ESPP. For financial accounting purposes, the ESPP was considered to be a “variable” plan since, to be eligible, a recipient had to be employed at the date of the change of control to receive a payment. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.
· A charge of $2.6 million for accelerated payments made by EXCO Holdings to certain employees of EXCO Resources under the EXCO Holdings Employee Bonus Retention Plan, or the Retention Plan. The Retention Plan was accelerated, paid in full and terminated upon consummation of the Equity Buyout.
During the 90 day period from October 3, 2005 to December 31, 2005, we recorded a non-cash charge of $2.2 million, of which $1.0 million was capitalized as part of our proved oil and natural gas properties as a result of the granting of options to purchase 4,992,650 shares of common stock under the 2005 Long-Term Incentive Plan. The offset to this expense was to shareholder’s equity as additional paid-in capital.
Interest expense
During 2006, our consolidated debt, including our senior notes, increased to $2.1 billion from $811.8 million as of December 31, 2005. The December 31, 2005 debt included $350.0 million associated with an interim bank loan which was funded on October 2, 2005 to finance the Equity Buyout. This interim bank loan was paid in full upon completion of our IPO on February 14, 2006. Prior to October 2, 2005, our borrowings under the EXCO Resources credit agreement were not significant. The increase to our
consolidated debt in 2006 reflects borrowings under the EXCO Resources credit agreement and the EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement to fund our 2006 acquisitions which occurred between February 14, 2006 and continued throughout the year. As a result, our 2006 interest expenses increased to $84.9 million from $46.1 million in non-GAAP combined 2005. On October 2, 2006, EPOP, a wholly-owned unrestricted subsidiary, closed on the acquisition of Winchester Energy. This acquisition was funded by a $650.0 million loan under the EPOP Senior Term Credit Agreement and $651.0 million of borrowings under the EPOP Revolving Credit Facility. EPOP’s debt is not guaranteed by EXCO. The following table presents our interest expense, including increases of $31.6 million during the fourth quarter of 2006 of interest and amortization of deferred financing costs for EPOP.
(a) Year to year changes relative to 2005 are calculated using the non-GAAP combined 2005 totals.
Interest expense for non-GAAP combined 2005 was $46.1 million compared with $34.6 million in 2004, an increase of $11.5 million, which is primarily attributable to the interest on the interim bank loan.
Income taxes
The following table presents a reconciliation of our income tax provision (benefit) for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006.
The income tax expense/benefit on our loss from continuing operations for the 12 months ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005 and benefit on our income from continuing operations for the 90 day period from October 3, 2005 to December 31, 2005 differs from the amounts calculated using the U.S. federal statutory rate. The December 31, 2004 expense includes a $0.9 million tax benefit from reductions to income tax rates and provisions for the deduction of crown royalties in Canada which became effective in May 2004. This benefit is reflected as a component of continuing operations pursuant to SFAS No. 109 and EITF 93-13.
On October 22, 2004, the President signed the American Jobs Creation Act of 2004, or the Act. The Act created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. We repatriated Cdn. $74.5 million ($59.6 million) in an extraordinary dividend, as defined in the Act, from Addison on February 9, 2005. We recognized a tax liability of $8.2 million as of December 31, 2004 related to the extraordinary dividend. As a result of certain technical advice issued by the U.S. Treasury Department, we reduced the tax liability by $2.1 million during the second quarter of 2005. EXCO Resources filed amended quarterly reports on Form 10-Q/A that included restated financial statements for the quarters ended June 30, 2005 and September 30, 2005 to reflect the tax benefit in the earlier quarter and to classify the benefit as a component of continuing rather than discontinued operations in the September 30, 2005 quarter. This additional tax benefit is recognized as a component of taxes from continuing operations pursuant to SFAS No. 109 and EITF 93-13, which require that a tax effect of a change in enacted rates be allocated to continuing operations without regard to whether the item giving rise to the effect is a component of discontinued operations.
In June 2005, the state of Ohio enacted new legislation that changed the method of taxing businesses that operate in Ohio. We have significant operations in the state of Ohio through our North Coast subsidiary. As a result of the new tax legislation in Ohio, we recognized a reduction to our deferred tax
liability of $5.2 million as of December 31, 2005, which reflects the change in Ohio tax rates and the impacts of our stepped-up basis resulting from the Equity Buyout. The 275 day period ended October 2, 2005 also includes a $2.1 million tax benefit related to an extraordinary dividend received from Addison, our former wholly-owned Canadian subsidiary.
On May 18, 2006, the Texas governor signed into law a Texas Margin tax that replaces the current franchise tax effective January 1, 2007. We had recorded the effect of the change in the tax rate on our existing deferred balances in the second quarter of 2006. Our deferred income tax related to the Texas Margin tax is $0.9 million at December 31, 2006.
On February 10, 2005, we sold all of the issued and outstanding shares of common stock of Addison and two intercompany notes that Addison owed to ROJO. The aggregate purchase price after contractual adjustments was Cdn. $551.3 million ($443.3 million) less the payment of the outstanding balance under Addison’s credit facility of Cdn. $90.1 million ($72.1 million). We have recognized a gain from the sale of Addison of $175.7 million before income tax expense of $50.1 million related to the gain. The income tax is composed of:
Income taxes from discontinued operations for the 275 day period ended October 2, 2005 reflects the income tax on the gain of $50.1 million as discussed above, an income tax benefit of $1.3 million from Addison’s operations during the period January 1, 2005 to February 10, 2005, and approximately $0.5 million of Canadian income taxes withheld on interest paid by Addison in 2005 on the intercompany notes.
The loss from discontinued operations of $4.4 million before the gain on the sale of Addison and income taxes from discontinued operations for the 275 day period ended October 2, 2005 includes:
· approximately $3.8 million in losses from commodity price risk management activities; and
· approximately $2.7 million in severance for employees not hired by the purchaser and management retention bonus payments to certain Addison employees that were accelerated as a result of the sale.
Liquidity, capital resources and capital commitments
General
Most of our growth has resulted from acquisitions and our development and exploitation programs. Consistent with our strategy of acquiring and developing reserves, we have an objective of maintaining financing flexibility. In the past, we have utilized a variety of sources of capital to fund our acquisition, development and exploitation programs and to fund our operations. Our general financial strategy is to use a combination of cash flow from operations, bank financing, cash received from the sale of oil and natural gas properties and the sale or issuance of equity and debt securities to fund our operations, conduct development and exploitation activities and to fund acquisitions. The EXCO Resources credit agreement, as amended, is a $1.25 billion facility with a $600.0 million borrowing base and a $500.0 million aggregate commitment. The EPOP Revolving Credit Agreement is a $750.0 million facility with a $750.0 million borrowing base and aggregate commitment. On April 1, 2007, the conforming borrowing base on the
EPOP Revolving Credit Facility becomes $650.0 million. The EPOP Senior Term Credit Agreement is a $650.0 million facility. We do not have a set budget for acquisitions as these tend to be opportunity driven. Historically, we have used the proceeds from the issuance of equity and debt securities and borrowings under our credit agreements to raise cash to fund acquisitions. Our ability to borrow from sources other than our credit agreements is subject to restrictions imposed by our lenders. In addition, our Indenture governing our senior notes contains restrictions on incurring indebtedness and pledging our assets.
On February 14, 2006, EXCO Resources completed its IPO of 50,000,000 shares of its common stock for aggregate net proceeds to EXCO Resources of $617.5 million after underwriters’ discount. The net proceeds from the IPO, together with cash on hand of $215.3 million and additional borrowings of $65.0 million under EXCO’s credit agreement, were used as follows:
· $360.0 million to repay $350.0 million in principal plus accrued and unpaid interest under the interim bank loan incurred in connection with the Equity Buyout;
· $158.8 million to fund the redemption of the $150.0 million of TXOK preferred stock, plus accumulated and unpaid dividends in connection with the acquisition of ONEOK Energy;
· $375.5 million to repay $171.8 million in principal plus accrued and unpaid interest of $0.9 million under the TXOK credit facility ($137.0 remained outstanding under this facility following the IPO) and $200.0 million in principal plus accrued and unpaid interest of $2.8 million under the TXOK term loan, both loans having been incurred in connection with the acquisition of ONEOK Energy; and
· $6.0 million to pay fees and expenses in connection with the IPO.
On February 21, 2006, we issued 3,615,200 additional shares of our common stock pursuant to an exercise by the underwriters of their over-allotment option for net proceeds to EXCO Resources of approximately $44.7 million. The net proceeds were used to reduce outstanding indebtedness under the EXCO Resources credit agreement.
On February 10, 2005, we sold Addison for $443.3 million after contractual adjustments. The net cash proceeds could only be utilized by us in accordance with the terms of the Indenture governing the senior notes and our credit agreement. In addition, $120.6 million of these proceeds were pledged as collateral under our credit agreement and the senior notes. The credit agreement security interest on these proceeds was released in conjunction with the commencement of the senior notes purchase offer on November 2, 2005 related to the sale of Addison, or the Addison senior notes purchase offer. Upon completion of the Addison senior notes purchase offer on December 7, 2005, the senior notes security interest was released.
Net cash provided by operating activities was $227.7 million for the twelve months ended December 31, 2006. At December 31, 2006, our cash and cash equivalents balance was $22.8 million, a decrease of $204.1 million from December 31, 2005 primarily as a result of the repayment of indebtedness incurred in connection with the Equity Buyout and our acquisition of TXOK in the first quarter of 2006.
Acquisitions and capital expenditures
The following table presents our capital expenditures and entity acquisitions for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, non-GAAP combined 2005 and the year ended December 31, 2006.
On January 27, 2004, we completed the North Coast acquisition for $215.1 million. We funded the North Coast acquisition with the net proceeds from the $350.0 million offering of our senior notes.
In July and August 2004, we acquired natural gas properties located in Rusk County, Texas for a total purchase price of $36.9 million. We funded the acquisition with $32.0 million in borrowings under our credit agreement and from surplus cash. The properties acquired consisted of 32 producing natural gas wells, which we operate, and a number of proved undeveloped and unproved drilling locations.
In November and December 2004 we acquired working interests in, and became operator of, 228 oil and natural gas wells, unproved drilling locations and related natural gas gathering systems in Centre and Clearfield Counties, Pennsylvania. The total purchase price, after contractual adjustments, was approximately $40.0 million and was funded with borrowings under our credit agreement.
On January 21, 2005, we acquired producing natural gas properties and unproved drilling locations located in the Minden Field in East Texas for a total purchase price of $17.7 million. We funded the acquisition with $13.3 million in borrowings under the EXCO Resources credit agreement and from surplus cash. We also acquired a small natural gas gathering system as part of this acquisition for an additional $0.7 million.
In the third quarter of 2005, we acquired natural gas properties located in the Appalachia area for an aggregate purchase price of $81.7 million. We funded these acquisitions with surplus cash. The properties acquired consisted of 744 producing natural gas wells, which we operate, and over 500 future drilling locations, of which 320 were classified as proved.
For the year 2005, we spent approximately $53.1 million for drilling, exploitation and development capital expenditures in the United States and were contractually obligated to spend $13.4 million for our drilling and exploitation activities as of December 31, 2005.
During 2006, we completed the following acquisitions of oil and natural gas properties and undeveloped acreage, including the acquisition of Winchester, our largest acquisition to date. A summary of these acquisitions and their related values to oil and natural gas properties and gathering facilities, net of contractual adjustments is presented on the following table.
Details of the components of the purchase price and related allocation of the purchase price to the acquired assets and liabilities of our corporate acquisitions in 2006 are as follows:
On February 14, 2006, at closing of our IPO, we acquired the 89% of TXOK that we did not already own by redeeming their outstanding preferred stock and assuming TXOK’s outstanding debt of $512.5 million. The purchase price, net of cash acquired was $665.1 million.
In April and May 2006, we acquired producing properties and undeveloped acreage in West Texas and the Cotton Valley trend in East Texas. The purchase price of these assets was $135.8 million, after contractual adjustments, which was funded with indebtedness drawn under the EXCO Resources credit agreement.
On April 28, 2006, we closed an acquisition and acquired 100% of the common stock of PGMT for a net purchase price of $113.0 million. The purchase price included the assumption of $13.1 million of debt and $38.1 million outstanding derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under the EXCO Resources credit agreement, we paid the assumed debt and terminated the assumed commodity hedges. The acquisition was accounted for as a purchase in accordance with SFAS No. 141.
On August 4, 2006, we acquired producing properties and undeveloped acreage in Wyoming. The purchase price of these assets was $27.5 million, subject to post-closing contractual adjustments, and was funded by $20.0 million of indebtedness drawn under the EXCO Resources credit agreement and $7.5 million of available cash.
On September 19, 2006, we acquired producing properties and undeveloped acreage in West Virginia. The purchase price, after contractual adjustments, was $49.4 million.
On October 2, 2006, we closed our acquisition of Winchester and its affiliated entities from Progress Energy, Inc. for approximately $1.1 billion in cash, net of purchase price adjustments. The assets included producing and undeveloped acreage located in the Cotton Valley, Hosston and Travis Peak trends in East Texas and North Louisiana. The assets also include six gathering systems with 300 miles of pipe and a 54 mile pipeline system. The acquisition was financed with a $650.0 million loan under the EPOP Senior Term Credit Agreement and $651.0 million of borrowings under the EPOP Revolving Credit Facility. We formed a new subsidiary to purchase Winchester and that subsidiary became an unrestricted subsidiary as defined under the Indenture governing our senior notes and the EXCO Resources credit agreement. Concurrent with the closing of the purchase of Winchester, we contributed to EPOP all of our East Texas properties, with an estimated value of approximately $425.0 million, and related indebtedness of approximately $150.0 million. EPOP is not a guarantor of the EXCO Resources credit agreement nor does EXCO Resources guarantee the debt of EPOP.
On December 22, 2006, Vernon, our wholly-owned subsidiary, entered into the Vernon Purchase Agreement with Anadarko Petroleum Corporation and Anadarko Gathering Company to acquire the Vernon Assets for a purchase price of approximately $1.6 billion in cash, subject to certain purchase price adjustments. This acquisition is expected to close on or about March 30, 2007. On February 1, 2007, EXCO Resources entered into the Southern Gas Purchase Agreement with Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP to acquire the Southern Gas Assets for a purchase price of approximately $860.0 million in cash, subject to certain purchase price adjustments. This acquisition is expected to close on or about May 2, 2007. See “Item 1. Business-Significant subsequent events” for a description of our pending acquisitions of the Vernon Assets and the Southern Gas Assets from Anadarko.
To ensure that we have sufficient financing to complete the pending acquisitions from Anadarko, we received a revised commitment letter dated as of February 1, 2007, from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A. This commitment letter supersedes and replaces the commitment letter we received on December 22, 2006 in conjunction with our entering into the Vernon Purchase Agreement. The new commitment letter, as subsequently supplemented, provides for a senior secured revolving credit
facility commitment in the amount of $1.8 billion and an undertaking to arrange a bridge loan facility in the amount of $1.1 billion if requested, or collectively the new credit facilities. If used to finance these acquisitions, the new credit facilities will contain customary representations, warranties and covenants, and the closing of the new credit facilities will be subject to the satisfaction of customary closing conditions. We are also pursuing other financing alternatives, including a proposed private placement of preferred stock. For a discussion of the proposed terms of the preferred stock, see “-Proposed recapitalization.”
During 2006, we sold oil and natural gas properties for proceeds totaling approximately $5.2 million. On January 5, 2007, we completed the sale of our oil and natural gas properties in the Wattenberg field in Colorado for $131.9 million. The proceeds from this sale were deposited with a qualified intermediary to effect a like-kind-exchange for Federal income tax purposes. The proceeds from this sale will be used to fund our pending acquisitions from Anadarko.
For 2007, we have budgeted approximately $314.7 million, excluding the pending acquisitions from Anadarko, for our development, exploitation and operational activities in the United States. We have also budgeted approximately $7.9 million in 2007 for our additional acquisition-related expenditures and approximately $2.0 for our information technology expenditures. In addition, we expect to add $80.4 million for projects associated with the pending acquisitions on a pro forma basis for 2007 (as if we acquired the pending acquisitions as of January 1, 2007). This additional capital brings our expected pro forma 2007 development, exploitation and operational program to $395.1 million.
We expect to utilize our current cash balance, cash flow from operations and available funds under our credit agreement to fund our acquisitions, capital expenditures and working capital. We also plan on selling non-strategic assets to assist with meeting our business objectives.
We believe that our capital resources from existing cash balances, cash flow from operating activities and borrowing capacity under our credit agreements are adequate to meet the cash requirements of our business. However, future cash flows are subject to a number of variables including production volumes, fluctuations in oil and natural gas prices and our ability to service the debt incurred in connection with the Winchester acquisition. If cash flows decline we would be required to reduce our capital expenditure budget which in turn may affect our production in future periods. Our operations and other capital resources may not provide cash in sufficient amounts to maintain or initiate planned levels of capital expenditures. We have experienced increased costs for tubular goods and for certain services during 2005 and 2006. Further, we have encountered difficulties in contracting for drilling rigs and other services due to high demand. Currently, we do not believe that these conditions have had a significant impact upon our capital expenditures programs or our results of operations. If the conditions continue, however, projects may be delayed due to lack of services or materials or we may have to delay projects to stay within our capital budget.
71¤4% senior notes due January 15, 2011
On January 20, 2004, we issued $350.0 million principal amount of our senior notes pursuant to Rule 144A and Regulation S under the Securities Act at a price of 100% of the principal amount. Approximately $168.3 million of the proceeds of the issuance of the senior notes was used to finance the acquisition of outstanding common stock, options and warrants of North Coast along with associated fees and expenses. Of the remaining proceeds, $113.8 million was used to repay a portion of our debt under our U.S. credit agreement, North Coast’s credit facility indebtedness and accrued interest and fees, $50.1 million was used to repay in full principal and interest on our senior term loan, approximately $10.6 million was used to pay fees and costs associated with the offering, with the remainder, approximately $7.2 million, available for general working capital purposes.
On April 13, 2004, we issued an additional $100.0 million principal amount of our senior notes pursuant to Rule 144A at a price of 103.3% of the principal amount having the same terms and governed
by the same Indenture as the senior notes issued on January 20, 2004. Of the total proceeds of $103.3 million, approximately $98.8 million was used to repay substantially all of our outstanding indebtedness under the Canadian credit agreement, approximately $1.2 million was used for fees and expenses associated with the offering, with the remainder, approximately $3.3 million, available for general working capital purposes.
Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011. Prior to January 15, 2007, we may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the senior notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the senior notes. If a change of control occurs, subject to certain conditions, we must offer holders of the senior notes an opportunity to sell us their senior notes at a purchase price of 101% of the principal amount of the senior notes, plus accrued and unpaid interest to the date of the purchase.
The Equity Buyout constituted a change of control under the Indenture governing our senior notes. As required by the Indenture, we commenced an offer to purchase all $450.0 million of senior notes outstanding at 101% of the principal amount plus accrued and unpaid interest through the date of purchase. The change of control offer expired on December 9, 2005 and $5.3 million in principal amount of senior notes were tendered, which was paid with available cash on hand, including the remaining net proceeds from the sale of Addison. As a result of the Equity Buyout, the carrying value of our senior notes was increased to $468.0 million, the fair value of the senior notes on October 3, 2005.
The Indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:
· incur or guarantee additional debt and issue certain types of preferred stock;
· pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
· make investments;
· create liens on our assets;
· enter into sale/leaseback transactions;
· create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
· engage in transactions with our affiliates;
· transfer or issue shares of stock of subsidiaries;
· transfer or sell assets; and
· consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
On February 14, 2006, concurrent with the closing of our IPO, TXOK and its subsidiaries became restricted subsidiaries under and guarantors of the senior notes. On May 4, 2006, PGMT became a guarantor of the senior notes. In conjunction with the formation of EXCO Partners and the Winchester acquisition on October 2, 2006, certain of our existing subsidiaries, specifically ROJO Pipeline, Inc. and those TXOK subsidiaries that hold direct or indirect interests in certain of our East Texas assets were released from their guaranties under the senior notes and are now deemed unrestricted subsidiaries thereunder. EXCO Resources also contributed all of its directly held East Texas assets to EXCO Partners. EXCO Partners and its general partners, which are also subsidiaries of EXCO Resources, and all of EXCO Partners’ subsidiaries are deemed unrestricted subsidiaries under the Indenture governing the senior notes and are not guarantors of the senior notes.
Credit agreements
EXCO Resources credit agreement
On March 17, 2006, EXCO Resources, Inc. and certain of its subsidiaries entered into an amended and restated credit agreement, or the EXCO Resources credit agreement, with certain lenders, JPMorgan Chase Bank, N.A., as administrative agent, and J.P. Morgan Securities Inc., as sole bookrunner and lead arranger. This amendment established a new borrowing base of $750.0 million under the EXCO Resources credit agreement reflecting the addition of the assets of TXOK. TXOK and its subsidiaries became guarantors of the EXCO Resources credit agreement. The amendment also provided for an extension of the EXCO Resources credit agreement maturity date to December 31, 2010. The borrowing base is redetermined each November 1 and May 1, beginning November 1, 2006. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. Financial covenants under the amended credit agreement require that we:
· maintain a consolidated current ratio (as defined under the EXCO Resources credit agreement) of at least 1.0 to 1.0 at the end of any fiscal quarter; and
· not permit our ratio of consolidated indebtedness to consolidated EBITDAX (as defined under the EXCO Resources credit agreement) to be greater than 3.5 to 1.0 at the end of each fiscal quarter.
Borrowings under the EXCO Resources credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our oil and natural gas properties including TXOK’s Oklahoma properties and North Coast. and their respective subsidiaries. Our borrowings are collateralized by a first lien mortgage providing a security interest in the value of our Proved Reserves which is at least 125% of the aggregate commitment. The aggregate commitment is the lesser of (i) $1.25 billion and (ii) the borrowing base, however, the initial aggregate commitment was $300.0 million. This aggregate commitment increased to $500.0 million on May 11, 2006, was reduced to $400.0 million on October 2, 2006, and was increased back to $500.0 million on February 2, 2007.
At our option, borrowings under the EXCO Resources credit agreement accrue interest at one of the following rates:
· the sum of (i) the greatest of the administrative agent’s prime rate, the base CD rate plus 1.0% or the federal funds effective rate plus 0.50% and (ii) an applicable margin, which ranges from 0.0% up to 0.75% depending on our borrowing usage; or
· the sum of (i) LIBOR multiplied by the statutory reserve rate and (ii) an applicable margin, which ranges from 1.0% up to 1.75% depending on our borrowing usage.
We typically elect to borrow funds using the LIBOR interest rate option described above. At December 31, 2005 and 2006, the six month LIBOR rates were 4.70% and 5.37% which would result in interest rates of approximately 5.95% and 6.62%, respectively, on any new indebtedness we may incur under the EXCO Resources credit agreement. At December 31, 2005 and 2006, we had $1,000 and $339.0 million, respectively, of outstanding indebtedness under the EXCO Resources credit agreement.
Additionally, the EXCO Resources credit agreement contains a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and a prohibition on the payment of dividends on our common stock. As of December 31, 2006, we were in compliance with the covenants contained in the EXCO Resources credit agreement.
In connection with the contribution by EXCO Resources to EXCO Partners of EXCO Resources’ East Texas assets, EXCO Resources entered into an amendment to its credit agreement, or First
Amendment. The First Amendment generally consents to and facilitates the contribution of the East Texas assets to EXCO Partners and provides that EXCO Partners, its subsidiaries and its general partners, all of which are subsidiaries of EXCO, are unrestricted subsidiaries under the EXCO Resources credit agreement, are not subject to the terms thereof and are no longer guarantors thereof. In addition, the assets contributed by EXCO Resources were released from the mortgages securing the credit agreement. Moreover, the assets of EXCO Partners and its subsidiaries have not been pledged under the EXCO Resources credit agreement and none of EXCO Partners or the other unrestricted subsidiaries have guaranteed the EXCO Resources credit agreement. The First Amendment also provides that the borrowing base under the EXCO Resources credit agreement shall be reduced to $600.0 million, with an aggregate commitment of $400.0 million (increased back to $500.0 million on February 2, 2007). The First Amendment also revises the covenants regarding the format of the financial statements to be delivered by EXCO Resources and consents to the contingent equity contribution obligation described below under “EXCO Resources Equity Contribution Agreement” subject to certain conditions. The First Amendment also amends certain covenants to address the relationship with EXCO Partners. Prior to any public offering by EXCO Partners, EXCO Resources may not permit the subsidiaries through which EXCO Resources owns the equity of EXCO Partners to incur any indebtedness or incur any lien. Prior to any public offering by EXCO Partners, EXCO Resources is required to own 100% of the equity of EXCO Partners. As of February 28, 2007, $407.0 million of indebtedness was outstanding under the EXCO Resources credit agreement and we had $91.5 million of availability under the EXCO Resources credit agreement. Our consolidated debt as of February 28, 2007, which includes EPOP’s debt, the EXCO Resources credit agreement and our senior notes, totals $2.2 billion. We are in compliance with the financial covenants of the EXCO Resources credit agreement as of December 31, 2006.
EPOP Revolving Credit Facility
To finance the Winchester acquisition and the $150.0 million payment to EXCO Resources for its East Texas assets, EXCO Partners’ wholly-owned subsidiary, EPOP, entered into the EPOP Revolving Credit Facility dated October 2, 2006, with a group of lenders led by JPMorgan Chase Bank, N.A. The EPOP Revolving Credit Facility has a face amount of $750.0 million with an initial borrowing base of $750.0 million and an initial conforming borrowing base of $650.0 million. The conforming borrowing base is the amount of borrowings upon which interest is computed on a lower premium to LIBOR than borrowings which exceed the conforming borrowing base. The borrowing base must be conforming by April 1, 2007. The EPOP Revolving Credit Facility is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries. We executed an amendment dated effective December 31, 2006, the EPOP Revolver First Amendment, which amends certain financial covenants contained in the EPOP Revolving Credit Facility. The EPOP Revolver First Amendment was sought due to our inability to comply with the leverage ratio and interest coverage ratio tests, as defined below, as of December 31, 2006. The original financial covenant ratios were negotiated assuming a more accelerated drilling program, which would have resulted in higher forecasted production. In addition, interest expense attributable to the EPOP Senior Term Credit Agreement was higher than originally forecast as the final negotiated interest rate exceeded our initial estimates when the covenants were being negotiated. Management and the lenders believe these revised covenants are more consistent with the actual operational activities contemplated at EPOP during 2007. As amended, the EPOP Revolving Credit Facility contains the following financial covenants:
· EPOP’s Consolidated Current Ratio (as defined) as of the end of any fiscal quarter ending after September 30, 2006 is not permitted to be less than 1.00 to 1.00. The EPOP Revolver First Amendment did not revise this covenant.
· EPOP’s ratio of (A) Consolidated Funded Indebtedness (as defined) as of the end of a fiscal quarter to (B) Consolidated EBITDAX (as defined) shall not be greater than:
· 6.00 to 1.00 (increased from 5.00 to 1.00) for the quarter ending December 31, 2006. For purposes of the December 31, 2006 Consolidated EBITDAX, the December 31, 2006 quarter shall be multiplied by four (4);
· 5.50 to 1.00 (increased from 4.00 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX calculated using a defined trailing period multiplied by a fraction);
· 5.50 to 1.00 (increased from 4.00 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);
· 5.25 to 1.00 (increased from 4.00 to 1.00) for the quarter ended December 31, 2007, and
· 4.00 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.
· EPOP will not permit its ratio of Consolidated EBITDAX to Consolidated Interest Expenses (as defined) to be less than:
· 1.50 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2006 (Consolidated EBITDAX and Consolidated Interest Expenses for such quarter to be multiplied by four);
· 1.75 to 1.00 (lowered from 2.50 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX and Consolidated Interest Expenses calculated using a defined trailing period multiplied by a fraction);
· 1.75 to 1.00 (lowered from 2.50 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX and Consolidated Interest Expenses calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);
· 2.00 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2007, and
· 2.50 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.
· Finally, EPOP will not permit its ratio of net present value (calculated pursuant to the terms of the EPOP Revolving Credit Facility) to Consolidated Funding Indebtedness (as defined) to be less than (i) 1.15 to 1.00 (unchanged) determined as of December 31, 2006 or (ii)1.25 to 1.00 (unchanged) determined as of each succeeding June 30 and December 31.
The EPOP Revolving Credit Facility, as amended, contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Revolving Credit Facility matures four years from the closing date and has an initial drawn interest rate of LIBOR + 175 basis points (“bps”) and an undrawn commitment fee of 37.5 bps on the first $650.0 million of the EPOP Revolving Credit Facility. To the extent usage exceeds the initial conforming borrowing base, the EPOP Revolving Credit Facility will have an initial drawn interest rate of LIBOR + 250 bps and an undrawn commitment fee of 50 bps on the portion of the borrowings that exceed the initial conforming borrowing base. Finally, as a condition precedent to the funding of the EPOP Revolving Credit Facility, EPOP is required to hedge 75% of proved developed producing production through 2010. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP. The initial amount borrowed under this facility was $651.0 million at closing of the Winchester merger and the weighted
average interest rate as of December 31, 2006, is 7.19%. As of February 28, 2007, $643.5 million was outstanding under this facility. We are in compliance with the financial covenants contained in the EPOP Revolving Credit Facility, as amended, as of December 31, 2006.
EPOP Senior Term Credit Agreement
In connection with the Winchester acquisition and the EXCO Resources asset contribution, EPOP entered into the EPOP Senior Term Credit Agreement, dated October 2, 2006 (as amended and restated as of October 13, 2006), with JPMorgan Chase Bank, N.A., as administrative agent. The aggregate principal amount is $650.0 million. The EPOP Senior Term Credit Agreement is secured by a second priority lien on all of the properties securing the EPOP Revolving Credit Facility, including 100% of the stock of subsidiaries, and is guaranteed by all existing and future subsidiaries. Financial covenants governing the EPOP Senior Term Credit Agreement include the same net present value ratio contained in the EPOP Revolving Credit Facility, a Leverage Ratio computed similarly to the covenant contained in the EPOP Revolving Credit Facility that cannot exceed 5.50 to 1.00 for applicable periods, and an Interest Coverage Ratio that cannot be less than 2.00 to 1.00 for any applicable period. The debt covenant tests for the EPOP Senior Term Credit Agreement begin with the quarter ended March 31, 2007. In addition, EPOP cannot make Capital Expenditures (as defined) exceeding $125.0 million in any fiscal year. The EPOP Senior Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The EPOP Senior Term Credit Agreement has an interest rate of LIBOR + 600 bps, with 25 bps step-ups on October 2, 2007 and January 2, 2008, and a total cap of LIBOR + 650 bps. Additionally, the EPOP Senior Term Credit Agreement matures five years from the closing date, requires payments of principle at 1% per year, with the balance of unpaid principle due at maturity. Upon an initial public offering by EXCO Partners, EPOP shall prepay the principal outstanding (plus accrued interest) under the EPOP Senior Term Credit Agreement at par plus an applicable premium. Commencing with the fiscal year ended December 31, 2007, and each year thereafter, EPOP must apply 100% of its Excess Cash Flow (as defined in the EPOP Senior Term Credit Agreement) toward prepayment at par of the EPOP Senior Term Credit Agreement. Such payments shall be made no later than the later of April 15 or five business days following delivery of the annual financial statements required under the EPOP Senior Term Credit Agreement. Any principal payment prior to the first anniversary, other than the mandatory cash flow and amortization prepayments described above, must be paid at 102% of the principal amount and after the first anniversary date to and including the second anniversary at 101% of par. Thereafter, any prepayments are at par. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP.
EXCO Resources Equity Contribution Agreement
In connection with the arrangement of the EPOP Senior Term Credit Agreement, the lenders required EXCO Resources to enter into an Equity Contribution Agreement, dated October 2, 2006, and amended and restated on October 4, 2006 and October 13, 2006. The Equity Contribution Agreement generally provides that on the date 18 months from October 2, 2006 (Equity Contribution Date), EXCO Resources will make a cash common equity contribution to EPOP in an amount equal to the lesser of (i) $150.0 million or (ii) the aggregate amount then outstanding under the EPOP Senior Term Credit Agreement; provided, that in no event can this obligation exceed during the term of the Equity Contribution Agreement the maximum amount that EXCO Resources could contribute under the terms of the Indenture governing its senior notes. Alternatively, EXCO Resources can cause EXCO Partners to make the equity contribution to EPOP in the amount of $150.0 million to satisfy this obligation. In lieu of requiring the equity contribution, the holders of at least 662¤3% of the aggregate principal amount of the
loans outstanding under the EPOP Senior Term Credit Agreement can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become “Restricted Subsidiaries” under the EXCO Resources credit agreement and require EXCO Resources to provide, and cause all then restricted subsidiaries as defined and constituted under the EXCO Resources credit agreement to provide, guarantees and collateral in respect of the EPOP Senior Term Credit Agreement on terms substantially consistent with the guarantees and collateral provided under the EXCO Resources credit agreement. This requirement is subject to compliance with the credit agreement. Any cash so contributed shall be used by EPOP to prepay loans under the EPOP Senior Term Credit Agreement. EXCO Resources is prohibited from making restricted payments (as defined in the Indenture) that would constitute a utilization of the Indenture restricted payment baskets, other than restricted payments not to exceed $5.0 million In addition, EXCO Resources has covenanted to redeem or defease its senior notes if the Indenture would not permit the equity contribution or the lenders’ election to cause EXCO Resources to designate EPOP and its subsidiaries as restricted subsidiaries under the EXCO Resources credit agreement (subject to certain restrictions on the indebtedness that may be incurred for any such redemption or defeasance if the election to cause the designation of EPOP as a restricted subsidiary is chosen). The Equity Contribution Agreement will terminate upon payment in full of the EPOP Senior Term Credit Agreement.
Proposed recapitalization
If we consummate the proposed private placement of up to $2.0 billion of preferred stock, we plan to contribute $1.75 billion of the net proceeds to EPOP, of which approximately $1.6 billion will be used to purchase the Vernon Assets and approximately $150.0 million will be used to refinance EPOP’s debt agreements. We expect the proposed refinancing of EPOP’s debt agreements to include a new revolving credit facility, or the Proposed EPOP Revolving Credit Facility, and a new term loan, or the Proposed EPOP Term Loan, each with JPMorgan Chase Bank, N.A., as administrative agent. We anticipate that the EPOP Senior Term Credit Agreement will be paid in full and terminated in connection with the proposed recapitalization. We plan to use the remaining $250.0 million of the net proceeds of the preferred stock to restructure and repay indebtedness under the EXCO Resources credit agreement and pay fees and expenses associated with the offering.
We are in discussion with our lenders concerning all of our credit agreements. There is no assurance that any of these transactions will be completed. Even if the proposed recapitalization is completed, it may involve terms and conditions other than those provided in this annual report.
Proposed private placement of preferred stock
On February 14, 2007, we issued a press release pursuant to Rule 135c of the Securities Act of 1933 to announce a proposed offering of up to $2.0 billion in preferred stock through the private placement of up to $400.0 million of 6% Cumulative Convertible Perpetual Preferred Stock, or the 6% Convertible Preferred Stock, and $1.6 billion of 11% Cumulative Preferred Stock, or the 11% Preferred Stock, to accredited institutional investors pursuant to Regulation D of the Securities Act of 1933. We have not entered into definitive agreements with potential investors to issue any preferred stock. As a result, we may never issue any preferred stock. In addition, any preferred stock that we ultimately issue may contain terms different from those provided in this annual report.
The securities proposed to be offered in the private placement will not been registered under the Securities Act of 1933 or any state securities laws, and unless so registered may not be offered or sold in the United States, except pursuant to an exemption from, or in a transaction subject to, the registration requirements of the Securities Act of 1933 and applicable state securities laws. This annual report does not constitute an offer to sell, or the solicitation of an offer to buy, the securities nor shall there be any sale of the securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction.
The 6% Convertible Preferred Stock will be convertible into our common stock at a price of $20.00 per share, as may be adjusted in accordance with the terms of the 6% Convertible Preferred Stock, and we may force the conversion of the 6% Convertible Preferred Stock at any time if our common stock trades for 20 days within a period of 30 consecutive days at a price, subject to adjustment, above $35.00 per share in the 24 months after issuance, $30.00 per share thereafter through the 48th month after issuance and $25.00 per share at any time thereafter. Upon the occurrence of a change of control, holders of the 6% Convertible Preferred Stock may require us to repurchase their shares for cash or shares of common stock at the liquidation preference plus accumulated dividends. Holders of the 6% Convertible Preferred Stock will have a right of first offer with respect to our subsequent issuance of shares of common stock at a price per share less than the then-effective conversion price, subject to customary exceptions.
The 11% Preferred Stock will automatically convert into an equal number of shares of 6% Convertible Preferred Stock upon shareholder approval as required by New York Stock Exchange rules. We expect to hold a shareholders meeting in the third quarter of 2007. If the 11% Preferred Stock has not been converted into 6% Convertible Preferred Stock within 180 days of issuance, the annual dividend rate will increase by 0.50% per quarter (up to a maximum rate of 18% per annum) until the shares of 11% Preferred Stock have been converted into 6% Convertible Preferred Stock. The 11% Preferred Stock must be redeemed for cash at 125% of the liquidation preference plus accumulated dividends following the maturity of our senior notes and is otherwise redeemable at such price at our option at any time. Upon the occurrence of a change of control, holders of the 11% Preferred Stock may require us to repurchase their shares for cash at 101% of the liquidation preference plus accumulated dividends. In the event that any person or group of persons consummates a tender offer to acquire more than 50% of our total voting power at a price per common share equivalent of greater than the then effective conversion price of the 6% Convertible Preferred Stock, then, within 30 days after expiration of the change of control offer made to the holders of the 11% Preferred Stock following such tender offer, we must issue to each holder of 11% Preferred Stock, for all such shares of 11% Preferred Stock so held, the number of additional shares of 11% Preferred Stock having a liquidation preference equal to the product of (i) such number of shares of 11% Preferred Stock so held multiplied by (ii) the remainder of the tender offer price minus the then effective conversion price of the 6% Convertible Preferred Stock multiplied by (iii) the quotient of $1,000 divided by the then effective conversion price of the 6% Convertible Preferred Stock. No shares will be issued to any holder that requires us to purchase any of its 11% Preferred Stock pursuant to a change of control offer.
The holders of 11% Preferred Stock will have a class vote to approve (i) any sale or disposition of all or substantially all of our assets to a third party or (ii) any merger or consolidation of EXCO in which either the holders of our voting stock prior to the merger or consolidation do not beneficially own more than 50% of the voting stock of the continuing or surviving corporation immediately after such merger or consolidation or individuals not nominated by our current directors (or their successors nominated by the remaining directors) constitute two-thirds of our board of directors immediately following the merger or consolidation, unless each holder of the 11% Preferred Stock receives in the asset sale or the merger or consolidation the consideration it would have received had it been able to convert its 11% Preferred Stock into 6% Convertible Preferred Stock and the 6% Convertible Preferred Stock into our common stock immediately prior to the merger or consolidation. After 180 days from the date of issuance, holders of the 11% Preferred Stock will have a right of first offer with respect to our subsequent debt or equity issuances, subject to customary exceptions.
We must pay dividends quarterly either in cash at 6% per annum or the dividend due shall be added to the liquidation preference (thereby increasing the amount due at liquidation or upon conversion) at a rate equal to 8% per annum. After the sixth anniversary of the issue date, the dividend rate on the 6% Convertible Preferred Stock will increase to 8.0% per annum and dividends will be payable only in cash. Dividends on the 11% Preferred Stock are only payable in cash.
Holders of the 6% Convertible Preferred Stock and the 11% Preferred Stock will have certain director appointment rights. We will be obligated to register for resale under the Securities Act of 1933 the shares of common stock issuable in connection with the 6% Convertible Preferred Stock.
We will use the net proceeds from the sale of the preferred stock to finance our previously announced acquisition from Anadarko of oil and natural gas properties in the Vernon and Ansley Fields in Louisiana and to repay a portion of our outstanding indebtedness and indebtedness of our subsidiary, EPOP.
Proposed EPOP Revolving Credit Facility
The Proposed EPOP Revolving Credit Facility is expected to have a face amount of $1.0 billion with an initial borrowing base of $1.3 billion. The aggregate outstanding amount of the Proposed EPOP Term Loan will be deemed usage of the borrowing base. The borrowing base will be redetermined on a semi-annual basis, with EPOP and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each year, beginning October 1, 2007. The Proposed EPOP Revolving Credit Facility will be secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EPOP. We expect the Proposed EPOP Revolving Credit Facility to contain financial covenants similar to those contained in the current EXCO Resources credit agreement, including:
· a Consolidated Current Ratio;
· a ratio of (A) Consolidated Funded Indebtedness as of the end of a fiscal quarter to (B) Consolidated EBITDAX; and
· a ratio of Consolidated EBITDAX to Consolidated Interest Expense.
The Proposed EPOP Revolving Credit Facility will contain representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The Proposed EPOP Revolving Credit Facility matures five years from the closing date and has an initial drawn interest rate of LIBOR + 150 basis points (“bps”) and an undrawn commitment fee of 37.5 bps.
The initial amount borrowed under this facility is expected to be $769.0 million at the closing of the acquisition of the Vernon Assets.
Proposed EPOP Term Loan
We expect that the Proposed EPOP Term Loan will have an aggregate principal amount of $300.0 million to be available in a single drawing on the closing date. The Proposed EPOP Term Loan will be secured by a first priority lien on all of the properties securing the Proposed EPOP Revolving Credit Facility, including 100% of the stock of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries of EPOP. We expect the financial covenants governing the Proposed EPOP Term Loan to be substantially similar to those contained in the Proposed EPOP Revolving Credit Facility. We expect the Proposed EPOP Term Loan to contain representations, warranties, covenants, events of default and indemnities customary for agreements of this type. We expect the Proposed EPOP Term Loan to have an interest rate of LIBOR + 150 bps. Additionally, the Proposed EPOP Term Loan will mature six years from the closing date, require payments of principal at 1% per year, with the balance of unpaid principal due at maturity. We anticipate that any principal payment prior to the first anniversary, other than the mandatory amortization prepayments described above, must be paid at par.
We expect to draw down the full $300.0 million at the closing of the acquisition of the Vernon Assets.
Proposed EXCO Resources credit agreement
In connection with the proposed private placement of preferred stock, we plan to refinance the existing EXCO Resources credit agreement with a new EXCO Resources credit agreement, the Proposed EXCO Resources credit agreement, having a face amount of $750.0 million and a new borrowing base of $1.0 billion. The aggregate outstanding amount of a new term loan, or the Proposed EXCO Resources Term Loan, will be deemed usage of the borrowing base. The borrowing base will be redetermined on a semi-annual basis, with EXCO Resources and the lenders having the right to interim unscheduled redeterminations in certain circumstances. Scheduled redeterminations will be made on or about April 1 and October 1 of each year, beginning October 1, 2007. Borrowings under the Proposed EXCO Resources credit agreement will be collateralized by a first lien mortgage providing a security interest in our oil and natural gas properties. We anticipate that the financial covenants under the Proposed EXCO Resources credit agreement will be similar to those contained in the current EXCO Resources credit agreement, including:
· a Consolidated Current Ratio;
· a ratio of (A) Consolidated Funded Indebtedness as of the end of a fiscal quarter to (B) Consolidated EBITDAX; and
· a ratio of Consolidated EBITDAX to Consolidated Interest Expense.
The Proposed EXCO Resources credit agreement will contain representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The Proposed EXCO Resources credit agreement matures five years from the closing date and has an initial drawn interest rate of LIBOR + 125 basis points (“bps”) and an undrawn commitment fee of 30.0 bps
Additionally, we expect the Proposed EXCO Resources credit agreement to contain a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and a prohibition on the payment of dividends on our common stock.
The initial amount borrowed under this facility is expected to be $482.0 million at the closing of the acquisition of the Southern Gas Assets.
Proposed EXCO Resources Term Loan
We expect that the Proposed EXCO Resources Term Loan will have an aggregate principal amount of $250.0 million to be available in a single drawing on the closing date. The Proposed EXCO Resources Term Loan will be secured by a first priority lien on all of the properties securing the Proposed EXCO Resources credit agreement. We expect the financial covenants governing the Proposed EXCO Resources Term Loan to be identical to those contained in the Proposed EXCO Resources credit agreement. We expect the Proposed EXCO Resources Term Loan to contain representations, warranties, covenants, events of default and indemnities customary for agreements of this type. We expect the Proposed EXCO Resources Term Loan to have an interest rate of LIBOR + 150 bps. Additionally, the Proposed EXCO Resources Term Loan will mature six years from the closing date, require payments of principal at 1% per year, with the balance of unpaid principal due at maturity. We anticipate that any principal payment prior to the first anniversary, other than the mandatory amortization prepayments described above, must be paid at par.
We expect to draw down the full $250.0 million of the Proposed EXCO Resources Term Loan at the closing of the acquisition of the Southern Gas Assets.
Derivative financial instruments
We use derivative financial instruments to manage exposure to commodity prices and interest rate risks. Our objectives for holding derivatives are to minimize risks using the most effective methods to eliminate or reduce the impacts of these exposures.
Our production is generally sold at prevailing market prices. However, we periodically enter into derivative financial instrument contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.
Our objective in entering into derivative financial instrument contracts is to manage price fluctuations and achieve a more predictable cash flow associated with our acquisition activities and borrowings under our credit agreements. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if prices increase. During the year ended December 31, 2005, we closed several of our derivative financial instrument contracts upon the payment of $67.6 million to our counterparties, of which $15.0 million was related to the sale of Addison and $52.6 million was related to our U.S. production. We also entered into new derivative financial instrument contracts at higher prices. As of December 31, 2006, we had contracts in place for the volumes and prices shown in the table below, which includes contracts we entered into or assumed in connection with the acquisition of Winchester.
EXCO Resources, Inc. hedge positions as of December 31, 2006
Pro forma including the acquisitions of the Vernon Assets and the Southern Gas Assets from Anadarko as of December 31, 2006
Off-balance sheet arrangements
None.
Contractual obligations and commercial commitments
The following table presents a summary of our contractual obligations at December 31, 2006:
(1) Our senior notes are due on January 15, 2011. The annual interest obligation is $32.2 million.
(2) The EXCO Resources credit agreement was amended and restated on March 17, 2006 and matures on December 31, 2010.
(3) The EPOP Revolving Credit Facility matures on October 2, 2010.
(4) The EPOP Senior Term Credit Agreement matures on October 2, 2011.
(5) Deferred compensation represents a Rabbi Trust for an officer of one of our subsidiaries. This obligation vests 20% each year and will fully vest on December 31, 2011.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates charged on borrowings and earned on cash equivalent investments, and adverse changes in the market value of marketable securities. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.
Commodity price risk
Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile.
The following table sets forth our use of derivative financial instruments activities as of December 31, 2006:
At December 31, 2006, the average forward spot oil prices per Bbl for calendar 2007 and for 2008 were $65.02 and $67.50, respectively, and the average forward spot natural gas prices per Mmbtu for calendar 2007 and for 2008 were $6.97 and $8.06, respectively.
Realized gains or losses from the settlement of derivative financial instruments are recorded in our financial statements as increases or decreases in use of derivative financial instruments activities. For
example, using the oil swaps in place at December 31, 2006, if the settlement price exceeded the actual weighted average strike price of $69.52, then a reduction in use of derivative financial instruments activities revenue would have been recorded for the difference between the settlement price and $69.52 multiplied by the hedged volume of 733,750 Bbls. Conversely, if the settlement price was less than $69.52, then an increase in use of derivative financial instruments activities revenue would have been recorded for the difference between the settlement price and $69.52 multiplied by the hedged volume of 733,750 Bbls. For example, for a hedged volume of 733,750 Bbls, if the settlement price was $70.52, then use of derivative financial instruments activities revenue would have decreased by $0.7 million. Conversely, if the settlement price was $68.52, use of derivative financial instruments activities revenue would have increased by $0.7 million.
Interest rate risk
At December 31, 2006, our exposure to interest rate changes related primarily to borrowings under our credit agreements and interest earned on our short-term investments. The interest rate is fixed at 7 1¤4% on the $444.7 million in senior notes we have outstanding. As of December 31, 2006, we were not using any derivatives to manage interest rate risk. Interest is payable on borrowings under our credit agreements based on a floating rate as more fully described in “Management’s discussion and analysis of financial condition and results of operations-Our liquidity, capital resources and capital commitments.” At December 31, 2006, we had $1.6 billion in outstanding borrowings under our credit agreements. On February 14, 2006, we increased our borrowings under the EXCO Resources credit agreement to $65.0 million and subsequently repaid $44.5 million of that increase on February 21, 2006. On March 17, 2006, we borrowed $123.0 million under the EXCO Resources credit agreement and used these borrowings to repay in full the TXOK credit facility. This increased the outstanding balance under the EXCO Resources credit agreement to $143.5 million. As of March 1, 2007, the outstanding balance under our credit agreement was $407.0 million. The interest rate under the EXCO Resources credit agreement as of that date was 6.67%. A 1% change in interest rates based on the borrowings as of March 1, 2007 would result in an increase or decrease in our interest costs of $4.1 million per year. The interest we pay on these borrowings is set periodically based upon market rates.
The EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement, both of which we entered into in connection with the Winchester acquisition on October 2, 2006, bear interest based on floating rates. As of December 31, 2006, we had $643.5 million and $650.0 million in outstanding borrowings under the EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement, respectively. As of March 1, 2007, our outstanding balance under the EPOP Revolving Credit Facility was $643.5 million and under the EPOP Senior Term Credit Agreement was $650.0 million. As of that date, the interest rate under the EPOP Revolving Credit Facility averaged 7.19% and under the EPOP Senior Term Credit Agreement averaged 11.44%. A 1% change in interest rates based on the borrowings as of March 1, 2007 under the EPOP Revolving Credit Facility and the EPOP Senior Term Credit Agreement would result in an increase or decrease in interest costs of $6.4 million and $6.5 million per year, respectively.
The interest we pay on these borrowings is set periodically based upon market rates.
Marketable securities risk
On January 5, 2007, we deposited $129.6 million of proceeds, net of contractual adjustments, with a qualified intermediary to effect a like-kind exchange under Section 1031 of the Internal Revenue Code from the sale of our Wattenberg properties. These proceeds are invested in overnight money market funds.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXCO RESOURCES, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Contents
Reports of Independent Registered Public Accounting Firms
Consolidated balance sheets at December 31, 2005 and 2006
Consolidated statements of operations for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006
Consolidated statements of cash flows for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006
Consolidated statements of changes in shareholders’ equity for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006
Consolidated statements of comprehensive income (loss) for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005, and the year ended December 31, 2006
Notes to consolidated financial statements
Financial information for the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, represents predecessor (Predecessor) basis financial statements for the period prior to our Equity Buyout transaction. Beginning October 3, 2005, the effective date of the Equity Buyout, the accompanying consolidated financial statements reflect a stepped up (Successor) basis of accounting to reflect the purchase of EXCO Resources by Holdings II. See “Note 1. Organization” to the consolidated financial statements.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
EXCO Resources, Inc.:
We have audited the accompanying consolidated balance sheet of EXCO Resources, Inc. and subsidiaries (the Company) as of December 31, 2006, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for the year ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EXCO Resources, Inc. and subsidiaries as of December 31, 2006, and the results of their operations and their cash flows for the year ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
KPMG LLP
Dallas, Texas
March 16, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of EXCO Resources, Inc.:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of shareholders’ equity and of cash flows present fairly, in all material respects, the financial position of EXCO Resources, Inc. and its subsidiaries (Successor Company) at December 31, 2005, and the results of their operations and their cash flows for period from October 3, 2005 to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, all financial information presented reflects the consolidated financial position and results of operations of EXCO Resources, Inc. and its former parent, EXCO Holdings Inc. in order to account for transactions between entities under common control as required by Statement of Financial Accounting Standards No. 141, “Business Combinations”.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
May 15, 2006, except for Note 21,
as to which the date is March 15, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of EXCO Resources, Inc.:
In our opinion, the accompanying consolidated statements of operations, of shareholders’ equity and of cash flows present fairly, in all material respects, the results of operations and cash flows of EXCO Resources, Inc. and its subsidiaries (Predecessor Company) for the period from January 1, 2005 to October 2, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, all financial information presented reflects the consolidated financial position and results of operations of EXCO Resources, Inc. and its former parent, EXCO Holdings Inc. in order to account for transactions between entities under common control as required by Statement of Financial Accounting Standards No. 141, “Business Combinations”.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
May 15, 2006, except for Note 21,
as to which the date is March 15, 2007
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of EXCO Resources, Inc.:
In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of shareholders’ equity and of cash flows present fairly, in all material respects, the results of operations and cash flows of EXCO Resources, Inc. and its subsidiaries (Predecessor Company) for the year ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 31, 2006, except for Note 21,
as to which the date is March 15, 2007
EXCO Resources, Inc.
Consolidated balance sheets
See accompanying notes.
EXCO Resources, Inc.
Consolidated balance sheets
See accompanying notes.
EXCO Resources, Inc.
Consolidated statements of operations
EXCO Resources, Inc.
Consolidated statements of cash flows
See accompanying notes.
EXCO Resources, Inc.
Consolidated statements of changes in shareholders’ equity
See accompanying notes.
EXCO Resources, Inc.
Consolidated statements of comprehensive income (loss)
See accompanying notes.
EXCO Resources, Inc.
Notes to consolidated financial statements
1. Organization
Unless the context requires otherwise, references in this annual report to “EXCO,” “EXCO Resources,” “we,” “us,” “our” and the “Company” are to EXCO Resources, Inc., its consolidated subsidiaries and EXCO Holding Inc., or EXCO Holdings, our former parent company, which was acquired by and into which EXCO Holdings II, Inc., or Holdings II, merged on October 3, 2005. References in this annual report to “Resources” refers only to the registrant, EXCO Resources, Inc. On February 14, 2006, EXCO Holdings merged with and into Resources. As such, all periods presented reflect the merger and include EXCO Holdings.
EXCO Resources, Inc., a Texas corporation, was formed in October 1955. 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 and, until February 10, 2005, in Canada. We expect to continue to grow by leveraging our management team’s experience, exploiting our multi-year inventory of development drilling locations and exploitation projects, and selectively pursuing acquisitions that meet our strategic and financial objectives. We employ the use of debt along with a comprehensive derivative financial instrument program to support our acquisition strategy. This approach enhances our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. On February 14, 2006, we acquired TXOK Acquisition, Inc., or TXOK, for approximately $665.1 million and on October 2, 2006, we completed the acquisition of Winchester Energy Company, Ltd., or Winchester, for approximately $1.1 billion in cash after closing adjustments. The Winchester acquisition was completed within our newly-formed subsidiary, EXCO Partners, LP, or EXCO Partners. Concurrent with the closing of this acquisition we contributed to EXCO Partners all of our East Texas assets, including four of our subsidiaries that own or operate certain of our East Texas assets in exchange for $150.0 million of cash and additional equity interests in EXCO Partners. EXCO Partners borrowed $1.3 billion to fund these transactions. Our 2006 acquisitions, including TXOK and Winchester, totaled in excess of $2.1 billion. In addition, we spent $214.3 million for development drilling, acreage and related oil and natural gas facilities during 2006. For a discussion of these acquisitions as well as other transactions that we completed during 2005 and 2006, see “Item 1. Business-Significant transactions during 2005” and “Item 1. Business-Significant transactions during 2006.”
Due to the merger of our parent, EXCO Holdings (formerly EXCO Holdings II), into Resources on February 14, 2006 concurrent with the closing of our initial public offering, or IPO (See “Note 4. Significant recent transactions”), all financial information in this annual report contains the consolidated financial position and results of EXCO Resources and EXCO Holdings pursuant to presentation requirements contained in Statement of Financial Accounting Standards No. 141, “Business Combinations”, or SFAS No. 141, for transactions between entities under common control. For comparative purposes pursuant to SFAS No. 141, the prior period financial statements of EXCO Resources present the consolidated operations of EXCO Resources and EXCO Holdings for all periods. As described below, our financial statements contain two separate and distinct bases of accounting.
Predecessor-For the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, financial information presented in our consolidated statements of operations, statements of cash flows and consolidated statements of shareholders’ equity reflect the consolidated information of EXCO Resources and EXCO Holdings, our parent company until October 2, 2005.
Successor-For the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, financial information presented in our consolidated financial statements of operations, statements of cash flows and consolidated statements of shareholders’ equity reflect the consolidated information of EXCO Resources and Holdings II, which became our parent company on October 3, 2005
effective with the consummation of the Equity Buyout and the acquisition by and merger of Holdings II into EXCO Holdings (See “Note 4. Significant recent transactions”). The Equity Buyout (See “Note 4. Significant recent transactions-Equity Buyout”) was accounted for as a purchase pursuant to SFAS No. 141 and resulted in a new basis of accounting. The consolidated balance sheets as of December 31, 2005 and 2006 reflect this new basis of accounting.
In addition, as a result of the redemption of TXOK preferred stock (See “Note 4. Significant recent transactions-TXOK acquisition”) on February 14, 2006, our investment in TXOK, which was accounted for using the equity method of accounting until our redemption of the preferred stock, became a wholly-owned subsidiary.
The consolidated balance sheet as of December 31, 2005 reflects the consolidated financial position of EXCO and Holdings II (as successor for accounting purposes after its merger with EXCO Holdings) prior to the IPO of our common stock on February 9, 2006, which is more fully described below. The consolidated balance sheet as of December 31, 2006 reflects our consolidated financial position after the IPO and the merger of EXCO Holdings into EXCO Resources.
On February 8, 2006, our registration statement on Form S-1, as amended, was declared effective by the Securities and Exchange Commission, or SEC, pursuant to which we offered 50,000,000 shares of our common stock, par value $.001 per share, at an initial offering price of $13.00 per share, or a net price after underwriting discount of $12.35 per share. Net proceeds from the offering after underwriting discount, but before other expenses, were approximately $617.5 million. Concurrent with the February 14, 2006 closing of the IPO, EXCO Holdings, our parent company, was merged into and with EXCO Resources and EXCO Resources became the surviving company. Shares of stock and stock options of EXCO Holdings were automatically converted into an equal number of like securities of EXCO Resources. Subsequently, the underwriters of our IPO exercised their over-allotment option to purchase an additional 3,615,200 shares of our common stock at $12.35 per share which yielded additional net proceeds of approximately $44.6 million.
The accompanying consolidated balance sheets as of December 31, 2005 and 2006, results of operations, cashflows and changes in shareholders’ equity for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 are for EXCO, its subsidiaries, and prior to the IPO, its parent. All intercompany transactions have been eliminated. Our results of operations reflect the results of our former Canadian subsidiary, Addison Energy Inc., or Addison, as discontinued operations. Certain prior year amounts have been reclassified to conform to the current year presentation.
The Equity Buyout
On August 29, 2005, EXCO announced that the Board of Directors of Holdings approved for consideration by the Holdings stockholders the proposed terms of an equity buyout (Equity Buyout) pursuant to a purchase of all of the outstanding shares of capital stock of Holdings by EXCO Holdings II, Inc. (Holdings II), a Delaware corporation controlled by a group of investors led by Douglas H. Miller, the Chairman and Chief Executive Officer of Holdings.
On October 3, 2005, Holdings II completed its purchase of all of the outstanding shares of capital stock of Holdings for an aggregate purchase price of approximately $699.3 million. The Equity Buyout was funded by a combination of (i) $350.0 million of interim loan indebtedness (interim bank loan), including $0.7 million for working capital, (ii) approximately $183.1 million from the issuance of Holdings II common stock to new private equity investors and EXCO employees and (iii) the exchange of Holdings Class A and Class B common stock valued at approximately $166.9 million for Holdings II common stock. Holdings’ majority stockholder sold all of its shares for cash. JPMorgan Chase Bank, N.A. was the lead lender under the interim bank loan.
GAAP requires the application of “pushdown accounting” in situations where the ownership of an entity has changed. Holdings II was deemed to be the acquiror of Holdings. The assets and liabilities of Holdings II were recorded at their fair value, and, under Staff Accounting Bulletin (SAB) No. 54, “Pushdown Basis of Accounting in Financial Statements of Subsidiaries Acquired by Purchase”, the fair value was allocated as follows:
(1) Marginal tax rate includes federal income taxes at 35.0% plus a blended state tax rate of 4.5%.
As a result of the Equity Buyout, we recorded stock based and other compensation expense for the following items during the 275 day period from January 1, 2005 to October 2, 2005:
· A non-cash charge of approximately $44.1 million as a result of the acquisition by Holdings II of all of the shares of Class B common stock of Holdings held by members of our management and other employees. The offset to this expense was to Shareholders’ Equity as additional paid-in capital. The shareholder agreements governing the Class A and Class B shares of Holdings provided that, upon the occurrence of certain specified events, including a change of control as occurred upon the Equity Buyout:
· the holders of the Class A shares were to receive the first $175.0 million in proceeds, and
· the remaining proceeds in excess of the $175.0 million were to be allocated on a pro-rata basis to the holders of the Class A and Class B shares. For financial accounting purposes, the Class B shares were considered to be a “variable” plan since a holder of the shares had to be employed
at the date of a participation event, such as a change of control, to receive fair value for the Class B shares.
· A charge of $17.8 million for payments made to holders of options to purchase Class A shares of Holdings less options held by the Employee Stock Participation Plan (ESPP). This amount was paid to option holders at the time of the Equity Buyout by Holdings to purchase all stock options outstanding at that time. The amount represents the cumulative difference between the $5.197 per share purchase price for the Equity Buyout for the Class A shares and the exercise price of the outstanding stock options times the number of stock options outstanding.
· A charge of $8.3 million for payments made to our employees who were participants in the ESPP. This amount was paid at the time of the Equity Buyout and was based upon shares of Holdings Class A and Class B stock that were reserved, but unissued, and options granted to the ESPP under the Holdings’ 2004 Long-Term Incentive Plan (the Holdings Plan). All employees on the date of the Equity Buyout who were not direct owners of Holdings Class A or Class B stock received payments under the ESPP. For financial accounting purposes, the ESPP was considered to be a “variable” plan since, to be eligible, a recipient had to be employed at the date of the change of control to receive a payment. As a result, we did not recognize compensation expense prior to the consummation of the change of control event.
· A charge of $2.6 million for accelerated payments made by Holdings to certain employees of EXCO under the Holdings Bonus Retention Plan. The Holdings Bonus Retention Plan was accelerated, paid in full and terminated upon consummation of the Equity Buyout.
Holdings II adopted the 2005 Long-Term Incentive Plan (the 2005 Incentive Plan) which provides for the granting of options to purchase up to 10,000,000 shares of Holdings (formerly Holdings II) common stock. On October 5, 2005, options were granted under the 2005 Incentive Plan to our employees to purchase 4,992,650 shares of Holdings common stock at $7.50 per share. During 2006, a total of 3,615,700 options to purchase shares of our common stock were granted at a weighted average price of $14.02. As of December 31, 2006, a total of 8,267,373 options were issued and outstanding. The options expire ten years from the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As a result of the new basis in accounting due to the Equity Buyout, we adopted the provisions of SFAS No. 123(R), “Share-Based Payment” as of October 3, 2005. During 2006, we recorded non-cash compensation of $6.5 million as general and administrative expenses and capitalized $1.4 million as oil and natural gas properties.
Merger of Holdings II into Holdings
Promptly following the consummation of the Equity Buyout, Holdings II merged with and into Holdings (Holdings II Merger). As a result of the Holdings II Merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of Holdings common stock. In addition, all shares of Holdings Class A and Class B common stock held by Holdings II were cancelled in connection with the Holdings II Merger. The Equity Buyout was accounted for as a purchase pursuant to SFAS No. 141, which resulted in the assets and liabilities being recorded at their fair value. Holdings II is deemed the accounting acquiror of Holdings.
Pursuant to the Holdings II Merger, the indebtedness incurred by Holdings II to fund the Equity Buyout was assumed by Holdings.
2. Summary of significant accounting policies
Principles of consolidation
The accompanying consolidated balance sheets as of December 31, 2005 and December 31, 2006 and the results of operations, cash flows and comprehensive income for the 90 day period from October 3, 2005 to December 31, 2005 and the twelve months ended December 31, 2006 are for EXCO and its subsidiaries and represents the stepped up Successor basis of accounting following the Equity Buyout transaction.
The accompanying results of operations, cash flows and comprehensive income for the year ended December 31, 2004 and for the 275 day period from January 1, 2005 to October 2, 2005 are for EXCO and its subsidiaries and represent the stepped up Predecessor basis of accounting.
The financial statements prior to January 1, 2005 have been restated to reflect the financial position, operations, cash flow and comprehensive income of Addison as discontinued operations.
All intercompany transactions and accounts have been eliminated.
Functional currency
The assets, liabilities and operations of Addison were measured using the Canadian dollar as the functional currency. These assets and liabilities were translated into U.S. dollars using end-of-period exchange rates. Revenue and expenses were translated into U.S. dollars at the average exchange rates in effect during the period. Translation adjustments were deferred and accumulated in other comprehensive income.
Management estimates
In preparing financial statements in conformity with accounting principles generally accepted in the United States, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserve volumes, future development, dismantlement and abandonment costs, share-based compensation expenses, estimates relating to certain oil and natural gas revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management’s estimates.
Cash equivalents
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
Concentration of credit risk and accounts receivable
Financial instruments that potentially subject us to a concentration of credit risk consist principally of cash, trade receivables and our derivative financial instruments. We place our cash with high credit quality financial institutions. We sell oil and natural gas to various customers. In addition, we participate with other parties in the drilling, completion and operation of oil and natural gas wells. The majority of our accounts receivable are due from either purchasers of oil or natural gas or participants in oil and natural gas wells for which we serve as the operator. We have the right to offset future revenues against unpaid charges related to operated wells. Oil and natural gas sales are generally uncollateralized. The allowance for doubtful accounts receivable (including current assets of discontinued operations) aggregated $1.6 million and $1.9 million at December 31, 2005 and 2006, respectively. We place our derivative financial instruments with financial institutions and other firms that we believe have high credit ratings.
For a discussion of the credit risks associated with our commodity price risk management activities, see “Note 7. Derivative financial instruments.”
Derivative financial instruments
In connection with the incurrence of debt related to our acquisition activities, our management has adopted a policy of entering into oil and natural gas derivative financial instruments to protect against commodity price fluctuations and to achieve a more predictable cash flow. SFAS No. 133 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. SFAS No. 133 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 allowed by SFAS No. 133 exist. We have not designated our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative’s fair value currently in earnings.
Oil and natural gas properties
We have recorded oil and natural gas properties at cost using the full cost method of accounting. Under the full cost method, all costs associated with the acquisition, exploration or development of oil and natural gas properties are capitalized as part of the full cost pool. Capitalized costs are limited to the aggregate of the after-tax present value of future net revenues plus the lower of cost or fair market value of unproved properties. The full cost pool is comprised of lease and well equipment and exploration and development costs incurred, plus costs of acquired proved leaseholds.
Unproved oil and natural gas properties are excluded from the calculation of depreciation, depletion and amortization until it is determined whether or not Proved Reserves can be assigned to such properties. At December 31, 2005 and 2006, the $53.1 million and $297.9 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the estimated fair value of undeveloped acreage and unproved reserves. We assess our unproved oil and natural gas properties for impairment on a quarterly basis.
Depreciation, depletion and amortization of evaluated oil and natural gas properties is calculated separately for the United States and until February 10, 2005, the Canadian full cost pools using the unit-of-production method based on total Proved Reserves, as determined by independent petroleum reservoir engineers.
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.
Full cost ceiling test
At the end of each quarterly period, the unamortized cost of proved oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices discounted at 10%, adjusted for related income tax effects (ceiling test). This ceiling test calculation is done separately for the United States and, until February 10, 2005, the Canadian full cost pools.
As of December 31, 2006, pursuant to Rule 4-10(c)(4)(i)(A) of Regulation S-X, the Company was required to compute its ceiling test using the December 31, 2006 spot prices for oil and natural gas. The computation resulted in the carrying costs of our unamortized proved oil and natural gas properties, net of deferred taxes, exceeding the December 31, 2006 present value of future net revenues by approximately $393.7 million, of which approximately $189.1 million is attributable to our Winchester and TXOK
acquisitions. The December 31, 2006 spot price per equivalent Mcf was less than the Company’s realized prices for 2006 by approximately 27% and approximately 38% including realized derivative settlements. Even though the December 31, 2006 prices for oil and natural gas indicated impairment, the spot price for natural gas and oil increased to $7.05 per Mmbtu and $60.03 per Bbl., respectively, on March 12, 2007, a level sufficient to eliminate the need for a ceiling test write-down.
In advance of the 2007 price recovery that eliminated the need for a ceiling test write-down, the Company requested, and received, an exemption from the SEC to exclude all of its 2006 Acquisitions, or the 2006 Acquisitions, from the full cost pool ceiling test assessments for a period of twelve months following December 31, 2006 (i.e. through the filing of our September 30, 2007 Form 10-Q). Accordingly, we will initially test the 2006 Acquisitions for impairment in conjunction with the preparation of our financial statements for the year ended December 31, 2007, provided that we can demonstrate that the fair value of the 2006 Acquisitions exceeds the carrying costs in the interim periods through September 30, 2007.
The allocated value of proved properties for the 2006 Acquisitions totaled approximately $1.6 billion, which represented an increase of over 250% to the full cost pool from December 31, 2005. The request for exemption was made because the Company believes the fair value of the 2006 Acquisitions’ proved oil and gas properties, in certain cases, can be demonstrated beyond a reasonable doubt to exceed their unamortized costs. The Company’s expectation of future prices is principally based on NYMEX futures contracts, adjusted for basis differentials, for a period of five years. After a five year period we have historically elected to use flat pricing as the NYMEX futures contracts become more thinly traded. Generally, the flat price used for the sixth year through the economic life of the property is management’s internal long-term price estimate, which is, in large part, based on an extension of the NYMEX pricing. EXCO believes the NYMEX futures contract reflects an independent proxy for fair value.
We recognize that, due to the volatility associated with oil and natural gas prices, a downward trend in market prices could occur. If such a trend were to occur and is deemed to be other than a temporary trend, we would assess the 2006 Acquisitions for impairment during the 2007 exemption period.
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 and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Gas gathering assets
Gas gathering assets are capitalized at cost and depreciated on a straight line basis over their estimated useful lives of 25 to 40 years.
Office and field equipment
Office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Office and field equipment useful lives range from 3 to 15 years.
Goodwill
In accordance with SFAS No. 142, “Goodwill and Intangible Assets”, goodwill is not amortized, but is tested for impairment on an annual basis, or more frequently as impairment indicators arise. Impairment tests, which involve the use of estimates related to the fair market value of the business operations with
which goodwill is associated, are performed at the end of our fourth quarter. Losses, if any, resulting from impairment tests will be reflected in operating income in the statement of operations. In a February 2005 letter to oil and natural gas companies, the SEC provided guidance concerning the treatment of goodwill in situations when a company sells less than 25% of its proved oil and natural gas reserves in a cost pool. The guidance indicated that such dispositions may trigger a need to evaluate goodwill for impairment under SFAS No. 142. As a result of this guidance, beginning January 1, 2005, we no longer reduce the balance of goodwill for property dispositions of less than 25% of our oil and natural gas reserves unless there is an indication that our goodwill is impaired as a result of the sale.
The following table reflects our balances for goodwill as of December 31, 2005 and 2006 (in thousands):
(1) Goodwill from the going private transaction was written off as a result of the Equity Buyout.
Deferred abandonment and asset retirement obligations
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. The statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our proved producing properties at the end of their productive lives, in accordance with applicable state laws. EXCO adopted the new rules on asset retirement obligations on January 1, 2003.
The following is a reconciliation of our asset retirement obligations for the periods indicated (in thousands):
We have no assets that are legally restricted for purposes of settling asset retirement obligations, however we maintain a letter of credit of $1.5 million for plugging costs. This letter of credit expires on September 28, 2007.
Revenue recognition and gas imbalances
We use the sales method of accounting for oil and natural gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. Gas imbalances at December 31, 2005 and 2006 were not significant.
Capitalization of internal costs
We capitalize as part of our proved developed oil and natural gas properties a portion of salaries and, beginning in October 2005, related share-based compensation for employees who are directly involved in the acquisition and exploitation of oil and natural gas properties. During the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, we have capitalized $1.6 million, $1.2 million, $1.5 million and $3.3 million, respectively. Included in the $1.5 million and $3.3 million are $1.0 million and $1.4 million of share based compensation for the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively, resulting from the adoption of SFAS No. 123(R) on October 3, 2005. See “Note 14. Stock transactions” for further discussion.
Overhead reimbursement fees
We have classified fees from overhead charges billed to working interest owners, including ourselves, of $2.1 million, $1.3 million, $0.5 million and $7.8 million, for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. Our share of these charges was
$1.5 million, $0.8 million, $0.3 million and $5.5 million for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively, and are classified as oil and natural gas production costs.
Environmental costs
Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income taxes
Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Earnings per share
We account for earnings per share in accordance with Statement of Financial Accounting Standards No. 128, “Earnings Per Share”, or SFAS No. 128. SFAS No. 128 requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings per common share are based on the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed in the same manner as basic earnings per share after assuming issuance of common stock for all potentially dilutive equivalent shares, whether exercisable or not.
Stock options
On December 16, 2004, FASB issued SFAS No. 123(R), which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB 25 and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in our consolidated statements of operations based on their estimated fair values. Pro forma disclosure is no longer an alternative.
Holdings (formerly Holdings II) adopted the 2005 Long-Term Incentive Plan (the 2005 Incentive Plan) which provides for the granting of options to purchase up to 10,000,000 shares of Holdings common stock. New shares will be issued for any stock options exercised. As a result of the new basis in accounting due to the Equity Buyout, we adopted the provisions of SFAS No. 123(R) as of October 3, 2005 in connection with the Equity Buyout. See “Note 14. Stock transactions” for additional information related to the 2005 Incentive Plan. The adoption of SFAS No. 123(R) did not have a cumulative affect on our financial statements as no options were outstanding prior to October 5, 2005.
SFAS No. 123, “Accounting for Stock-Based Compensation” defines a fair value based method of accounting for employee stock compensation plans, but allows for the continuation of the intrinsic value based method of accounting to measure compensation cost prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25). For companies electing not to change their accounting, SFAS 123 requires pro forma disclosures of earnings and earnings per share as if the change in accounting provision of SFAS 123 has been adopted.
EXCO elected to continue to utilize the accounting method prescribed by APB 25 until October 3, 2005, under which no compensation cost was recognized, and adopted the disclosure requirements of SFAS 123.
Certain employees were granted Holdings stock options under Holdings’ 2004 Long-Term Incentive Plan (the Holdings Plan). The Holdings Plan provides for grants of stock options that could have been exercised for Class A common shares of Holdings. The stock options were to vest upon the earlier of a change in control of Holdings, the consummation of an initial public offering or three years from the date of grant, and expire ten years after the date of grant. Holdings had reserved 12,962,968 shares of its Class A common stock for issuance upon the exercise of stock options. The Equity Buyout was a change of control under the Holdings Plan. All Holdings stock options outstanding on October 3, 2005 (8,671,906 shares) were cancelled upon the payment of an aggregate amount of $17.8 million to the holders of the stock options. This amount was expensed as general and administrative expense during the 275 day period from January 1, 2005 to October 2, 2005.
Foreign currency translation
Addison, our former Canadian subsidiary, entered into a long-term note agreement with a U.S. subsidiary of EXCO in the amount of $98.8 million. Addison used the proceeds of this borrowing to repay virtually all of its outstanding indebtedness under its Canadian credit agreement in April 2004. The indebtedness was denominated in U.S. dollars and was repaid upon the sale of Addison on February 10, 2005. Under the provisions of SFAS No. 52 “Foreign Currency Translation”, Addison was required to recognize any foreign transaction gains or losses in its statement of operations when translating this liability from U.S. dollars to Canadian dollars. Gain or loss recognized by Addison was not eliminated when preparing EXCO’s consolidated statement of operations. As a result, we recorded a non-cash foreign currency transaction gain of $10.8 million during the year ended December 31, 2004 and a non-cash foreign currency loss of $3.5 million for the 275 day period from January 1, 2005 to October 2, 2005. These amounts are included in income (loss) from operations of discontinued operations in the accompanying consolidated statements of operations.
3. Recent accounting pronouncements
In July 2006, the Financial Accounting Standards Board, or FASB, issued Financial Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes”. FIN 48 provides guidance on recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that a company has taken or expects to take on a tax return. FIN 48 is effective as of January 1, 2007. We do not believe the adoption of FIN 48 will have a material impact on our consolidated financial position or results of operations.
In September 2006, the Securities and Exchange Commission Staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” or SAB 108, in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB 108, the two methods used for quantifying the effects of financial statement errors were the “roll-over” and “iron curtain” methods. Under the “roll-over” method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The criticism of this method is that misstatements can accumulate on the balance sheet. On the other hand, the “iron curtain” method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB 108 establishes a “dual approach” which requires the quantification of the effect of financial statement errors on each financial statement, as well as related
disclosures. Public companies are required to record the cumulative effect of initially adopting the “dual approach” method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. We adopted SAB 108 in the fourth quarter of 2006. The adoption did not have a material impact on our financial position, results of operations and cash flows.
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements,” or SFAS No. 157 which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We will be required to adopt SFAS No. 157 in the first quarter of fiscal year 2008. We are currently evaluating the impact of SFAS No. 157 on our financial statements.
4. Recent significant transactions
TXOK acquisition
On September 16, 2005, Holdings II formed TXOK for the purpose of acquiring ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C., or collectively, ONEOK Energy. Prior to TXOK’s acquisition of ONEOK Energy, BP EXCO Holdings LP, an entity controlled by Mr. Boone Pickens, one of our directors, held all of the outstanding shares of TXOK preferred stock and EXCO Holdings owned all of the issued and outstanding common stock of TXOK. On September 27, 2005, TXOK completed the acquisition of ONEOK Energy for an aggregate purchase price of approximately $633.0 million after contractual adjustments. Effective upon closing, ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C. became wholly-owned subsidiaries of TXOK. EXCO Holdings purchased an additional $20.0 million of Class B common stock of TXOK on October 7, 2005, which investment represented an 11% equity interest and a 10% voting interest in TXOK. The preferred stock of TXOK held by BP EXCO Holdings LP represented the remaining 89% equity interest and 90% voting interest of TXOK.
TXOK funded the acquisition of ONEOK Energy with (i) $20.0 million in private debt financing, $15.0 million of which was provided by Mr. Pickens, which was subsequently repaid; (ii) the issuance of $150.0 million of 15% Series A Convertible Preferred Stock of TXOK, or the TXOK preferred stock, to BP EXCO Holdings LP; (iii) approximately $308.8 million of borrowings under the revolving credit facility of TXOK, or the TXOK credit facility; and (iv) $200.0 million of borrowings under the second lien term loan facility of TXOK, or the TXOK term loan.
Prior to TXOK’s redemption of the preferred stock concurrently with the IPO, we held an 11% economic interest in TXOK and used the equity method of accounting for that investment until the merger.
Equity Buyout
On October 3, 2005, Holdings II, an entity formed by our management, purchased 100% of the outstanding equity securities of EXCO Holdings in an equity buyout, or Equity Buyout, for an aggregate price of approximately $699.3 million, resulting in a change of control and a new basis of accounting. To fund the Equity Buyout, Holdings II raised $350.0 million in interim debt financing, including $0.7 million for working capital, from a group of lenders and $183.1 million of equity financing from new institutional and other investors as well as stockholders of EXCO Holdings. In addition, current management and other stockholders of EXCO Holdings exchanged $166.9 million of their EXCO Holdings common stock for Holdings II common stock. EXCO Holdings’ majority stockholder sold all of its EXCO Holdings common
stock for cash. Promptly following the completion of the Equity Buyout, Holdings II merged with and into EXCO Holdings. As a result of the merger, each outstanding share of Holdings II common stock was cancelled and exchanged for one share of EXCO Holdings common stock and all shares of EXCO Holdings common stock held by Holdings II were cancelled.
Initial public offering
On February 14, 2006, we closed our IPO and subsequently issued 53.6 million shares of our common stock, including shares subsequently issued pursuant to an exercise by the underwriters of their over-allotment option, for net proceeds of $662.1 million. Concurrent with the consummation of the IPO, we advanced $158.8 million to TXOK to redeem the TXOK preferred stock and issued an additional 388,889 shares of our common stock as a redemption premium (see-Redemption of preferred stock and consolidation of TXOK). The redemption of this preferred stock caused TXOK to become our wholly-owned subsidiary. In addition to the redemption of the preferred stock of TXOK, we used proceeds from the IPO, together with cash on hand to repay the interim bank loan, repay the TXOK term loan, repay a portion of TXOK’s revolving credit facility and pay fees and expenses incurred in connection with the IPO. Concurrently with the closing of the IPO, EXCO Holdings merged with and into Resources and the shares of stock and stock options of EXCO Holdings were automatically converted into an equal number of like securities of EXCO Resources. As a result, Resources became the surviving company.
Redemption of preferred stock and consolidation of TXOK
On February 14, 2006, we redeemed all of the outstanding TXOK preferred stock, which represented 90% of the voting rights and an 89% economic interest in TXOK. The redemption price for the TXOK preferred stock was cash in the amount of $150.0 million plus $8.8 million of unpaid dividends at a rate of 15% and 388,889 shares of our common stock. The EXCO common stock issued in connection with the preferred redemption represented the value necessary to produce an overall 23% annualized rate of return on the stated value of the TXOK preferred stock as of the date of redemption pursuant to the terms of the preferred stock agreement. For purposes of calculating the rate of return, the common stock of EXCO was valued at $12.00 as required by the terms of the preferred stock. Once the TXOK preferred stock was redeemed, our acquisition of TXOK, or the TXOK acquisition, was complete and it became our wholly-owned subsidiary. We accounted for the acquisition of TXOK as a step acquisition using the purchase method of accounting and began consolidating its operations effective February 14, 2006. As a result, 89% of the fair value of the assets and liabilities of TXOK was recorded at the redemption date and the remaining 11% was recorded as an adjustment to book value as of the date of the initial investment. The total purchase price of TXOK was $665.1 million representing the redemption of the TXOK preferred stock, the initial investment in TXOK common stock and the assumption of liabilities as detailed below. The allocation of the purchase price to the assets and liabilities acquired, which reflect certain second quarter adjustments to the original fair values assigned to certain current assets, current liabilities and deferred income taxes, are also presented (in thousands).
Acquisition of Power Gas Marketing & Transmission, Inc.
On April 28, 2006, our wholly-owned subsidiary, North Coast Energy, Inc., or North Coast, closed an acquisition of 100% of the common stock of Power Gas Marketing & Transmission, Inc., or PGMT, for a purchase price of $115.0 million before contractual adjustments, and a net purchase price of $113.0 million. The purchase price included the assumption of $13.1 million of debt and $38.1 million of derivative financial instruments. Upon closing of the transaction, which was funded with indebtedness drawn under our credit facility, we paid the assumed debt and terminated the assumed derivative financial instruments. The acquisition was accounted for as a purchase in accordance with SFAS No. 141. The allocation of the purchase price to the assets and liabilities of PGMT is presented on the following table (in thousands).
Winchester Acquisition
On October 2, 2006, our wholly-owned subsidiary, Winchester Acquisition, LLC, or Winchester Acquisition, acquired Winchester Energy Company, Ltd., or Winchester, and its affiliated entities from Progress Fuels Corporation for $1.1 billion in cash, subject to purchase price adjustments, which was funded with indebtedness, as discussed below and in Note 8. The acquisition was accounted for as a purchase in accordance with SFAS No. 141. Goodwill of $163.9 million resulted from the acquisition, primarily due to the Company’s emphasis in concentrating on assets in the East Texas/North Louisiana producing regions.
The allocation of the purchase price to the assets and liabilities of Winchester is presented on the following table (in thousands):
Pro forma results of operations
The following table reflects the unaudited pro forma results of operations as though the acquisitions of TXOK, PGMT and Winchester had occurred at the beginning of each respective period (in thousands except per share data):
Acquisition of North Coast Energy, Inc.
On November 26, 2003, EXCO entered into the North Coast Acquisition Agreement, as amended and restated on December 4, 2003, to acquire all of the issued and outstanding stock of North Coast pursuant to a tender offer and merger. EXCO acquired all of the outstanding common stock, options and warrants of North Coast on January 27, 2004 for a purchase price of $168.0 million, including transaction related
costs, and we assumed $57.1 million of North Coast's outstanding indebtedness. As a result, on January 27, 2004, North Coast became a wholly-owned subsidiary and established a new core operating area for us in the Appalachian Basin. We have accounted for the North Coast acquisition using the purchase method of accounting and have consolidated its operations effective January 27, 2004.
The following table reflects the unaudited pro forma results of operations for the year ended December 31, 2004. The information for the year ended December 31, 2004 has been derived from our audited consolidated statement of operations for the year ended December 31, 2004 and North Coast's unaudited consolidated financial statement of operations for the 26 day period from January 1 to January 26, 2004. The pro forma results of operations give effect to the payment of our related fees and expenses as if each occurred on January 1, 2004.
During North Coast's 26 day period from January 1, 2004 to January 26, 2004, there was $11.9 million in investment banking fees, employee bonus and severance payments and other costs incurred in connection with the merger with EXCO that have been excluded from net income in the following table:
The pro forma information presented herein does not purport to be indicative of the financial position or results of operations that would have actually occurred had the events discussed above occurred on the dates indicated or which may occur in the future.
5. Sale of Addison Energy Inc.
On January 17, 2005, our directors approved the Share and Debt Purchase Agreement (the Addison Purchase Agreement), dated effective January 12, 2005, among 1143928 Alberta Ltd., a corporation organized under the laws of the Province of Alberta (Purchaser) and a wholly-owned subsidiary of NAL Oil & Gas Trust, an Alberta trust, EXCO and Taurus Acquisition, Inc. (Taurus), our wholly-owned subsidiary. The Addison Purchase Agreement provided that EXCO would sell to Purchaser all of the issued and outstanding shares of common stock of Addison Energy Inc. (Addison), which was at that time our wholly-owned Canadian subsidiary. The Addison Purchase Agreement also provided that Taurus would sell to Purchaser a promissory note in the amount of U.S. $98.8 million and a promissory note in the amount of Cdn. $108.3 million (U.S. $79.3 million) (collectively, the Addison Notes), each of which were issued by Addison in favor of Taurus. This transaction closed on February 10, 2005.
The aggregate purchase price for the stock and the Addison Notes was Cdn. $551.3 million (U.S. $443.4 million). Of this amount Cdn. $90.1 million (U.S. $72.1 million) was used to repay in full all outstanding balances under Addison's credit facility while Cdn. $56.2 million (U.S. $45.2 million) was withheld and has been remitted to the Canadian government for potential income taxes that we may owe resulting from the sale of the stock. As of December 31, 2005, we had a receivable in the amount of Cdn. $21.5 million (U.S. $18.5 million) for the excess of the amount withheld for Canadian income taxes from the sales proceeds over the estimated amount of Canadian income taxes that were actually owed on the gain from the sale which was received in March 2006. The purchase price was subject to further adjustment based upon, among other items, the final determination of Addison's working capital balance. In June 2005, we adjusted the liability and the gain recognized on the sale by Cdn. $1.6 million (U.S. $1.3 million). In October 2005, we paid the Purchaser the Cdn. $1.6 million (U.S. $1.1 million) in settlement of the working capital balance. The purchase price remains subject to additional adjustments based upon the outcome of Crown royalty and joint venture audits, if any, that may occur in the future that cover periods prior to February 1, 2005.
All severance payments paid or payable in respect of employees terminated up to May 31, 2005 were borne by EXCO. If Purchaser or its affiliates made an employment offer to a terminated employee and the employee accepted the offer, Purchaser was obligated to pay EXCO an amount equal to all severance payments paid to that employee. This obligation was in effect for a period of six months for any employee terminated at closing and for an indefinite period for any employee terminated after closing but prior to May 31, 2005. At closing, Cdn. $2.1 million (U.S. $1.7 million) was deducted from the sales proceeds for severance payments made to Addison employees who were terminated at closing.
We recognized a gain from the sale of Addison in the amount of U.S. $175.7 million before income tax expense of U.S. $49.3 million related to the gain. The cumulative adjustment resulting from the translation of Addison's financial statements was eliminated as these amounts were considered in the determination of the gain on the sale.
The following table presents the summary operating results for Addison, which are reported as a discontinued operation:
Addison Energy Inc. dividend
On February 9, 2005 Addison made an earnings and profits dividend (as calculated under U.S. tax law) to EXCO in an amount of Cdn. $74.5 million (U.S. $59.6 million). This dividend was funded by Addison by an additional drawdown on its bank credit facility. The dividend was subject to Canadian tax withholding of 5% or Cdn. $3.7 million (U.S. $3.0 million), which amount has been included in the 2004 tax provision.
Presentation on financial statements
Addison's financial position and results of operations have been reported as discontinued operations. We have revised our consolidated statements of cash flows for the year ended December 31, 2004 to separately disclose the operating, investing, and financing sections of the cash flows attributable to Addison's operations. We had previously reported the income or loss from discontinued operations as a component of net cash provided by or used in operating activities of discontinued operations.
6. Acquisitions and dispositions
Transactions other than TXOK, PGMT and Winchester that occurred during 2006
In April and May 2006, we acquired producing properties and undeveloped acreage in West Texas and the Cotton Valley trend in East Texas in two separate acquisitions. The aggregate purchase price of these assets was $135.8 million, after contractual adjustments, which was funded with indebtedness drawn under our credit agreement.
In August and September 2006, we closed two acquisitions of producing properties and acreage for an aggregate purchase price of $76.9 million, after contractual adjustments, adding properties and acreage in our Appalachia and Rockies areas. We paid $27.5 million for properties located in Wyoming.
For the year ended December 31, 2006, property and other asset sales totaled $5.8 million.
Transactions, other than the sale of Addison, that occurred during 2005
During the 275 day period from January 1, 2005 to October 2, 2005, we completed seven oil and natural gas property acquisitions. The total purchase price for the acquisitions was approximately $102.3 million, funded with borrowings under our U.S. credit agreement and from surplus cash. In addition, we acquired a small natural gas gathering system for $0.7 million as part of one of the acquisitions.
During the 275 day period from January 1, 2005 to October 2, 2005, we completed seven sales of oil and natural gas properties. As of January 1, 2005, estimated total Proved Reserves net to our interest from these properties included approximately 0.3 Mmbbls of oil and NGLs and 18.4 Bcf of natural gas. The total sales proceeds we received were approximately $45.4 million. During the year ended December 31, 2004, we recorded revenue of approximately $5.5 million and oil and natural gas production costs of approximately $1.2 million on these properties. During the 275 day period from January 1, 2005 to October 2, 2005, we recorded revenues of approximately $3.7 million and oil and natural gas production costs of approximately $1.2 million on these properties through the date of their respective dispositions.
During the 90 day period from October 3, 2005 to December 31, 2005, we did not complete any acquisitions or dispositions of oil and natural gas properties.
Transactions, other than the acquisition of North Coast, that occurred during 2004
During the year ended December 31, 2004, we completed six oil and natural gas property acquisitions in the United States. The total purchase price, after contractual adjustments, for the acquisitions was approximately $88.4 million funded with borrowings under our U.S. credit agreement and from surplus cash.
During the year ended December 31, 2004, we completed 21 sales of oil and natural gas properties in the United States. The total sales proceeds we received were approximately $51.9 million.
Pro forma financial information has not been provided because the acquisitions and dispositions were not material.
7. Derivative financial instruments
The following table sets forth our oil and natural gas derivatives as of December 31, 2006. The fair values at December 31, 2006 are estimated from quotes from the counterparties and represent the amount that we would expect to receive or pay to terminate the contracts at December 31, 2006. We have the right to offset amounts we expect to receive or pay among our individual counterparties. As a result, we have offset amounts for financial statement presentation purposes.
At December 31, 2006, the average forward NYMEX oil prices per Bbl for calendar 2007 and 2008 were $65.02 and $67.50, respectively, and the average forward NYMEX natural gas prices per Mmbtu for calendar 2007 and 2008 were $6.97 and $8.06, respectively.
During the 275 day period from January 1, 2005 to October 2, 2005, we canceled several of our commodity price risk management contracts upon the payment of $67.6 million to our counterparties, of which $15.0 million was related to the sale of Addison. We also entered into new commodity price risk management contracts at higher prices.
8. Long-term debt and interim bank loan
Credit agreements
Interim bank loan
In order to fund the Equity Buyout on October 3, 2005, Holdings II borrowed $350.0 million in interim debt financing under a credit agreement dated October 3, 2006 with JP Morgan. The loan was collateralized by a first priority lien on all of Holdings II common stock. The maturity date of the loan was July 3, 2006, with an interest rate of 10%. The loan agreement contained representations and warranties, covenants and conditions usual for a transaction of this type. Covenants contained in the loan include, among other things, restrictions on the incurrence of indebtedness, the payment dividends, redemption of capital stock and making of certain investments, sales of assets and subsidiary stock, entering into sale and leaseback transactions, entering into agreements that restrict the payment of dividends by subsidiaries, or the repayment of intercompany loans and advances, entering into affiliate transactions, entering into mergers, consolidations and sales of substantially all of our assets, amending material debt instruments, and certain other activities.
On February 14, 2006, upon closing of the initial public offering (IPO), the interim bank loan, together with accrued interest was paid in full.
EXCO Credit Agreement
On March 17, 2006, EXCO Resources, Inc. and certain of its subsidiaries entered into an amended and restated credit agreement, or our credit agreement, with certain lenders, JPMorgan Chase Bank, N.A., as administrative agent, and J.P. Morgan Securities Inc., as sole bookrunner and lead arranger. This amendment established a new borrowing base of $750.0 million under our credit agreement reflecting the addition of the assets of TXOK. TXOK and its subsidiaries became guarantors of our credit agreement. The amendment also provided for an extension of our credit agreement maturity date to December 31, 2010. The borrowing base is redetermined each November 1 and May 1, beginning November 1, 2006. Our borrowing base is determined based on a number of factors including commodity prices. We use derivative financial instruments to lessen the impact of volatility in commodity prices. Financial covenants under the amended credit agreement require that we:
· maintain a consolidated current ratio (as defined under our credit agreement) of at least 1.0 to 1.0 at the end of any fiscal quarter; and
· not permit our ratio of consolidated indebtedness to consolidated EBITDAX (as defined under our credit agreement) to be greater than 3.5 to 1.0 at the end of each fiscal quarter.
Borrowings under our credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our oil and natural gas properties including TXOK’s Oklahoma properties and North Coast Energy, Inc. and their respective subsidiaries. Our borrowings are collateralized by a first lien mortgage providing a security interest in the value of our Proved Reserves which is at least 125% of the aggregate commitment. The aggregate commitment is the lesser of (i) $1.25 billion and (ii) the borrowing base, however, the initial aggregate commitment was $300.0 million. This aggregate commitment increased to $500.0 million on May 11, 2006, was reduced to $400.0 million on October 2, 2006, and was increased back to $500.0 million on February 2, 2007.
At our option, borrowings under our credit agreement accrue interest at one of the following rates:
· the sum of (i) the greatest of the administrative agent’s prime rate, the base CD rate plus 1.0% or the federal funds effective rate plus 0.50% and (ii) an applicable margin, which ranges from 0.0% up to 0.75% depending on our borrowing usage; or
· the sum of (i) LIBOR multiplied by the statutory reserve rate and (ii) an applicable margin, which ranges from 1.0% up to 1.75% depending on our borrowing usage.
We typically elect to borrow funds using the LIBOR interest rate option described above. At December 31, 2005 and 2006, the six month LIBOR rates were 4.70% and 5.37% which would result in interest rates of approximately 5.95% and 6.62%, respectively, on any new indebtedness we may incur under the credit agreement. At December 31, 2005 and 2006, we had $1,000 and $339.0 million respectively, of outstanding indebtedness under our credit agreement.
Additionally, the credit agreement contains a number of other covenants regarding our liquidity and capital resources, including restrictions on our ability to incur additional indebtedness, restrictions on our ability to pledge assets, and a prohibition on the payment of dividends on our common stock. As of December 31, 2006, we were in compliance with the covenants contained in our credit agreement.
In connection with the contribution by EXCO Resources to EXCO Partners of EXCO Resources’ East Texas assets, EXCO Resources entered into an amendment to its credit agreement (“First Amendment”). The First Amendment generally consents to and facilitates the contribution of the East Texas assets to EXCO Partners and provides that EXCO Partners, its subsidiaries and its general partners, all of which are subsidiaries of EXCO are unrestricted subsidiaries under our credit agreement, are not subject to the terms thereof and are no longer guarantors thereof. In addition, the assets contributed by EXCO Resources were released from the mortgages securing the credit agreement. Moreover, the assets of EXCO Partners and its subsidiaries have not been pledged under our credit agreement and none of EXCO Partners or the other unrestricted subsidiaries have guaranteed our credit agreement. The First Amendment also provides that the borrowing base under the credit agreement shall be reduced to $600.0 million, with an aggregate commitment of $400.0 million (increased back to $500.0 million on February 2, 2007). The First Amendment also revises the covenants regarding the format of the financial statements to be delivered by EXCO Resources and consents to the contingent equity contribution obligation described below under “EXCO Resources Equity Contribution Agreement” subject to certain conditions. The First Amendment also amends certain covenants to address the relationship with EXCO Partners. Prior to any public offering by EXCO Partners, EXCO Resources may not permit the subsidiaries through which EXCO Resources owns the equity of EXCO Partners to incur any indebtedness or incur any lien. Prior to any public offering by EXCO Partners, EXCO Resources is required to own 100% of the equity of EXCO Partners. As of February 28, 2007, $407.0 million of indebtedness was outstanding under our credit agreement and we had $91.5 million of availability under our credit agreement. Our consolidated debt as of February 28, 2007, which includes EPOP’s debt, our credit facility
and 71¤4% senior notes totals $2.2 billion. The debt incurred in the Winchester acquisition is more fully described below. We are in compliance with the financial covenants of the EXCO Credit Agreement as of December 31, 2006.
EPOP Revolving Credit Facility
To finance the Winchester acquisition and the $150.0 million payment to EXCO Resources for its East Texas assets, EXCO Partners’ wholly-owned subsidiary, EPOP, entered into a Senior Revolving Credit Agreement, or EPOP Revolving Credit Facility dated October 2, 2006, with a group of lenders led by JPMorgan Chase Bank, N.A. The EPOP Revolving Credit Facility has a face amount of $750.0 million with an initial borrowing base of $750.0 million and an initial conforming borrowing base of $650.0 million. The conforming borrowing base is the amount of borrowings upon which interest is computed on a lower premium to LIBOR than borrowings which exceed the conforming borrowing base. The borrowing base must be conforming by April 1, 2007. The EPOP Revolving Credit Facility is secured by a first priority lien on the assets of EPOP, including 100% of the equity of EPOP’s subsidiaries, and is guaranteed by all existing and future subsidiaries. We executed an amendment dated effective as of December 31, 2006, the EPOP Revolver First Amendment, which amends certain financial covenants contained in the EPOP Revolving Credit Facility. The EPOP Revolver Amendment was sought due to our inability to comply with the leverage ratio and interest coverage ratio tests, as defined below, as of December 31, 2006. The original financial covenant ratios were negotiated assuming a more accelerated drilling program, which would have resulted in higher forecasted production. In addition, interest expense attributable to the EPOP Senior Term Credit Agreement was higher than originally forecast as the final negotiated interest rate exceeded our initial estimates when the covenants were being negotiated. Management and the lenders believe these revised covenants are more consistent with the actual operational activities contemplated at EPOP during 2007. As amended, the EPOP Revolving Credit Facility contains the following financial covenants:
· EPOP’s Consolidated Current Ratio (as defined) as of the end of any fiscal quarter ending after September 30, 2006 is not permitted to be less than 1.00 to 1.00. The EPOP Revolver Amendment did not revise this covenant.
· EPOP’s ratio of (A) Consolidated Funded Indebtedness (as defined) as of the end of a fiscal quarter to (B) Consolidated EBITDAX (as defined) shall not be greater than:
· 6.00 to 1.00 (increased from 5.00 to 1.00) for the quarter ending December 31, 2006. For purposes of the December 31, 2006 Consolidated EBITDAX, the December 31, 2006 quarter shall be multiplied by four (4);
· 5.50 to 1.00 (increased from 4.00 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX calculated using a defined trailing period multiplied by a fraction);
· 5.50 to 1.00 (increased from 4.00 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);
· 5.25 to 1.00 (increased from 4.00 to 1.00) for the quarter ended December 31, 2007, and
· 4.00 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.
· EPOP will not permit its ratio of Consolidated EBITDAX to Consolidated Interest Expenses (as defined) to be less than:
· 1.50 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2006 (Consolidated EBITDAX and Consolidated Interest Expenses for such quarter to be multiplied by four);
· 1.75 to 1.00 (lowered from 2.50 to 1.00) for the first and second quarters of 2007 (Consolidated EBITDAX and Consolidated Interest Expenses calculated using a defined trailing period multiplied by a fraction);
· 1.75 to 1.00 (lowered from 2.50 to 1.00) for the quarter ended September 30, 2007 (with Consolidated EBITDAX and Consolidated Interest Expenses calculated using, for this quarter and all subsequent quarters, the trailing four quarter period ending on such date);
· 2.00 to 1.00 (lowered from 2.50 to 1.00) as of the quarter ended December 31, 2007, and
· 2.50 to 1.00 (unchanged) for any quarter ending on or after March 31, 2008.
· Finally, EPOP will not permit its ratio of net present value (calculated pursuant to the terms of the EPOP Revolving Credit Facility) to Consolidated Funding Indebtedness (as defined) to be less than (i) 1.15 to 1.00 (unchanged) determined as of December 31, 2006 or (ii)1.25 to 1.00 (unchanged) determined as of each succeeding June 30 and December 31.
The EPOP Revolving Credit Facility, as amended, contains representations, warranties, covenants, events of default, and indemnities customary for agreements of this type. The EPOP Revolving Credit Facility matures four years from the closing date and has an initial drawn interest rate of LIBOR + 175 basis points (“bps”) and an undrawn commitment fee of 37.5 bps on the first $650.0 million of the EPOP Revolving Credit Facility. To the extent usage exceeds the initial conforming borrowing base, the EPOP Revolving Credit Facility will have an initial drawn interest rate of LIBOR + 250 bps and an undrawn commitment fee of 50 bps on the portion of the borrowings that exceed the initial conforming borrowing base. Finally, as a condition precedent to the funding of the EPOP Revolving Credit Facility, EPOP is required to hedge 75% of proved developed producing production through 2010. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP. The initial amount borrowed under this facility was $651.0 million at closing of the Winchester merger and the weighted average interest rate as of December 31, 2006, is 7.19%. As of February 28, 2007, $643.5 million was outstanding under this facility. We are in compliance with the financial covenants, as amended, pursuant to the EPOP Revolver First Amendment as of December 31, 2006.
EPOP Senior Term Credit Agreement
In connection with the Winchester acquisition and the EXCO Resources asset contribution, EPOP entered into the EPOP Senior Term Credit Agreement, dated October 2, 2006 (as amended and restated as of October 13, 2006), with JPMorgan Chase Bank, N.A., as administrative agent. The aggregate principal amount is $650.0 million. The EPOP Senior Term Credit Agreement is secured by a second priority lien on all of the properties securing the EPOP Revolving Credit Facility, including 100% of the stock of subsidiaries, and is guaranteed by all existing and future subsidiaries. Financial covenants governing the EPOP Senior Term Credit Agreement include the same net present value ratio contained in the EPOP Revolving Credit Facility, a Leverage Ratio computed similarly to the covenant contained in the EPOP Revolving Credit Facility that cannot exceed 5.50 to 1.00 for applicable periods, and an Interest Coverage Ratio that cannot be less than 2.00 to 1.00 for any applicable period. The debt covenant tests for the EPOP Senior Term Credit Agreement begin with the quarter ended March 31, 2007. In addition, EPOP cannot make Capital Expenditures (as defined) exceeding $125.0 million in any fiscal year. The EPOP Senior Term Credit Agreement contains representations, warranties, covenants, events of default and indemnities customary for agreements of this type. The EPOP Senior Term Credit Agreement has an interest rate of LIBOR + 600 bps, with 25 bps step-ups on October 2, 2007 and January 2, 2008, and a total cap of LIBOR + 650 bps. Additionally, the EPOP Senior Term Credit Agreement matures five years from
the closing date, requires payments of principle at 1% per year, with the balance of unpaid principle due at maturity. Upon an initial public offering by EXCO Partners, EPOP shall prepay the principal outstanding (plus accrued interest) under the EPOP Senior Term Credit Agreement at par plus an applicable premium. Commencing with the fiscal year ended December 31, 2007, and each year thereafter, EPOP must apply 100% of its Excess Cash Flow (as defined in the EPOP Senior Term Credit Agreement) toward prepayment at par of the EPOP Senior Term Credit Agreement. Such payments shall be made no later than the later of April 15 or five business days following delivery of the annual financial statements required under the EPOP Senior Term Credit Agreement. Any principal payment prior to the first anniversary, other than the mandatory cash flow and amortization prepayments described above, must be paid at 102% of the principal amount and after the first anniversary date to and including the second anniversary at 101% of par. Thereafter, any prepayments are at par. The repayment obligation under this facility can be accelerated upon the occurrence of an event of default including the failure to pay principal or interest, a material inaccuracy of a representation or warranty, failure to observe or perform covenants, subject to certain cure periods, bankruptcy, judgments against EPOP or any subsidiary in excess of $5.0 million or a change of control (as defined) of EPOP.
EXCO Resources Equity Contribution Agreement
In connection with the arrangement of the EPOP Senior Term Credit Agreement, the lenders required EXCO Resources to enter into an Equity Contribution Agreement, dated October 2, 2006, and amended and restated on October 4, 2006 and October 13, 2006 (as amended and restated, the “ECA”). The ECA generally provides that on the date 18 months from October 2, 2006 (Equity Contribution Date), EXCO Resources will make a cash common equity contribution to EPOP in an amount equal to the lesser of (i) $150.0 million or (ii) the aggregate amount then outstanding under the EPOP Senior Term Credit Agreement; provided, that in no event can this obligation exceed during the term of the ECA the maximum amount that EXCO Resources could contribute under the terms of the Indenture governing its senior notes. Alternatively, EXCO Resources can cause EXCO Partners to make the equity contribution to EPOP in the amount of $150.0 million to satisfy this obligation. In lieu of requiring the equity contribution, the holders of at least 662¤3% of the aggregate principal amount of the loans outstanding under the EPOP Senior Term Credit Agreement can elect at the Equity Contribution Date to require EPOP and its subsidiaries to become “Restricted Subsidiaries” under the credit agreement and require EXCO Resources to provide, and cause all then restricted subsidiaries as defined and constituted under the credit agreement to provide, guarantees and collateral in respect of the EPOP Senior Term Credit Agreement on terms substantially consistent with the guarantees and collateral provided under its credit agreement. This requirement is subject to compliance with the credit agreement. Any cash so contributed shall be used by EPOP to prepay loans under the EPOP Senior Term Credit Agreement. EXCO Resources is prohibited from making restricted payments (as defined in the Indenture) that would constitute a utilization of the Indenture restricted payment baskets, other than restricted payments not to exceed $5.0 million In addition, EXCO Resources has covenanted to redeem or defease its senior notes if the Indenture would not permit the equity contribution or the lenders’ election to cause EXCO Resources to designate EPOP and its subsidiaries as restricted subsidiaries under the credit agreement (subject to certain restrictions on the indebtedness that may be incurred for any such redemption or defeasance if the election to cause the designation of EPOP as a restricted subsidiary is chosen). The ECA will terminate upon payment in full of the EPOP Senior Term Credit Agreement.
7¼% senior notes due January 15, 2011
On January 20, 2004, EXCO completed the private placement of $350.0 million aggregate principal amount of 7¼% senior notes due January 15, 2011 pursuant to Rule 144A and Regulation S under the Securities Act of 1933 (Securities Act) at a price of 100% of the principal amount. The net proceeds of the offering were used to acquire North Coast, pay down debt under our credit facilities and North Coast’s
credit facility, repay our senior term loan in full and pay fees and expenses associated with those transactions.
Concurrent with the issuance of the senior notes, we wrote off $0.9 million of costs incurred in January 2004 to secure interim loan financing which was not utilized upon issuance of the senior notes and deferred financing costs of approximately $0.7 million related to the senior term loan, which was retired with the proceeds of the senior notes. These amounts are reflected in the consolidated statements of operations as interest expense.
On April 13, 2004, EXCO completed a private placement of an additional $100.0 million aggregate principal amount of the senior notes pursuant to Rule 144A, having the same terms and governed by the same Indenture as the notes issued on January 20, 2004. The notes issued on April 13, 2004 were issued at a price of 103.25% of the principal amount plus interest accrued since January 20, 2004. The net proceeds of the April 13, 2004 offering were used to repay substantially all of our outstanding indebtedness under our Canadian credit agreement and pay fees and expenses associated therewith.
On May 28, 2004, EXCO concluded an exchange offer of $450.0 million aggregate principal amount of our senior notes, which were privately placed in January and April 2004, for $450.0 million aggregate principal amount of our senior notes that have been registered under the Securities Act. Holders of all but $0.3 million of the senior notes elected to accept our exchange offer.
The Equity Buyout was a change of control under the Indenture governing the senior notes. As a result of this change of control and also in connection with the sale of Addison, on November 2, 2005, we commenced an offer to the holders of senior notes to repurchase up to $120.6 million of senior notes at 100% of the principal amount plus accrued and unpaid interest of the notes pursuant to the Indenture. Simultaneously therewith, we commenced an offer to repurchase all outstanding senior notes at 101% of the principal amount plus accrued and unpaid interest in connection with the change in control provision contained in the Indenture as a result of the Equity Buyout. Holders of $5.3 million in aggregate principal amount of the senior notes were tendered to and purchased by us in December 2005 as a result of these offers for total consideration of $5.5 million including accrued plus unpaid interest and the applicable premium. As a result of the repurchase of these senior notes, we recognized a gain upon the early extinguishment of these notes in the amount of approximately $151,000 during the 90 day period from October 3, 2005 to December 31, 2005 which has been reflected in other income on our consolidated statements of operations. Upon completion of the offer to repurchase related to the Addison sale, the second lien security interest on $120.6 million of the proceeds from the sale and the general restrictions under the Indenture on the entire proceeds was terminated.
Interest is payable on the senior notes semi-annually in arrears on January 15 and July 15 of each year. The senior notes mature on January 15, 2011. Prior to January 15, 2007, EXCO may redeem all, but not less than all, of the senior notes in cash at a redemption price equal to 100% of the principal amount of the notes plus a premium. We may redeem some or all of the senior notes beginning on January 15, 2007 for the redemption price set forth in the notes.
As part of the “pushdown accounting” resulting from the Equity Buyout, the senior notes were recorded at their fair value of $468.0 million on October 3, 2005. The resulting premium of $18.0 million in excess of the aggregate principal amount is being amortized over the remaining life of the senior notes. The unamortized premium was $14.1 million at December 31, 2006. The purchase of the $5.3 million in aggregate principal amount of senior notes tendered to us as discussed above reduced the premium to be amortized by approximately $202,000.
The Indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:
· incur or guarantee additional debt and issue certain types of preferred stock;
· pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated debt;
· make investments;
· create liens on our assets;
· enter into sale/leaseback transactions;
· create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;
· engage in transactions with our affiliates;
· transfer or issue shares of stock of subsidiaries;
· transfer or sell assets; and
· consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries.
The estimated fair value of our senior notes at December 31, 2006 was $453.6 million as compared to the carrying amount of $458.8 million (including $14.1 million of unamortized premium). The fair value of the senior notes is estimated based on quoted market prices for the senior notes.
Following is the principal maturity schedule for the debt outstanding as of December 31, 2006 (in thousands):
9. Environmental regulation
Various federal, state and local laws and regulations covering discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect our operations and the costs of our oil and natural gas exploitation, development and production operations. We do not anticipate that we will be required in the foreseeable future to expend amounts material in relation to the financial statements taken as a whole by reason of environmental laws and regulations. Because these laws and regulations are constantly being changed, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us.
10. Commitments and contingencies
We lease our offices and certain equipment. Our rental expenses were approximately $0.6 million, $0.6 million, $0.2 million and $1.7 million for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006, respectively. Our future minimum rental payments under
operating leases with remaining noncancellable lease terms at December 31, 2006, are as follows (in thousands):
We regularly enter into agreements with contract drilling companies which commit us to utilize, or to pay for if not utilized, the use of drilling rigs in east Texas. As of December 31, 2006, the minimum amount that we are obligated to pay under these contracts is $78.6 million.
On October 11, 2006, a putative class action was filed against our subsidiary, North Coast Energy, Inc. The case is styled PRC Holdings, LLC, et al. v. North Coast Energy, Inc. and was filed in the Circuit Court of Roane County, West Virginia. This action has been removed to the United States District Court for the Southern District of West Virginia. The action has been brought by certain landowners and lessors in West Virginia for themselves and on behalf of other similarly situated landowners and lessors in West Virginia. The lawsuit alleges that North Coast Energy, Inc. has not been paying royalties to the plaintiffs in the manner required under the applicable leases, has provided misleading documentation to the plaintiffs regarding the royalties due, and has breached various other contractual, statutory and fiduciary duties to the plaintiffs with regard to the payment of royalties. In a case styled The Estate of Garrison Tawney v. Columbia Natural Resources, LLC announced in June 2006, the West Virginia Supreme Court held that language such as “at the wellhead” and similar language contained in leases when used in describing how to calculate royalties due lessors was ambiguous and, therefore, should be construed strictly against the lessee. Accordingly, in the absence of express language in a lease that is intended to allocate between a lessor and lessee post-production costs such as the costs of marketing the product and transporting it to the point of sale, no post-production costs may be deducted from the lessor’s royalty payment due from the lessee. The claims alleged by the plaintiffs in the lawsuit filed against us are similar to the claims alleged in the Tawney case. Plaintiffs are seeking common law and statutory compensatory and punitive damages, interest and costs and other remedies. We are vigorously defending the existing lawsuit. The action is in a very preliminary stage. The preliminary status of the lawsuit leaves the ultimate outcome of this litigation uncertain. We believe that we have substantial defenses to this lawsuit and that the adverse affects from this litigation, if any, are reflected in our financial statements and we do not expect the ultimate outcome of the lawsuit to have a material effect on our financial position, results of operations or cash flows.
In the ordinary course of business, we are periodically a party to lawsuits. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a materially adverse effect on our results of operations or financial condition.
11. Employee benefit plans
We sponsor two 401(k) plans for our U.S. employees and match up to 100% of employee contributions based on years of service with us. Our matching contributions of $0.4 million, $0.4 million, $95,000 and $1.1 million for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, for the 90 day period from October 3, 2005 to December 31, 2005 and for the year ended December 31, 2006, respectively, have been included as general and administrative expense.
12. Bonus retention program
Prior to entering into the Equity Buyout, Holdings established a bonus retention program in 2003 to provide an incentive for the employee stockholders of Holdings to remain employed with the company and its subsidiaries. The program provided for equal quarterly payments to the employee stockholders totaling $1.8 million on an annual basis. For the year ended December 31, 2004, we included approximately $1.4 million in general and administrative expense and $0.4 million in income from operations of discontinued operations related to this program.
The payments to employee stockholders were to continue for four years unless the employee stockholder voluntarily terminated employment or was dismissed for cause, at which time the payments would cease. On February 10, 2005, in conjunction with the sale of Addison, the Addison employee bonus retention plan was terminated and all bonus retention amounts payable, aggregating approximately $1.0 million, were accelerated and paid in full pursuant to the terms of the plan. This amount has been included in the loss from operations of discontinued operations during the 275 day period from January 1, 2005 to October 2, 2005. The Equity Buyout on October 3, 2005 constituted a change of control as defined in the agreement. As a result, the employee bonus retention plan was terminated resulting in an additional charge of $2.6 million. Accordingly, all bonus retention amounts payable, aggregating approximately $2.8 million, were accelerated and paid in full pursuant to the terms of the plan. As a result, we have included this amount in general and administrative expense related to this program during the 275 day period from January 1, 2005 to October 2, 2005.
13. Earnings per share
The following table presents basic and diluted earnings (loss) per share for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 (in thousands, except per share amounts):
As a result of the loss from continuing operations for the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, the potential common stock equivalents from the assumed conversion of stock options of 5,097,369 and 8,801,351, respectively, have been excluded from the diluted EPS calculation. For financial accounting purposes, the Class B shares of Holdings for the year ended December 31, 2004 and the 275 day period from January 1, 2005 to October 2, 2005, were considered to be a “variable” plan since a holder of the shares had to be employed at the date of a change in control to receive fair value for the Class B shares. As a result, the Class B shares have been excluded from per share calculations as required under SFAS No. 128.
14. Stock transactions
Stock options
As discussed in “Note 2. Summary of significant accounting policies”, certain of our employees were granted Holdings stock options under the Holdings Plan. The following table summarizes Holdings stock option activity under the Holdings Plan, which were canceled upon consummation of the Equity Buyout:
All of the issued and outstanding Holdings stock options as of October 3, 2005 were purchased by Holdings as a part of the Equity Buyout transaction. This resulted in a charge of $17.8 million to general and administrative expense during the 275 day period from January 1, 2005 to October 2, 2005.
The 2005 Incentive Plan provides for the granting of options to purchase up to 10,000,000 shares of EXCO’s common stock. The options expire ten years following the date of grant and have a weighted average remaining life of 9.19 years. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of December 31, 2006, there were 1,574,475 shares available to be granted under the Plan.
The following table summarizes stock option activity related to our employees under the 2005 Incentive Plan:
The weighted average grant date fair value of stock options granted during the years 2005 and 2006 were $2.29 and $4.75, respectively. The total intrinsic value of stock options exercised for the 90 day period from October 3, 2006 and the year ended December 31, 2006 was $0 and $0.9 million, respectively.
The following summarizes the status of the non-vested stock options as of December 31, 2006 and changes for the year ended December 31, 2006:
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. Options are granted at the fair market value of the common stock on the date of grant. The following assumptions were used for the options included in the above table:
As required by SFAS 123(R), the granting of options under the 2005 Incentive Plan to our employees 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 was determined based on the weighted average of historical volatility of the common stock of the Predecessor for .25 years and the daily closing prices from five comparable public companies. Total share-based compensation for the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 was $3.2 million and $7.9 million, of which $2.2 million and $6.5 million is included in general and administrative expense and $1.0 million and $1.4 million was capitalized as part of proved developed and undeveloped oil and natural gas properties, respectively, as discussed in “Note 2. Summary of significant accounting policies.” Total share-based compensation to be recognized on unvested awards is $15.5 million over a weighted average period of 2.40 years as of December 31, 2006.
As discussed in “Note 1. Organization,” the Class B common stock issued in July 2003 was considered to be a “variable” plan for financial reporting purposes. As a result, we recognized a non-cash charge of approximately $44.1 million during the 275 day period from January 1, 2005 to October 2, 2005 related to the Class B common stock.
15. Income taxes
The income tax provision attributable to our income (loss) before income taxes consists of the following:
We have net operating loss carryforwards (NOLs) for United States income tax purposes that have either been generated from our operations or were purchased in our acquisitions. Our ability to use the purchased NOLs has been restricted by Section 382 of the Internal Revenue Code due to ownership changes which occurred on December 19, 1997 and July 29, 2003, the change in ownership of Rio Grande, Inc. which occurred on March 16, 1999, as well as the Equity Buyout, which occurred on October 3, 2005. We estimate that approximately $7.9 million of the NOLs limited by Section 382 will expire prior to their utilization. Expiration is expected to occur from 2007 through 2016. Our NOL available for utilization at December 31, 2006 is approximately $129.3 million.
Prior to the fourth quarter of 2004, we had not provided for any U.S. deferred income taxes on the undistributed earnings of Addison, our former Canadian subsidiary, based upon the determination that those earnings would be indefinitely reinvested in Canada. On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). The Act created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividends received deduction for certain dividends from controlled foreign corporations. In February 2005, we repatriated Cdn. $74.5 million (U.S. $59.6 million) in an extraordinary dividend, as defined in the Act, from Addison. Accordingly, we recognized a tax liability of $8.2 million as of December 31, 2004 related to the extraordinary dividend. This dividend represented a substantial portion of the undistributed earnings of Addison, based upon its earnings and profits as determined under U.S. federal income tax law, as of December 31, 2004. As a result of certain technical corrections to the Act, we recognized a benefit of $2.1 million in our current income taxes during the 275 day period from January 1, 2005 to October 2, 2005 related to this dividend. This additional $2.1 million benefit has been recognized as a component of taxes from continuing operations pursuant to SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109) and Emerging Issues Task Force 93-13, “Effect of a Retroactive Change in Enacted Tax Rates That is Included in Income from Continuing Operations” (EITF 93-13), which require that the tax effect of a change in enacted tax rates be allocated to continuing operations without regard to whether the item giving
rise to the effect is a component of discontinued operations. On May 18, 2006, the Texas governor signed into law a Texas Margin tax that replaces the current franchise tax effective January 1, 2007. We had recorded the effect of the change in tax rate on our existing deferred balances in the second quarter of 2006. Our deferred income tax related to the Texas Margin tax is $0.9 million at December 31, 2006.
For the year ended December 31, 2004, we recognized a deferred income tax benefit of approximately $0.9 million related to Canadian legislation which became effective in May 2004 to phase in reduced income tax rates and allow for deductibility of crown royalties. This amount has been reflected as an income tax benefit in continuing operations pursuant to the provisions of SFAS No. 109 and EITF 93-13 as discussed above.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax liabilities and assets are as follows:
A reconciliation of our income tax provision (benefit) computed by applying the statutory United States federal income tax rate to our income (loss) before income taxes for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, the 90 day period from October 3, 2005 to December 31, 2005 and the year ended December 31, 2006 is presented in the following table:
16. Related party transactions
TXOK acquisition
On September 16, 2005, Holdings (formerly Holdings II) incorporated TXOK Acquisition, Inc. (TXOK), a Delaware corporation with a $1,000 investment in TXOK common stock. TXOK was formed to acquire (i) all of the issued and outstanding shares of common stock of ONEOK Energy Resources Company (ONEOK Energy) and (ii) all of the issued and outstanding membership interests of ONEOK Energy Resources Holdings, LLC (ONEOK Energy LLC) (collectively ONEOK Energy). ONEOK Energy was wholly-owned by ONEOK, Inc., a Tulsa-based public utility company.
The ONEOK Energy acquisition closed on September 27, 2005. The purchase price paid at closing, based upon adjustments as of that date, was $633.0 million, net of contractual adjustments. Effective upon closing, ONEOK Energy and ONEOK Energy LLC became wholly-owned subsidiaries of TXOK.
TXOK funded the ONEOK Energy acquisition with (i) $20.0 million in private debt financing, $15.0 million of which was provided by Mr. Boone Pickens, one of our directors; (ii) the issuance of $150.0 million of TXOK preferred stock to BP EXCO Holdings LP, an entity controlled by Mr. Pickens; (iii) the TXOK credit facility, with an initial borrowing base of $325.0 million, of which approximately $308.8 million was drawn at the closing of the ONEOK Energy acquisition; and (iv) the TXOK second lien term loan facility of $200.0 million. Neither Holdings nor EXCO Resources were an obligor or guarantor with respect to these financings; however, Holdings (formerly Holdings II) pledged its stock in TXOK as collateral security for payment of the TXOK credit facility and the TXOK term loan.
On October 7, 2005 Holdings made an additional $20.0 million investment in TXOK. Holdings’ additional investment was partially funded by an advance of $4.0 million from EXCO Resources. TXOK
used these proceeds to repay the $20.0 million in private debt financing described in (i) above. Following the Equity Buyout, Holdings made payments on behalf of EXCO Resources of approximately $10.0 million, including bank fees associated with the interim bank loan that was pushed down to us. As of December 31, 2005, we had a net liability to Holdings of $6.1 million.
On February 14, 2006, in connection with our IPO, EXCO advanced TXOK $158.8 million to redeem its preferred stock and TXOK became our wholly-owned subsidiary. The TXOK preferred stock had full voting rights to vote with the TXOK common stock on all matters submitted to a vote by stockholders. Accordingly, holders of the TXOK preferred stock held voting control of TXOK prior to the February 14, 2006 redemption. If the TXOK preferred stock was not redeemed on or before September 27, 2006, the TXOK preferred stock and accumulated dividends would have automatically converted into common stock representing 90% of the outstanding common stock of TXOK. We used the equity method of accounting for our investment in TXOK until February 14, 2006, when TXOK became a wholly-owned subsidiary.
Effective October 15, 2005, we entered into an agreement with TXOK to manage TXOK’s business affairs. Mr. Pickens controlled TXOK through BP EXCO Holdings LP’s ownership of the TXOK preferred stock. The agreement provided that we would provide TXOK with general management, treasury, finance, legal, audit, tax, information technology, and payroll and benefit administration services. TXOK agreed to reimburse us on a monthly basis for the total amount of compensation, taxes and benefits we provide to employees providing services to TXOK. TXOK also agreed to pay us $25,000 per month for the additional services that we provide, as well as reimbursement of all costs directly related to the operations of TXOK. We hired 57 people who were formerly employed by ONEOK and historically worked on these assets. TXOK reimbursed us for all compensation expenses of these employees. At December 31, 2005, we had approximately $2.6 million reflected in accounts receivable-related parties on our consolidated balance sheet as due to us from TXOK of which $0.3 million was to reimburse us for accrued, but unpaid, stock option compensation expense for our employees who are assigned to manage TXOK’s business. On February 14, 2006, TXOK became our wholly-owned subsidiary and the accounts under the related party arrangements were settled.
Corporate use of personal aircraft
We periodically charter, for company business, a jet aircraft from DHM Aviation, LLC, a company owned by Douglas H. Miller, our chairman and chief executive officer. The Board of Directors has adopted a written policy covering the use of this aircraft. The Company believes that prudent use of a chartered private airplane by our senior management while on company business can promote efficient use of management time. Such usage can allow for unfettered, confidential communications among management during the course of the flight and minimize airport commuting and waiting time, thereby promoting maximum use of management time for company business. However, we restrict the use of the aircraft to priority company business being conducted by senior management in a manner that is cost effective for us and our shareholders. As a result, EXCO reimbursed use of the aircraft is restricted to company business. Such use must be approved in advance by Resources’ President and Chief Financial Officer. We maintain a detailed written log of such usage specifying the company personnel (and others, if any) that fly on the aircraft, the travel dates and destination(s), and the company business being conducted. In addition, the log contains a detail of all charges paid or reimbursed by us with supporting written documentation.
In the event the aircraft is chartered for a mixture of company business and personal use, all charges will be reasonably allocated between company reimbursed charges and charges to the person using the aircraft for personal use.
At least annually, and more frequently if requested by the Audit Committee, our Director of Internal Audit surveys fixed base operators and other charter operators located at Dallas Love Field, Dallas, Texas
to ascertain hourly flight rates for aircraft of comparable size and equipment in relation to the aircraft. This survey also ascertains other charges (including fuel surcharges) invoiced by such charter operators as well as out-of-pocket reimbursement policies. Such survey is supplied to the Audit Committee in order for the Audit Committee to establish an hourly rate and other charges EXCO shall pay for the upcoming calendar year for the use of the aircraft. The present hourly rate paid by EXCO to DHM Aviation, LLC is less than market rate for similar aircraft.
We reimburse DHM Aviation, LLC at a rate of $3,600 per hour, including fuel surcharges, for use of the aircraft. During the year ended December 31, 2004, we paid DHM Aviation, LLC $0.5 million for use of the aircraft. For the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005, we paid DHM Aviation, LLC $0.3 million and $0.1 million, respectively. Payments to DHM Aviation, LLC for the year ended December 31, 2006 were $0.4 million for use of the aircraft. During 2004, we were reimbursed a total of $93,000 of the aircraft fees by the underwriters of our senior notes offering.
Equity Buyout
On October 3, 2005, Holdings II acquired all the capital stock of EXCO Holdings and subsequently merged into EXCO Holdings. Upon its formation, Holdings II issued 3,333,330 shares of common stock to its founders for $0.01 per share. This group of founders included Mr. Douglas H. Miller, who purchased 1,655,000 shares, Mr. Stephen F. Smith, who purchased 333,330 shares, Dr. J. Douglas Ramsey, who purchased 166,670 shares (these shares were issued to a limited partnership in which Dr. Ramsey owns a 98.0% limited partnership interest), and Mr. Harold L. Hickey, who purchased 166,670 shares, as well as a number of our employees. Each of these persons and many of our employees also exchanged shares of EXCO Holdings common stock for Holdings II common stock or purchased additional shares of Holdings II common stock for cash.
Suite
The Company maintains a suite at the American Airlines Center in Dallas, Texas. The Company shares the suite with and is reimbursed for 50% of its expenses relative to the suite by an entity affiliated with Boone Pickens, one of our directors, pursuant to an arrangement entered into in 2006 between the Company and such entity. During the year ended December 31, 2006, the Company paid a total of $350,000 to maintain the suite, of which $175,000 was reimbursed by the entity affiliated with Mr. Pickens.
Other
Robert Stillwell, Jr., the son of Robert L. Stillwell, one of our directors, was employed by us from October 2002 until July 2005 as a financial analyst. In connection with the Equity Buyout in 2005, Robert Stillwell, Jr. received a payment of $71,187 for certain options granted to him as compensation for his employment with us and a payment of $41,064 under the Employee Stock Participation Plan. These payments were in addition to the prorated annualized salary of $45,000 that Robert Stillwell, Jr. received during the period of his employment in 2005.
17. Concentration of credit risk
During 2005 and 2006, sales of natural gas to an industrial customer and an interstate pipeline accounted for 10.1% and 11.6%, respectively, of our total oil and natural gas revenues. During 2004, sales of natural gas to an industrial customer accounted for 10.6% of our total oil and natural gas revenues. If we were to lose any one of our oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of our oil and natural gas in that particular purchaser’s service area. If we were to lose a purchaser, we believe we could identify a substitute purchaser.
18. Geographic operating segment information and oil and natural gas disclosures
We follow Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS No. 131). We have operations in only one industry segment, that being the oil and natural gas exploration and production industry. In prior periods, the Company provided geographic segment information for the following regions within the United States: EXCO, excluding Appalachia, and Appalachia. Effective in the fourth quarter of 2006, we no longer present separate financial information for geographic regions within the United States as we have aggregated these regions into one reportable segment. As a result, the prior period segment information has been deleted.
19. Subsequent events
On December 29, 2006, we announced an agreement with Anadarko Petroleum Corporation and Anadarko Gathering Company, or collectively Anadarko, to acquire substantially all of the oil and gas properties and related assets, or collectively the Vernon Assets, of Anadarko in the Vernon and Ansley Fields located in Jackson Parish, Louisiana through our wholly-owned subsidiary, Vernon Holdings, LLC, or Vernon, for $1.6 billion in cash. In December 2006, we deposited $80.0 million in an escrow account to be applied to the purchase price upon closing. We anticipate closing on these properties in the first quarter of 2007.
On February 2, 2007, we announced we had signed a Purchase and Sale Agreement, or the Southern Gas Purchase Agreement, with Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, or collectively Anadarko, to acquire substantially all of the oil and natural gas properties and related assets, of Anadarko in multiple fields located in the Mid-Continent, South Texas and Gulf Coast areas of Oklahoma and Texas. The purchase price is $860.0 million, of which, we have paid $43.0 million. We anticipate closing in the second quarter of 2007.
In conjunction with these acquisitions, we have received a revised commitment letter dated as of February 1, 2007, from J.P. Morgan Securities Inc. and JPMorgan Chase Bank, N.A. The new commitment letter provides for a senior secured revolving credit facility in the amount of $1.8 billion and a bridge loan facility in the amount of $1.1 billion, or collectively the new credit facilities. In addition, we are considering other financing alternatives, including a private placement of preferred stock.
In January 2007, we completed the sale of our producing properties and remaining undeveloped drilling locations in the Wattenberg Field area of the DJ Basin, Colorado. The transaction included substantially all of our assets in the area. The adjusted purchase price paid at closing was $131.9 million.
20. Quarterly financial data (unaudited)
The following are summarized quarterly financial data for the years ended December 31, 2005 and 2006:
21. 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 in the United States (referred to as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources, and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. On February 14, 2006, concurrent with the closing of our IPO, TXOK and its subsidiaries became restricted subsidiaries under and guarantors of the senior notes. On May 4, 2006, PGMT became a guarantor of the senior notes. In conjunction with the formation of EXCO Partners and the Winchester acquisition on October 2, 2006, certain of our existing subsidiaries, specifically ROJO Pipeline, Inc. and those TXOK subsidiaries that hold direct or indirect interests in certain of our East Texas assets were released from their guaranties under the senior notes and are now deemed unrestricted subsidiaries thereunder. EXCO Resources itself also contributed all of its directly held East Texas assets to EXCO Partners. EXCO Partners, its direct and indirect partners, which are also subsidiaries of EXCO Resources, and all of EXCO Partners’ subsidiaries are deemed unrestricted subsidiaries under the Indenture governing the senior notes and are not guarantors of the senior notes.
In connection with the formation of EXCO Partners on October 2, 2006 and the resulting contribution of EXCO’s assets in East Texas, its ROJO subsidiary and the East Texas subsidiaries of TXOK (collectively, the non-guarantor subsidiaries), the consolidating balance sheet as of December 31, 2005 and the consolidating statements of operations and consolidating statements of cash flows for the year ended December 31, 2004, the 275 day period from January 1, 2005 to October 2, 2005 and the 90 day period from October 3, 2005 to December 31, 2005 have been restated to reflect the non-guarantor subsidiaries as if they had been non-guarantor subsidiaries for all periods presented. We have also presented the 2006 consolidating financial statements to reflect the non-guarantor status as if it was in place at the beginning of the year.
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 and non-guarantor subsidiaries are presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.
EXCO Resources, Inc.
Consolidating balance sheet
December 31, 2005
EXCO Resources, Inc.
Consolidating balance sheet
December 31, 2006
EXCO Resources, Inc.
Consolidating statement of operations
For the year ended December 31, 2004
EXCO Resources, Inc.
Consolidating statement of operations
For the 275 day period ended October 2, 2005
EXCO Resources, Inc.
Consolidating statement of operations
For the 90 day period ended December 31, 2005
EXCO Resources, Inc.
Consolidating statement of operations
For the year ended December 31, 2006
EXCO Resources, Inc.
Consolidating statement of cash flow
For the year ended December 31, 2004
EXCO Resources, Inc.
Consolidating statement of cash flow
For the 275 day period ended October 2, 2005
EXCO Resources, Inc.
Consolidating statement of cash flow
For the 90 day period ended December 31, 2005
EXCO Resources, Inc.
Consolidating statement of cash flow
For the year ended December 31, 2006
22. Supplemental information relating to oil and natural gas producing activities-continuing operations (unaudited)
Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities (excluding all amounts related to Addison, our former Canadian subsidiary):
(1) Includes $199.3 million that was allocated to oil and natural gas properties in the North Coast purchase price allocation.
(2) Exploration costs are not considered material.
(3) Includes $489.1 million, $123.0 million and $583.7 million allocated to proved oil and natural gas properties in connection with the TXOK, PGMT and Winchester acquisitions, respectively.
(4) Includes $60.8 million, $0.4 million and $154.3 million allocated to unproved oil and natural gas properties in connection with the TXOK, PGMT and Winchester acquisitions, respectively.
We retain independent engineering firms to provide annual year-end estimates of our future net recoverable oil and natural gas reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on
undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations. All of our reserves are located onshore in the continental United States of America.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise. All amounts related to Addison, our former Canadian subsidiary, have been excluded from the information contained in this note.
Estimated Quantities of Proved Reserves
Estimated Quantities of Proved Developed Reserves
(1) Beginning December 31, 2005, NGL’s are no longer tracked separately as they are considered immaterial.
(2) Mcfe-One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Standardized measure of discounted future net cash flows
We have summarized the Standardized Measure related to our proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.
Standardized Measure of Discounted Future Net Cash Flows
During recent years, prices paid for oil and natural gas have fluctuated significantly. The spot prices at December 31, 2004, 2005 and 2006 used in the above table, were $43.33, $61.03 and $60.82 per Bbl of oil, respectively, and $6.18, $10.08 and $5.64 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials.
The following are the principal sources of change in the Standardized Measure:
Supplemental information relating to oil and natural gas producing activities-discontinued operations (unaudited)
Presented below are costs incurred in oil and natural gas property acquisition, exploration and development activities of our discontinued operations, which relate to Addison, our former Canadian subsidiary.
We used our internal engineers for 2004 to provide annual year-end estimates of our future net recoverable oil, natural gas and NGL reserves. The estimated proved net recoverable reserves we show below include only those quantities that we expect to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves that we may recover through existing wells. Proved Undeveloped Reserves include those reserves that we may recover from new wells on undrilled acreage or from existing wells on which we must make a relatively major expenditure for recompletion or secondary recovery operations.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of our oil and natural gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.
Estimated Quantities of Proved Reserves
Estimated Quantities of Proved Developed Reserves
(1) Mcfe-One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Standardized measure of discounted future net cash flows-discontinued operations
We have summarized the Standardized Measure related to Addison’s proved oil, natural gas, and NGL reserves. We have based the following summary on a valuation of Proved Reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to Proved Reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, you should not view the information presented below as an estimate of the fair value of our oil and natural gas properties, nor should you consider the information indicative of any trends.
Standardized Measure of Discounted Future Net Cash Flows
Near month NYMEX futures prices at December 31, 2004 used in the above table was $43.45 per Bbl or oil and $6.15 per Mmbtu of natural gas, adjusted for historical differentials.
Changes in standardized measure-discontinued operations
The following are the principal sources of change in the Standardized Measure:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures
We maintain “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer (CEO), Chief Financial Officer (CFO) and Chief Accounting Officer (CAO), as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well conceived and operated, can provide only reasonable assurance of achieving the desired control objectives and we necessarily are required to apply our judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures.
Our management evaluated, under the supervision and with the participation of our CEO, CFO and CAO, the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2006 and concluded our controls were effective.
Prior to September 30, 2006, our management had concluded that our disclosure controls and procedures were not effective due to a material weakness relating to accounting for income taxes. We believe we have taken the necessary steps to remediate the material weakness described below. Before concluding that the material weakness was remediated, management implemented and evaluated its new controls and procedures for income tax provisions and determined that these procedures were operating effectively for two consecutive quarters, an amount of time deemed sufficient to conclude that the material weakness no longer existed.
Material weakness in internal control over financial reporting
A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.
Prior to September 30, 2006, our management had concluded that we did not maintain effective controls over the preparation and review of the quarterly and annual tax provision and the related financial statement presentation and disclosure of income tax matters. Specifically, our controls were not adequate to ensure the completeness and accuracy of the tax provision and the deferred tax balances, including the timing and classification of recording the tax impact of an extraordinary dividend. This control deficiency resulted in the restatement of our consolidated financial statements for the quarters ended June 30, 2005 and September 30, 2005 and audit adjustments to the consolidated financial statements for the years ended December 31, 2004 and 2005, affecting income tax expense and the deferred tax liability accounts. We undertook numerous remedial actions, as described below, to enhance controls.
Remediation of material weakness
During 2005 and 2006, the following remedial activities were undertaken to strengthen internal controls to address the material weakness described above:
· we added additional staff to our tax department, as well as a new tax director.
· we changed the process in calculating our quarterly and annual tax provisions and related deferred taxes that streamline and simplify the process, thereby increasing the effectiveness of our tax calculation process.
· we added staff to our financial reporting function with technical expertise to strengthen our deferred tax calculation and reviews.
· we implemented more stringent reviews of the quarterly tax provision.
We believe the aforementioned steps have resolved the open matters related to the material weakness described above for a period of time sufficient to conclude that our controls are now effective.
Changes in internal control over financial reporting
There have been no changes during the quarter ended December 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
The acquisition of Winchester on October 2, 2006 has significantly increased the breadth of our operating and control environment. Our pending acquisitions from Anadarko will significantly increase the number of properties we operate and assets that we manage. Management believes its controls are adequate to effectively integrate the Winchester operations into its existing control environment.
At the end of 2007, Section 404 of the Sarbanes-Oxley Act will require our management to provide an assessment of the effectiveness of our internal control over financial reporting, and our independent registered public accountants will be required to audit management’s assessment. We are in the process of performing the system and process documentation, evaluation and testing required for management to make this assessment and for its independent registered public accountants to provide their attestation report. We have not completed this process or its assessment, and this process will require significant amounts of management time and resources. In the course of evaluation and testing, management may identify deficiencies that will need to be addressed and remediated.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLER MATTERS
The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Securities Exchange Act of 1934 not later than 120 days after the end of the fiscal year covered by this Form 10-K.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
EXHIBIT
NUMBER
Description Of Exhibit
2.1
Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
2.2
First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
3.1
Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.
3.2
Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s current report on Form 8-K, dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.
4.1
Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.
4.2
First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
4.3
Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
4.4
Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K filed on February 21, 2006 and incorporated by reference herein.
EXHIBIT
NUMBER
Description Of Exhibit
4.5
Form of 71¤4% Global Note Due 2011.**
4.6
Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
4.7
Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A Amendment No. 1, dated February 10, 2005 and filed February 16, 2005 and incorporated by reference herein.
4.8
Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-1 (File No. 333- 129935) filed on January 27, 2006 and incorporated by reference herein.
4.9
Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
4.10
First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1
Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.
10.2
First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.3
Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
EXHIBIT
NUMBER
Description Of Exhibit
10.4
Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.5
Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.
10.6
First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
10.7
Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.8
Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.9
Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
10.10
Form of 71¤4% Global Note Due 2011.**
10.11
EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.12
Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.13
Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.14
Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
EXHIBIT
NUMBER
Description Of Exhibit
10.15
Letter Agreement, dated October 3, 2005, between EXCO Resources, Inc. and JPMorgan Chase Bank, N.A., as agent for certain lenders under the Credit Agreement by and among EXCO Holdings II, Inc. (EXCO Holdings Inc. as successor by merger) as Borrower and JPMorgan Chase Bank, N.A., as Administrative Agent for itself and the Lenders defined therein, dated October 3, 2005, as filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.16
Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.17
First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.18
Agreement and Plan of Merger between EXCO Holdings Inc. and EXCO Resources, Inc., dated February 9, 2006, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 8, 2006 and filed February 14, 2006 and incorporated by reference herein.
10.19
Credit Agreement for Senior Secured Revolving Credit Facility, dated as of September 27, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.20
First Amendment to Revolving Credit Agreement, dated as of December 15, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined herein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.21
Second Amendment to Revolving Credit Agreement, dated as of February 6, 2006, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
EXHIBIT
NUMBER
Description Of Exhibit
10.22
Subsidiary Guaranty, dated February 14, 2006, among TXOK Acquisition, Inc., TXOK Energy Resources Company, TXOK Energy Holdings, L.L.C., TXOK Texas Energy Holdings, LLC and TXOK Texas Energy Resources, L.P., as Subsidiary Guarantors, in favor of JPMorgan Chase Bank, NA, as agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.23
Amended and Restated Credit Agreement, dated as of March 17, 2006, among EXCO Resource, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Manager, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 17, 2006 and filed on March 23, 2006 and incorporated by reference herein.
10.24
EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***
10.25
Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.26
Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.27
Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***
10.28
Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
10.29
First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.30
Payment Performance Guaranty, dated July 22, 2006, by and between Progress Fuels Corporation and EXCO Resources, Inc., filed as an exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 24, 2006 and incorporated by reference herein.
EXHIBIT
NUMBER
Description Of Exhibit
10.31
Senior Revolving Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.32
Senior Term Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.33
First Amendment to Credit Agreement, dated October 2, 2006, among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.34
Amended and Restated Equity Contribution Agreement, dated October 4, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.35
Senior Term Credit Agreement, dated October 2, 2006, as amended and restated as of October 13, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.36
Second Amended and Restated Equity Contribution Agreement, dated October 13, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.37
Second Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
10.38
Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 15, 2007 and filed on January 16, 2007 and incorporated by reference herein.
EXHIBIT
NUMBER
Description Of Exhibit
10.39
Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.40
Guaranty dated December 22, 2006 by EXCO Resources, Inc. in favor of Anadarko Petroleum Corporation and Anadarko Gathering Company, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.41
Purchase and Sale Agreement by and among EXCO Resources, Inc., Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated February 1, 2007, filed herewith.
10.42
First Amendment to Senior Revolving Credit Agreement effective as of December 31, 2006 among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated March 8, 2007 and filed march 13, 2007 and incorporated by reference herein.
14.1
Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.2
Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.3
Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
21.1
Subsidiaries of the registrant, filed herewith.
23.1
Consent of KPMG LLP, filed herewith.
23.2
Consent of PricewaterhouseCoopers LLP, filed herewith.
23.3
Consent of Lee Keeling and Associates, Inc., filed herewith.
31.1
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
EXHIBIT
NUMBER
Description Of Exhibit
31.3
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting Officer of EXCO Resources, Inc., filed herewith.
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer of EXCO Resources, Inc., filed herewith.
99.1
Audit Committee Charter, filed as an Exhibit to EXCO’s Form 8-K filed November 24, 2004 and incorporated by reference herein.
* Filed as an Exhibit to EXCO’s Form S-4 filed March 25, 2004 and incorporated by reference herein.
** Filed as an Exhibit to EXCO’s Pre-effective Amendment No. 1 to the Form S-4 filed April 20, 2004 and incorporated by reference herein.
*** These exhibits are management contracts.
SIGNATURE PAGE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Date: March 19,
/s/ DOUGLAS H. MILLER
Douglas H. Miller
Director, Chairman and Chief Executive Officer
/s/ STEPHEN F. SMITH
Stephen F. Smith
Director, Vice Chairman and President
/s/ J. DOUGLAS RAMSEY
J. Douglas Ramsey
Vice President, Chief Financial Officer and Treasurer
/s/ MARK E. WILSON
Mark E. Wilson
Vice President, Chief Accounting Officer and Controller
/s/ JEFFREY D. BENJAMIN
Jeffrey D. Benjamin
Director
/s/ EARL E. ELLIS
Earl E. Ellis
Director
/s/ ROBERT H. NIEHAUS
Robert H. Niehaus
Director
/s/ BOONE PICKENS
Boone Pickens
Director
/s/ ROBERT L. STILLWELL
Robert L. Stillwell
Director
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED
PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE
NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
Not applicable.
Index to Exhibits
4.8
Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-1 (File No. 333- 129935) filed on January 27, 2006 and incorporated by reference herein.
4.9
Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
4.10
First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1
Share and Debt Purchase Agreement, dated effective January 12, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2005 and filed January 21, 2005 and incorporated by reference herein.
10.2
First Amending Agreement to the Share and Debt Purchase Agreement, dated effective February 8, 2005, among 1143928 Alberta Ltd., EXCO Resources, Inc. and Taurus Acquisition, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.3
Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., Wilmington Trust Company and JPMorgan Securities Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.4
Securities Account Control Agreement, dated as of February 10, 2005, among EXCO Resources, Inc., Wilmington Trust Company and J.P. Morgan Securities Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated January 17, 2005 and filed February 16, 2005 and incorporated by reference herein.
10.5
Indenture among EXCO Resources, Inc., the Subsidiary Guarantors and Wilmington Trust Company, as Trustee, dated as of January 20, 2004, filed as exhibit (b)(2) to Amendment No. 4 to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on January 21, 2004 and incorporated by reference herein.
10.6
First Supplemental Indenture by and among EXCO Resources, Inc., North Coast Energy, Inc., North Coast Energy Eastern, Inc. and Wilmington Trust Company, as Trustee, dated as of January 27, 2004.*
10.7
Second Supplemental Indenture by and among EXCO Resources, Inc., Pinestone Resources, LLC and Wilmington Trust Company, as Trustee, dated as of December 21, 2004, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein.
10.8
Third Supplemental Indenture by and among EXCO Resources, Inc., TXOK Acquisition, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.9
Fourth Supplemental Indenture, dated as of May 4, 2006, by and among EXCO Resources, Inc., Power Gas Marketing & Transmission, Inc. and Wilmington Trust Company, as Trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 4, 2006 and filed on May 10, 2006 and incorporated by reference herein.
10.10
Form of 71¤4% Global Note Due 2011.**
10.11
EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.12
Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.13
Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.14
Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 30, 2005 and filed on October 7, 2005 and incorporated by reference herein.***
10.15
Letter Agreement, dated October 3, 2005, between EXCO Resources, Inc. and JPMorgan Chase Bank, N.A., as agent for certain lenders under the Credit Agreement by and among EXCO Holdings II, Inc. (EXCO Holdings Inc. as successor by merger) as Borrower and JPMorgan Chase Bank, N.A., as Administrative Agent for itself and the Lenders defined therein, dated October 3, 2005, as filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.16
Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein.
10.17
First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.18
Agreement and Plan of Merger between EXCO Holdings Inc. and EXCO Resources, Inc., dated February 9, 2006, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 8, 2006 and filed February 14, 2006 and incorporated by reference herein.
10.19
Credit Agreement for Senior Secured Revolving Credit Facility, dated as of September 27, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Arranger, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.20
First Amendment to Revolving Credit Agreement, dated as of December 15, 2005, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined herein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.21
Second Amendment to Revolving Credit Agreement, dated as of February 6, 2006, by and among TXOK Acquisition, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders (as defined therein), and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.22
Subsidiary Guaranty, dated February 14, 2006, among TXOK Acquisition, Inc., TXOK Energy Resources Company, TXOK Energy Holdings, L.L.C., TXOK Texas Energy Holdings, LLC and TXOK Texas Energy Resources, L.P., as Subsidiary Guarantors, in favor of JPMorgan Chase Bank, NA, as agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 1, dated February 8, 2006 and filed on February 21, 2006 and incorporated by reference herein.
10.23
Amended and Restated Credit Agreement, dated as of March 17, 2006, among EXCO Resource, Inc. as Borrower, certain of its subsidiaries, as Guarantors, the Lenders defined therein, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Bookrunner and Lead Manager, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 17, 2006 and filed on March 23, 2006 and incorporated by reference herein.
10.24
EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***
10.25
Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.26
Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed herewith.***
10.27
Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.***
10.28
Merger Agreement, dated July 22, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 25, 2006 and incorporated by reference herein.
10.29
First Amendment to Agreement and Plan of Merger, dated as of September 28, 2006, by and among Winchester Acquisition, LLC, Progress Fuels Corporation, Winchester Energy Company, Ltd., and WGC Holdco, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.30
Payment Performance Guaranty, dated July 22, 2006, by and between Progress Fuels Corporation and EXCO Resources, Inc., filed as an exhibit to EXCO’s Current Report on Form 8-K, dated July 22, 2006 and filed on July 24, 2006 and incorporated by reference herein.
10.31
Senior Revolving Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.32
Senior Term Credit Agreement, dated October 2, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.33
First Amendment to Credit Agreement, dated October 2, 2006, among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.34
Amended and Restated Equity Contribution Agreement, dated October 4, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 2, dated July 22, 2006 and filed on October 4, 2006 and incorporated by reference herein.
10.35
Senior Term Credit Agreement, dated October 2, 2006, as amended and restated as of October 13, 2006, among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.36
Second Amended and Restated Equity Contribution Agreement, dated October 13, 2006, among EXCO Resources, Inc., EXCO Partners Operating Partnership, LP, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K/A-Amendment No. 3, dated July 22, 2006 and filed on October 19, 2006 and incorporated by reference herein.
10.37
Second Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
10.38
Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 15, 2007 and filed on January 16, 2007 and incorporated by reference herein.
10.39
Purchase and Sale Agreement by and among Anadarko Petroleum Corporation and Anadarko Gathering Company, as Seller, and Vernon Holdings, LLC, as Purchaser, dated December 22, 2006, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.40
Guaranty dated December 22, 2006 by EXCO Resources, Inc. in favor of Anadarko Petroleum Corporation and Anadarko Gathering Company, filed as an Exhibit to EXCO’s Pre-Effective Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-139568) filed on January 16, 2007 and incorporated by reference herein.
10.41
Purchase and Sale Agreement by and among EXCO Resources, Inc., Anadarko Petroleum Corporation, Anadarko E&P Company, LP, Howell Petroleum Corporation, and Kerr-McGee Oil & Gas Onshore LP, dated February 1, 2007, filed herewith.
10.42
First Amendment to Credit Agreement effective as of December 31, 2006 among EXCO Partners Operating Partnership, LP, certain of its subsidiaries, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated March 8, 2007 and filed March 13, 2007 and incorporated by reference herein.
14.1
Code of Ethics for the Chief Executive Officer and Senior Financial Officers, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.2
Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein.
14.3
Amendment No. 1 to EXCO Resources, Inc. Code of Business Conduct and Ethics for Directors, Officers and Employees, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2006 and filed on November 9, 2006 and incorporated by reference herein.
21.1
Subsidiaries of the registrant, filed herewith.
23.1
Consent of KPMG LLP, filed herewith.
23.2
Consent of PricewaterhouseCoopers LLP, filed herewith.
23.3
Consent of Lee Keeling and Associates, Inc., filed herewith.
31.1
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
31.3
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Accounting Officer of EXCO Resources, Inc., filed herewith.
32.1
Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer of EXCO Resources, Inc., filed herewith.
99.1
Audit Committee Charter, filed as an Exhibit to EXCO’s Form 8-K filed November 24, 2004 and incorporated by reference herein.
* Filed as an Exhibit to EXCO’s Form S-4 filed March 25, 2004 and incorporated by reference herein.
** Filed as an Exhibit to EXCO’s Pre-effective Amendment No. 1 to the Form S-4 filed April 20, 2004 and incorporated by reference herein.
*** These exhibits are management contracts.