UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 2)
| ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 2005 | |
OR | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period from to | |
Commission File Number 0-9204
EXCO RESOURCES, INC.
(Exact name of Registrant as specified in its charter)
| Texas (State or other jurisdiction of incorporation or organization) | 74-1492779 (I.R.S. Employer Identification No.) | |
12377 Merit Drive, Suite 1700, LB 82 Dallas, Texas (Address of principal executive offices) | 75251 (Zip Code) |
Registrant's telephone number, including area code:(214) 368-2084
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |
|---|---|---|
| Common Stock, $0.001 par value | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES o NO ý
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES o NO ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES o NO ý
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment of this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o Accelerated filer o Non-accelerated filer ý
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES o NO ý
As of March 15, 2006, the registrant had 104,004,089 outstanding shares of common stock, par value $.001 per share, which is its only class of stock. As of the last business day of the registrant's most recently completed second fiscal quarter, the registrant's common stock was not traded on any public securities market and, therefore, the aggregate market value of its common equity held by non-affiliates cannot be determined as of such date.
DOCUMENTS INCORPORATED BY REFERENCE
None
Explanatory Note—Restatement of supplemental information related to oil and natural gas producing activities (unaudited)
EXCO Resources, Inc. discovered an error in unaudited data contained in Note 20.—"Supplemental information relating to oil and natural gas producing activities—continuing operations (unaudited)" of the Notes to the Consolidated Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2005 (the Original 10-K). As a result, we are restating our previously reported supplemental oil and gas disclosures for the years ended December 31, 2003, 2004 and 2005 prepared pursuant to Statement of Financial Accounting Standards No. 69 ("FAS 69"). The amendment is due to our historical use of near month NYMEX futures prices for calculating oil and natural gas reserves and the standardized measure instead of using the physical spot price at the end of each reporting period. The amended amounts of the standardized measure, quantities and PV-10 are located in the following sections of this Amendment No. 2 to the Original 10-K:
The supplemental information relating to oil and natural gas properties is located in an unaudited footnote to our audited consolidated financial statements. This footnote is prepared in accordance with the guidelines of FAS 69. Historically, we used the near month NYMEX futures oil and natural gas prices. The Company has determined that the use of the near month NYMEX price is not correct and is amending the price to physical spot prices. Typically, the near month NYMEX futures price and physical spot price for both oil and natural gas are closely aligned as shown in the table below. However, as shown below, the differential for natural gas was much larger at December 31, 2005 exacerbated by a temporary increase in the geographic market differences which had a negative impact on the calculation of the standardized measure.
Prices for each of the years ended December 31, 2003, 2004 and 2005 were as follows:
| | NYMEX | WTI Cushing Spot | % difference | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Oil prices: | ||||||||||
| December 31, 2003 | $ | 32.52 | $ | 32.47 | -0.15 | % | ||||
| December 31, 2004 | $ | 43.45 | $ | 43.33 | -0.28 | % | ||||
| December 31, 2005 | $ | 61.04 | $ | 61.03 | -0.02 | % | ||||
| | NYMEX | Henry Hub Spot | % difference | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Natural gas prices: | ||||||||||
| December 31, 2003 | $ | 6.19 | $ | 5.97 | -3.55 | % | ||||
| December 31, 2004 | $ | 6.15 | $ | 6.18 | 0.49 | % | ||||
| December 31, 2005 | $ | 11.23 | $ | 10.08 | -10.24 | % | ||||
This amendment to the supplemental oil and natural gas information had no impact on our consolidated balance sheets, consolidated statements of operations, consolidated statements of changes in stockholders' equity or consolidated statements of cash flows for the years ended December 31, 2003, 2004 and 2005. The Company evaluated impacts of revised computations of depreciation, depletion and amortization reported in the Original 10-K and determined that the impacts were not material due to the changes to the estimated total proved reserves being impacted by less than 1% for each of the years affected by this Amendment No. 2. The only restated amounts in Item 8—"Financial Statements and Supplementary Data" are to the standardized measure and quantities in Note 20 and in Item 1.—"Business" to the standardized measure, quantities and PV-10 of this Amendment No. 2. A
summary of the changes to estimated total proved reserves, estimated quantities of proved developed reserves and the standardized measure for the periods affected is presented in the following tables:
| | As reported on Original 10-K (NYMEX futures) | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (dollars in thousands) | Year ended December 31, 2003 | Year ended December 31, 2004 | Year ended December 31, 2005 | ||||||
| Estimated total proved reserves (Mmcfe) | 223,964 | 405,775 | 444,614 | ||||||
| Estimated quantities of proved developed reserves (Mmcfe) | 174,741 | 355,442 | 357,530 | ||||||
| Standardized measure of discounted future net cash flows | $ | 234,085 | $ | 473,390 | $ | 930,327 | |||
| | As restated using spot pricing | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (dollars in thousands) | Year ended December 31, 2003 | Year ended December 31, 2004 | Year ended December 31, 2005 | ||||||
| Estimated total proved reserves (Mmcfe) | 223,400 | 406,068 | 441,962 | ||||||
| Estimated quantities of proved developed reserves (Mmcfe) | 174,195 | 355,678 | 354,878 | ||||||
| Standardized measure of discounted future net cash flows | $ | 226,006 | $ | 473,737 | $ | 823,299 | |||
| | Percentage changes | ||||||
|---|---|---|---|---|---|---|---|
| | Year ended December 31, 2003 | Year ended December 31, 2004 | Year ended December 31, 2005 | ||||
| Estimated total proved reserves (Mmcfe) | -0.3 | % | 0.1 | % | -0.6 | % | |
| Estimated quantities of proved developed reserves (Mmcfe) | -0.3 | % | 0.1 | % | -0.7 | % | |
| Standardized measure of discounted future net cash flows | -3.5 | % | 0.1 | % | -11.5 | % | |
We are also amending Part IV. Item 15—Exhibits and Financial Statement Schedules to update the certifications of the Chief Executive Offer, Chief Financial Officer and Chief Accounting Officer.
Other than as specified above, this amendment does not modify or affect the financial statements or the notes thereto in the Original 10-K. This amendment does not reflect events occurring after the filing of the Original 10-K nor modify or update the disclosures contained therein in any way other than as required to reflect the amendments as described above. In accordance with Rule 12b-15 promulgated under the Securities Exchange Act of 1934, the complete text of each affected item, as amended, is included herein. Sections not affected by this amendment have not been repeated.
General
EXCO Resources, Inc., 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 Appalachia, East Texas, Mid-Continent, Permian and the Rockies. As of December 31, 2005, our Proved Reserves were approximately 442.0 Bcfe, of which 91% were natural gas and 80% were Proved Developed Reserves. As of December 31, 2005, the related PV-10 of our Proved Reserves was $1.3 billion, and the Standardized Measure of our Proved Reserves was $823.3 million. For the twelve months ended December 31, 2005, we produced 23.6 Bcfe of oil and natural gas, which translates to a Reserve Life of approximately 18.8 years. For the twelve month period ended December 31, 2005, we generated $202.9 million of oil and natural gas revenues. On February 14, 2006, as more fully described below, we acquired TXOK Acquisition, Inc., or TXOK. Our pro forma Proved Reserves as of December 31, 2005, including those of TXOK are 663.4 Bcfe with a PV-10 of Proved Reserves of $1.9 billion and a Standardized Measure of Proved Reserves of $1.4 billion.
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 was acquired by and into which EXCO Holdings II, Inc., or Holdings II, merged in October 2005. On February 14, 2006, EXCO Holdings merged with and into EXCO Resources.
Financial information presented in this annual report includes three separate periods of accounting. Information related to the period beginning January 1, 2003 to July 28, 2003 is referred to as public predecessor and represents the accounting period prior to our going private transaction. For more information about our going private transaction, see "—Significant transactions during 2003 and 2004." The period beginning July 29, 2003 to December 31, 2003, the year ended December 31, 2004 and the period beginning January 1, 2005 to October 2, 2005 is referred to as the private predecessor. The private predecessor period represents the accounting period following the going private transaction up to the Equity Buyout. For more information about the Equity Buyout, see "—Significant transactions during 2005 and 2006." The period beginning October 3, 2005 and ending December 31, 2005 is referred to as successor.
All reserve and other non-financial operating data described as being presented on a pro forma basis excludes data relating to our former Canadian subsidiary, Addison Energy Inc., or Addison, that we sold in February 2005, but includes data relating to ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C., collectively ONEOK Energy, acquired in September 2005 by TXOK, which became our wholly-owned subsidiary on February 14, 2006. For a description of these and other significant events involving EXCO, see "—Significant transactions during 2005 and 2006." We have provided definitions for some of the oil and natural gas industry terms used in this annual report in the "Glossary of selected oil and natural gas terms" beginning on page 24.
Our business strategy
We plan to achieve reserve, production, and cash flow growth by executing our strategy as highlighted below:
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
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January 1, 2003 to December 31, 2005, we have drilled 226 wells and completed 217 wells resulting in a 96% drilling success rate. We have identified over 2,000 drilling locations and exploitation projects across our properties on a pro forma basis.
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 January 2004 acquisition of North Coast in the Appalachian Basin and the acquisition of TXOK in the East Texas and the Mid-Continent areas are examples of this strategy.
We regularly 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 $443.3 million in February 2005.
We employ the use of debt along with a comprehensive commodity price risk management 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.
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 663.4 Bcfe on a pro forma basis, and our average daily production increased from less than 1 Mmcfe per day in 1997 to 117.1 Mmcfe per day in December 2005, on a pro forma basis. Importantly, as of March 15, 2006, our management team and employees (excluding our outside directors) own approximately 12.4% of our fully-diluted capital stock, which aligns their objectives with those of our shareholders.
We own and plan to maintain a geographically diversified reserve base. Our principal operations are in the Appalachia, East Texas, Mid-Continent, Permian, and Rockies areas. Our properties are generally characterized by:
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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, 2005, we were the operator of wells which represented 88% of our pro forma Proved Reserves.
Significant transactions during 2003 and 2004
��Going private transaction. On July 29, 2003, EXCO Resources consummated a going private transaction pursuant to which it became a wholly-owned subsidiary of EXCO Holdings. Prior to July 29, 2003, EXCO Resources had registered equity securities that were publicly traded on the NASDAQ National Market. Prior to the going private transaction, EXCO Holdings had no assets, liabilities or operations other than those nominal to its formation. Accordingly, EXCO Resources was deemed the predecessor entity to EXCO Holdings through July 28, 2003.
North Coast acquisition. On January 27, 2004, we acquired North Coast Energy, Inc. (North Coast) for a purchase price of $225.1 million, including the assumption of $57.1 million of North Coast's outstanding indebtedness. As a result, North Coast became one of our wholly-owned subsidiaries and continues to be an energy company focused on the acquisition, exploitation, development and production of natural gas reserves in the Appalachian Basin. The North Coast acquisition established a new core operating area for us in the Appalachian Basin, which positioned us to benefit from the attractive qualities of the basin and to capitalize on consolidation opportunities in the area.
On January 20, 2004, we issued $350.0 million principal amount of our 71/4% senior notes, or senior notes, due January 15, 2011 pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended, or 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 103.25% 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 our 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.
Significant transactions during 2005 and 2006
Sale of Addison. On February 10, 2005, we sold Addison, our former wholly-owned subsidiary through which all of our Canadian operations were conducted, for an aggregate purchase price of Cdn. $551.3 million ($443.3 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
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($3.0 million). See "Note 3. Sale of Addison Energy Inc." of the notes to the consolidated financial statements for additional information.
TXOK acquisition. On September 16, 2005, Holdings II formed TXOK for the purpose of acquiring 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 $642.9 million, or $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.
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 $163.4 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 has Proved Reserves, estimated as of December 31, 2005, of approximately 221.4 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 "Item 13. Certain relationships and related transactions—TXOK acquisition."
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. For more information about the Equity Buyout, see "Item 13. Certain relationships and related transactions—Equity Buyout."
Following completion of the Equity Buyout, Stephen F. Smith became our Vice Chairman, President and Secretary and Harold L. Hickey became our Vice President and Chief Operating Officer. See "Item 10. Directors and executive officers of the registrant."
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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 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.
Initial public offering. On February 14, 2006, EXCO Resources completed its initial public offering, or 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:
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. 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.
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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, 2005 on a pro forma basis:
| Areas | Total proved reserves (Bcfe)(1) | PV-10 (in millions) (1)(2) | Average December daily net production (Mmcfe/d) | Reserve life (years)(8) | ||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Appalachia | 279.4 | $ | 848.5 | 39.0 | 19.6 | |||||
| East Texas(3) | 160.5 | 420.6 | 35.4 | 12.4 | ||||||
| Mid-Continent(3) | 114.1 | 377.2 | 27.0 | 11.6 | ||||||
| Permian | 57.4 | 133.2 | 7.5 | 21.0 | ||||||
| Rockies | 46.8 | 114.4 | 6.7 | 19.1 | ||||||
| Other | 5.2 | 13.4 | 1.5 | 9.1 | ||||||
| Total | 663.4 | $ | 1,907.3 | 117.1 | 15.5 | |||||
| Areas | Identified drilling locations(4) | Identified exploitation projects(5) | Total gross acreage | Total net acreage(6) | |||||
|---|---|---|---|---|---|---|---|---|---|
| Appalachia | 1,089 | 123 | 664,450 | 626,628 | |||||
| East Texas(7) | 260 | 169 | 56,509 | 31,841 | |||||
| Mid-Continent(7) | 187 | 188 | 179,065 | 105,150 | |||||
| Permian | 80 | 32 | 47,755 | 27,395 | |||||
| Rockies | 53 | 65 | 56,440 | 29,978 | |||||
| Other | 5 | 8 | 7,543 | 4,055 | |||||
| Total | 1,674 | 585 | 1,011,762 | 825,047 | |||||
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The following table provides a reconciliation of our PV-10 to our Standardized Measure as of December 31, 2005 on a pro forma basis:
| (in millions) | | |||
|---|---|---|---|---|
| PV-10 | $ | 1,907.3 | ||
| Future income taxes | (1,331.3 | ) | ||
| Discount of future income taxes at 10% per annum | 780.9 | |||
| Standardized Measure | $ | 1,356.9 | ||
| Areas | Total Proved Reserves (Bcfe) | PV-10 (in millions) | Average December daily net production (Mmcfe/d) | Reserve Life (years)(8) | ||||||
|---|---|---|---|---|---|---|---|---|---|---|
| East Texas | 125.8 | $ | 328.0 | 26.2 | 13.2 | |||||
| Mid-Continent | 95.6 | 330.7 | 25.0 | 10.5 | ||||||
| Total | 221.4 | $ | 658.7 | 51.2 | 11.8 | |||||
| Areas | Identified drilling locations | Identified exploitation projects | Total gross acreage | Total net acreage | |||||
|---|---|---|---|---|---|---|---|---|---|
| East Texas | 173 | 166 | 48,292 | 25,230 | |||||
| Mid-Continent | 178 | 160 | 135,204 | 79,766 | |||||
| Total | 351 | 326 | 183,496 | 104,996 | |||||
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Our development and exploitation project areas
Appalachia
The Appalachian Basin includes portions of the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee, and covers an area of over 185,000 square miles. It is the most mature oil and natural gas producing region in the United States, first establishing oil production in 1859. The Appalachian Basin is strategically located near high energy demand areas with limited supply. As a result, the natural gas from the area typically commands a higher well head price relative to other North American areas.
Although the Appalachian Basin has sedimentary formations indicating the potential for deposits of oil and natural gas reserves up to depths of 30,000 feet or more, most production in this area has been derived from relatively shallow, low porosity and permeability sand and shale formations at depths of 1,000 to 6,000 feet. Operations in the area are generally characterized by long reserve lives, high drilling success rates and a large number of low productivity wells in these shallow formations. In the Appalachian Basin, there are more than 200,000 producing wells and 3,100 operators, with most being relatively small, private enterprises. Our operations in the area primarily include development drilling on our existing acreage, as well as the acquisition of properties with established production and growth opportunities. We believe that the number of wells and operators presents a significant consolidation opportunity.
Central Pennsylvania Area
The Central Pennsylvania Area stretches across six counties in central Pennsylvania. At December 31, 2005, we had Proved Reserves of 74.6 Bcfe and 852 gross producing wells. We operate 100% of our Proved Reserves in this area. Production is primarily from the Upper Devonian, Venango, Bradford, and Elk formations at depths from 1,800 to 4,600 feet. We currently plan to drill 84 wells during 2006.
Ravenswood Area
The Ravenswood Area is located in the western portion of West Virginia. At December 31, 2005, we had Proved Reserves of 46.7 Bcfe and 587 gross producing wells. We operate 98% of our Proved Reserves in this area. Production in the Ravenswood area is primarily from the Mississippian and Devonian formations at depths of 2,500 to 4,400 feet. We currently plan to drill eight wells during 2006.
Maben Area
The Maben Area is located in southwest West Virginia. At December 31, 2005, we had Proved Reserves of 34.5 Bcfe and 316 gross producing wells. We operate 100% of our Proved Reserves in this area. In Maben, we produce from the Mississippian and Devonian formations at depths ranging from 1,500 to 5,500 feet. Our drilling activity targets seven separate shallow formations, with a typical well completed in two or more horizons. We currently plan to drill six wells during 2006.
Adamsville Area
The Adamsville Area is located in south central Ohio. At December 31, 2005, we had Proved Reserves of 11.6 Bcfe and 342 gross producing wells. We operate 99% of our Proved Reserves in this area. Adamsville produces from the Clinton reservoir and the Knox series at depths from 3,000 to 6,300 feet. We currently plan to drill five wells during 2006.
Jamestown Area
The Jamestown Area is located in western Pennsylvania. At December 31, 2005, we had Proved Reserves of 17.3 Bcfe. We operate 123 gross producing wells which represent 100% of our Proved Reserves in the area. Production is primarily from the Medina Sandstone formation at depths of 4,500 to 5,100 feet. We currently plan to drill 31 wells during 2006.
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The East Texas area is a part of the Cotton Valley Sand trend, which covers parts of the East Texas Basin and the Northern Louisiana Salt Basin. The TXOK acquisition significantly enhanced our position in this area. We are targeting tight sand reservoirs along the Cotton Valley Sand trend at depths of 6,500 to 12,000 feet. Operations in the area are generally characterized by long-lived reserves, high drilling success rates and wells with relatively high initial production rates. Due to the tight nature of the reservoirs, development programs in the area are mostly focused on infill development drilling. Many areas have been down spaced to 80-acres per well, with some areas having economically established 40 acre spacing.
Cotton Valley Area
Within our Cotton Valley Area, we are active in Rusk, Upshur and Gregg Counties in Texas primarily across four fields—Oak Hill, Minden, Glenwood and White Oak. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 161.4 Bcfe and 467 gross producing wells. We operate 97% of our pro forma Proved Reserves in this area. We are focused on developing the Lower Cotton Valley (Taylor) and Upper Cotton Valley sands at depths of 10,400 to 11,000 feet, the Pettit Lime at depths of 7,000 to 8,500 feet and Travis Peak Sands at depths of 7,800 to 9,000 feet. Our natural gas is gathered through our own gathering lines in these fields. On a pro forma basis we currently plan to drill 44 wells during 2006.
Mid-Continent
Our Mid-Continent area includes parts of Oklahoma, southwestern Kansas and the Texas Panhandle. The major properties in the Mid-Continent area were acquired in the TXOK acquisition and are located in the Anadarko Shelf and Anadarko Basin of Oklahoma. The Mid-Continent area is characterized by stratigraphic plays with multiple, stacked pay zones and more complex geology than in our other operating areas. Similar to our other operating areas, the Mid-Continent area contains a number of fields with long production histories. We also recognize the potential for additional attractive acquisition opportunities, as this area contains a number of smaller operators seeking liquidity opportunities and some larger companies seeking to divest non-core assets.
Mocane-Laverne Field
Our Mocane-Laverne Field, which was acquired in the TXOK acquisition, is located in Beaver, Harper and Ellis Counties of Oklahoma. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 46.3 Bcfe and we had 479 gross producing wells. We operate 77% of our pro forma Proved Reserves. At Mocane-Laverne, we are targeting eight productive formations at depths from 2,500 to 9,000 feet. On a pro forma basis we currently plan to drill 24 wells during 2006.
Cement Field
Our Cement Field, which was acquired in the TXOK acquisition, is located in Caddo and Grady Counties of Oklahoma. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 25.5 Bcfe and we had 131 gross producing wells, all operated by others. Production in the Cement field is primarily from multi-pay Pennsylvanian formations at depths of 4,500 to 18,000 feet. On a pro forma basis we currently plan to participate in the drilling of 17 wells during 2006.
Chitwood Field
Our Chitwood Field, which was acquired in the TXOK acquisition, is near our Cement Field in Grady County, Oklahoma. At December 31, 2005 on a pro forma basis, we had Proved Reserves of 24.7 Bcfe and we had 50 gross producing wells. We operate 65% of our pro forma Proved Reserves. At
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Chitwood, we are targeting four productive formations at depths of 15,000 to 17,600 feet. On a pro forma basis we currently plan to drill seven wells during 2006.
Permian
The Permian Basin is located in West Texas and the adjoining area of southeastern New Mexico. Though the Permian Basin is better known as a mature oil focused basin exploited with waterflood and other enhanced oil recovery techniques, our activities are focused on conventional gas properties. With the use of 3-D seismic, we are targeting prolific natural gas reservoirs with potential for multi-pay horizons. The properties are characterized by long reserve lives and low operating costs.
Vinegarone Field
Our Vinegarone Field is located in Val Verde County, Texas. At December 31, 2005, we had Proved Reserves of 29.6 Bcfe and 26 gross producing wells. We operate 99% of the Proved Reserves in the field. Production in the Vinegarone field is primarily from the Pennsylvanian Strawn formation at depths of 10,000 to 10,500 feet. We currently plan to drill three wells during 2006.
Gomez Field
Our Gomez Field is located in Pecos County, Texas. At December 31, 2005, we had Proved Reserves of 10.5 Bcfe and 12 gross producing wells, all operated by others. At Gomez, we are primarily targeting the Ellenberger, Devonian, Wolfcamp and Atoka formations at depths of from 15,000 to 22,000 feet. We currently plan to participate in the drilling of three wells during 2006.
Rockies
The Rockies is a well known oil and natural gas province which encompasses several oil and natural gas basins. Our activities are currently focused on the Wattenberg Field of the Denver-Julesberg Basin of northeastern Colorado. Though the Wattenberg Field has been under extensive development since the early 1970s, improvements in fracturing technology have enhanced recoveries from these tight sand reservoirs and supported continued active development of the field. Operations in the area are generally characterized by high drilling success rates and low cost wells with significant potential for refracs.
Wattenberg Field
The Wattenberg Field encompasses more than 1,000 square miles, between 20 and 55 miles northeast of Denver, Colorado. At December 31, 2005, we had Proved Reserves of 36.3 Bcfe and 125 gross producing wells. Our activities at Wattenberg are focused on a portion of the field in which the primary productive reservoirs are in the Codell and Niobrara formations and in selected deeper "J" Sand formations. These formations cover large areas of the field and are found at depths of approximately 6,500 to 8,500 feet. We currently plan to drill 10 wells and perform exploitation operations on eight wells during 2006.
Our oil, natural gas and NGL reserves
The following tables summarize historical information regarding Proved Reserves at December 31, 2003, 2004 and 2005 and historical and pro forma information at December 31, 2005 and exclude
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information with respect to Canada as a result of the sale of Addison in February 2005. The historical information was prepared in accordance with the rules and regulations of the SEC.
| | At December 31, | At December 31, 2005(2) | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2004 | EXCO | TXOK | Pro forma | |||||||||||
| Oil (Mmbbls) | ||||||||||||||||
| Developed | 7.8 | 6.0 | 5.5 | 3.0 | 8.5 | |||||||||||
| Undeveloped | 2.7 | 1.2 | 1.3 | 1.1 | 2.4 | |||||||||||
| Total | 10.5 | 7.2 | 6.8 | 4.1 | 10.9 | |||||||||||
| Natural gas (Bcf) | ||||||||||||||||
| Developed | 123.5 | 318.3 | 321.7 | 162.3 | 484.0 | |||||||||||
| Undeveloped | 32.1 | 43.1 | 79.5 | 34.5 | 114.0 | |||||||||||
| Total | 155.6 | 361.4 | 401.2 | 196.8 | 598.0 | |||||||||||
| Natural Gas Liquids (Mmbbls) | ||||||||||||||||
| Developed | 0.7 | 0.2 | — | — | — | |||||||||||
| Undeveloped | 0.1 | — | — | — | — | |||||||||||
| Total | 0.8 | 0.2 | — | — | — | |||||||||||
| Total equivalent reserves (Bcfe) | 223.4 | 406.1 | 442.0 | 221.4 | 663.4 | |||||||||||
| Pre-tax Present Value, discounted at 10% (PV-10) (in millions)(1) | ||||||||||||||||
| Developed | $ | 265.4 | $ | 642.2 | $ | 1,046.7 | $ | 550.8 | $ | 1,597.5 | ||||||
| Undeveloped | 66.5 | 58.2 | 201.9 | 107.9 | 309.8 | |||||||||||
| Total | $ | 331.9 | $ | 700.4 | $ | 1,248.6 | $ | 658.7 | $ | 1,907.3 | ||||||
| Standardized Measure (in millions) | $ | 226.0 | $ | 473.7 | $ | 823.3 | $ | 533.6 | $ | 1,356.9 | ||||||
| | Spot price | |||||
|---|---|---|---|---|---|---|
| Date | Natural gas (per Mmbtu) | Oil (per Bbl) | ||||
| December 31, 2003 | $ | 5.97 | $ | 32.47 | ||
| December 31, 2004 | $ | 6.19 | $ | 43.33 | ||
| December 31, 2005 | $ | 10.08 | $ | 61.03 | ||
We believe that PV-10 before income taxes, while not a financial measure in accordance with generally accepted accounting principles, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The Standardized Measure represents the PV-10 after giving effect to income taxes, and is
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calculated in accordance with SFAS No. 69. The following table provides a reconciliation of our PV-10 to our Standardized Measure:
| | At December 31, | At December 31, 2005 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) | ||||||||||||||||
| 2003 | 2004 | EXCO | TXOK | Pro forma | ||||||||||||
| PV-10 | $ | 331.9 | $ | 700.4 | $ | 1,248.6 | $ | 658.7 | $ | 1,907.3 | ||||||
| Future income taxes | (243.1 | ) | (588.9 | ) | (1,097.6 | ) | (233.7 | ) | (1,331.3 | ) | ||||||
| Discount of future income taxes at 10% per annum | 137.2 | 362.2 | 672.3 | 108.6 | 780.9 | |||||||||||
| Standardized Measure | $ | 226.0 | $ | 473.7 | $ | 823.3 | $ | 533.6 | $ | 1,356.9 | ||||||
The total reserve estimates presented as of December 31, 2003, 2004 and 2005 have been prepared by Lee Keeling and Associates, Inc., an independent petroleum engineering firm in Tulsa, Oklahoma. The estimate of our PV-10 and Standardized Measure is based upon our estimate of future abandonment costs and the report on our Proved Reserves as prepared by Lee Keeling and Associates, Inc. Estimates of oil, natural gas and NGL reserves are projections based on engineering data and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, production and ad valorem taxes and availability of funds. These reports should not be construed as the current market value of our Proved Reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See "Note 20. Supplemental information relating to oil and natural gas producing activities—continuing operations (unaudited)" of the notes to the consolidated financial statements for additional information regarding our oil, natural gas and NGL reserves, and our Standardized Measure.
Our production, prices and expenses
The following tables summarize for the periods indicated, revenues (before cash settlements of derivative financial instruments), net production of oil, natural gas and NGLs sold, average sales price per unit of oil, natural gas and NGLs and costs and expenses associated with the production of oil, natural gas and NGLs. Revenues shown in this table do not reflect the impact of derivatives that were treated as hedges for the 209 day period from January 1, 2003 to July 28, 2003 in order to show revenues on a consistent basis for the three years presented. Oil and natural gas revenues for the 209 day period from January 1, 2003 to July 28, 2003 as shown on the consolidated statements of
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operations have been reduced by $14.5 million for cash settlements paid on hedges. These tables exclude information with respect to Canada as a result of the sale of Addison in February 2005.
| | Public predecessor | Private predecessor | |||||
|---|---|---|---|---|---|---|---|
| (in thousands, except production and per unit amounts) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | |||||
| Sales: | |||||||
| Oil: | |||||||
| Revenue(1) | $ | 13,874 | $ | 8,477 | |||
| Production sold (Mbbl) | 461 | 294 | |||||
| Average sales price per Bbl(1) | $ | 30.08 | $ | 28.83 | |||
| Natural Gas: | |||||||
| Revenue | $ | 21,300 | $ | 12,751 | |||
| Production sold (Mmcf) | 4,424 | 3,127 | |||||
| Average sales price per Mcf(1) | $ | 4.81 | $ | 4.08 | |||
| Natural gas liquids: | |||||||
| Revenue(1) | $ | 803 | $ | 539 | |||
| Production sold (Mbbl) | 35 | 24 | |||||
| Average sales price per Bbl | $ | 22.77 | $ | 22.29 | |||
| Costs and Expenses: | |||||||
| Average production cost per Mcfe | $ | 1.54 | $ | 1.46 | |||
| General and administrative expense per Mcfe | $ | 1.53 | $ | 0.76 | |||
| Depreciation, depletion and amortization per Mcfe | $ | 0.69 | $ | 1.07 | |||
| | Private predecessor | ||||||
|---|---|---|---|---|---|---|---|
| | Year ended December 31, 2004 | ||||||
| (in thousands, except production and per unit amounts) | US (excluding Appalachia) | Appalachia(2) | |||||
| Sales: | |||||||
| Oil: | |||||||
| Revenue(1) | $ | 20,966 | $ | 3,728 | |||
| Production sold (Mbbl) | 538 | 100 | |||||
| Average Sales price per Bbl(1) | $ | 38.97 | $ | 37.28 | |||
| Natural Gas: | |||||||
| Revenue(1) | $ | 44,193 | $ | 71,262 | |||
| Production sold (Mmcf) | 8,355 | 10,505 | |||||
| Average Sales price per Mcf(1) | $ | 5.29 | $ | 6.78 | |||
| Natural Gas Liquids: | |||||||
| Revenue(1) | $ | 1,844 | — | ||||
| Production sold (Mbbl) | 60 | — | |||||
| Average Sales price per Bbl (1) | $ | 30.73 | — | ||||
| Costs and Expenses: | |||||||
| Average production cost per Mcfe | $ | 1.41 | $ | 1.02 | |||
| General and administrative expense per Mcfe | $ | 0.96 | $ | 0.35 | |||
| Depreciation, depletion and amortization per Mcfe | $ | 1.17 | $ | 1.31 | |||
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| | Private predecessor | Successor | |||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | for the 275 day period ended October 2, 2005 | for the 90 day period ended December 31, 2005 | |||||||||||||||||
| (in thousands, except production and per unit amounts) | US (excluding Appalachia) | Appalachia | Total | US (excluding Appalachia) | Appalachia | Total | |||||||||||||
| Sales: | |||||||||||||||||||
| Oil: | |||||||||||||||||||
| Revenue(1) | $ | 15,100 | $ | 4,428 | $ | 19,528 | $ | 4,875 | $ | 1,791 | $ | 6,666 | |||||||
| Production sold (Mbbl) | 290 | 85 | 375 | 85 | 31 | 116 | |||||||||||||
| Average Sales price per Bbl(1) | $ | 52.07 | $ | 52.09 | $ | 52.07 | $ | 57.35 | $ | 57.77 | $ | 57.47 | |||||||
| Natural Gas: | |||||||||||||||||||
| Revenue(1) | $ | 39,523 | $ | 73,217 | $ | 112,740 | $ | 18,294 | $ | 45,000 | $ | 63,294 | |||||||
| Production sold (Mmcf) | 6,339 | 9,043 | 15,382 | 1,947 | 3,153 | 5,100 | |||||||||||||
| Average Sales price per Mcf(1) | $ | 6.23 | $ | 8.10 | $ | 7.33 | $ | 9.40 | $ | 14.27 | $ | 12.41 | |||||||
| Natural Gas Liquids: | |||||||||||||||||||
| Revenue(1) | $ | 553 | $ | — | $ | 553 | $ | 101 | $ | — | $ | 101 | |||||||
| Production sold (Mbbl) | 18 | — | 18 | 2 | — | 2 | |||||||||||||
| Average Sales price per Bbl(1) | $ | 30.72 | $ | — | $ | 30.72 | $ | 50.50 | $ | — | $ | 50.50 | |||||||
| Costs and Expenses: | |||||||||||||||||||
| Average production cost per Mcfe | $ | 1.39 | $ | 1.13 | $ | 1.25 | $ | 1.85 | $ | 1.31 | $ | 1.54 | |||||||
| General and administrative expense per Mcfe(3) | $ | 9.68 | $ | 1.06 | $ | 5.04 | $ | 1.96 | $ | 0.42 | $ | 1.07 | |||||||
| Depreciation, depletion and amortization per Mcfe | $ | 1.39 | $ | 1.40 | $ | 1.39 | $ | 2.30 | $ | 2.51 | $ | 2.42 | |||||||
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Our interest in productive wells
The following table quantifies as of the dates indicated information regarding productive wells (wells that are currently producing oil or natural gas or are capable of production), including temporarily shut-in wells. The number of total gross oil and natural gas wells excludes any multiple completions. Gross wells refers to the total number of physical wells that we hold any working interest in, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interests we hold in all wells. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells. This table excludes information with respect to Canada as a result of the sale of Addison in February 2005. The information is presented on a pro forma basis.
| | Pro forma at December 31, 2005 | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Gross wells(1) | Net wells | |||||||||||
| Areas | |||||||||||||
| Oil | Gas | Total | Oil | Gas | Total | ||||||||
| Appalachia | 408 | 4,289 | 4,697 | 403.4 | 3,916.5 | 4,319.9 | |||||||
| East Texas(2) | 15 | 456 | 471 | 13.1 | 275.2 | 288.3 | |||||||
| Mid-Continent(2) | 210 | 630 | 840 | 86.9 | 231.7 | 318.6 | |||||||
| Permian | 106 | 119 | 225 | 12.5 | 73.3 | 85.8 | |||||||
| Rockies | 67 | 140 | 207 | 35.0 | 125.2 | 160.2 | |||||||
| Other | 21 | 7 | 28 | 11.9 | 4.4 | 16.3 | |||||||
| Total | 827 | 5,641 | 6,468 | 562.8 | 4,626.3 | 5,189.1 | |||||||
| | Gross wells | Net wells | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Areas | |||||||||||||
| Oil | Gas | Total | Oil | Gas | Total | ||||||||
| East Texas | 5 | 392 | 397 | 3.2 | 216.4 | 219.6 | |||||||
| Mid-Continent | 96 | 564 | 660 | 39.2 | 194.3 | 233.5 | |||||||
| Total | 101 | 956 | 1,057 | 42.4 | 410.7 | 453.1 | |||||||
As of December 31, 2005 on a pro forma basis, we were the operator of 5,556 gross (4,969.2 net) wells, which represented approximately 88% of our pro forma Proved Reserves as of December 31, 2005.
Our drilling activities
We intend to concentrate our drilling activity on lower risk, development-type properties. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well, the estimated recoverable reserves attributable to each well and accessibility to the well site.
The following tables summarize our approximate gross and net interests in the wells we drilled during the periods indicated and refers to the number of wells completed at any time during the period, regardless of when drilling was initiated. These tables exclude information with respect to
15
Canada as a result of the sale of Addison in February 2005. The information for the year ended December 31, 2005 is presented on an actual basis and therefore excludes TXOK's drilling activities.
| | Development wells | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Gross | Net | |||||||||||
| | Productive | Dry | Total | Productive | Dry | Total | |||||||
| Year ended December 31, 2003 | |||||||||||||
| Total | 12 | 3 | 15 | 8.9 | 1.3 | 10.2 | |||||||
| Year ended December 31, 2004 | |||||||||||||
| U.S. (excluding Appalachia) | 20 | 2 | 22 | 15.4 | 1.3 | 16.7 | |||||||
| Appalachia | 71 | — | 71 | 70.0 | — | 70.0 | |||||||
| Total | 91 | 2 | 93 | 85.4 | 1.3 | 86.7 | |||||||
| Year ended December 31, 2005 | |||||||||||||
| U.S. (excluding Appalachia) | 19 | 1 | 20 | 18.4 | 0.5 | 18.9 | |||||||
| Appalachia | 85 | 1 | 86 | 82.7 | 1.0 | 83.7 | |||||||
| Total | 104 | 2 | 106 | 101.1 | 1.5 | 102.6 | |||||||
| | Exploratory wells | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Gross | Net | |||||||||||
| | Productive | Dry | Total | Productive | Dry | Total | |||||||
| Year ended December 31, 2003 | |||||||||||||
| Total | — | — | — | — | — | — | |||||||
| Year ended December 31, 2004 | |||||||||||||
| U.S. (excluding Appalachia) | — | — | — | — | — | — | |||||||
| Appalachia | 6 | 1 | 7 | 6.0 | 1.0 | 7.0 | |||||||
| Total | 6 | 1 | 7 | 6.0 | 1.0 | 7.0 | |||||||
| Year ended December 31, 2005 | |||||||||||||
| U.S. (excluding Appalachia) | — | — | — | — | — | — | |||||||
| Appalachia | 4 | 1 | 5 | 2.7 | 0.2 | 2.9 | |||||||
| Total | 4 | 1 | 5 | 2.7 | 0.2 | 2.9 | |||||||
The drilling activities in the United States referenced in the above table were primarily conducted in Texas, New Mexico, Louisiana, Colorado, Kansas, Ohio, Pennsylvania and West Virginia. As of December 31, 2005, we owned a 100% working interest in one well being drilled in Pennsylvania, one well in Texas, two wells in Colorado and a 50% working interest in one well being drilled in West Virginia. In addition, we had 100% working interest in two wells in Texas, six wells in Pennsylvania, one well with a 50% working interest in West Virginia and one well with a 25% working interest in Tennessee in the process of being completed. As of February 28, 2006, we owned a 100% working interest in two wells being drilled in Pennsylvania, 100% working interest in one well being drilled in Ohio, and 100% working interest in one well being drilled in West Virginia. In addition, we had three 100% working interest wells being completed in Texas and one 98.7% working interest well being completed in Colorado.
Our developed and undeveloped acreage
Developed acreage are those acres spaced or assignable to producing wells. Undeveloped acreage are those acres that do not currently have completed wells capable of producing commercial quantities of oil or natural gas, regardless of whether the acreage contains Proved Reserves. The following table
16
sets forth our developed and undeveloped acreage on a pro forma basis, at December 31, 2005 and excludes Canada as a result of the sale of Addison in February 2005:
| | Pro forma at December 31, 2005 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| | Developed acreage | Undeveloped acreage | |||||||
| Areas | |||||||||
| Gross | Net | Gross | Net | ||||||
| Appalachia | 349,848 | 329,343 | 314,602 | 297,285 | |||||
| East Texas(1) | 51,659 | 29,364 | 4,850 | 2,477 | |||||
| Mid-Continent(1) | 155,674 | 90,621 | 23,391 | 14,529 | |||||
| Permian | 39,116 | 22,228 | 8,639 | 5,167 | |||||
| Rockies | 42,096 | 23,077 | 14,344 | 6,901 | |||||
| Gulf Coast | 6,070 | 3,420 | 1,473 | 635 | |||||
| Total | 644,463 | 498,053 | 367,299 | 326,994 | |||||
| | Developed acreage | Undeveloped acreage | |||||||
|---|---|---|---|---|---|---|---|---|---|
| Areas | |||||||||
| Gross | Net | Gross | Net | ||||||
| East Texas | 44,617 | 23,360 | 3,675 | 1,870 | |||||
| Mid-Continent | 117,096 | 69,111 | 18,108 | 10,655 | |||||
| Total | 161,713 | 92,471 | 21,783 | 12,525 | |||||
The primary terms of our oil and natural gas leases expire at various dates, generally ranging from one to five years. Almost all of our undeveloped acreage is "held by production," which means that these leases are active as long as we produce oil or natural gas from the acreage. Upon ceasing production, these leases will expire. In Appalachia, we have 33,360, 28,485 and 42,747 net acres with leases expiring in 2006, 2007 and 2008, respectively. Leases expiring over the next three years in the other geographic areas are immaterial.
The undeveloped "held by production" acreage in many cases represents potential additional drilling opportunities through down spacing and drilling of proved undeveloped and unproved locations in the same formation(s) already producing in a given oil or natural gas field without the necessity of purchasing additional leases or producing properties.
Sales of producing properties and undeveloped acreage
We regularly 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 $443.3 million. During 2004, we received proceeds of $51.9 million from the sale of properties in the United States. During the year ended December 31, 2005, we received proceeds of $45.3 million from the sale of properties in the United States.
Our principal customers
During 2004, sales of natural gas to an industrial customer accounted for 10.6% of our total oil and natural gas revenues. For the 209 day period from January 1, 2003 to July 28, 2003, sales of oil to Plains All American, Inc. and affiliates accounted for approximately 14.0% of total revenues. Sales to
17
Western Gas Resources accounted for approximately 10.0% of total revenues for the same 209 day period. For the 156 day period from July 29, 2003 to December 31, 2003, sales to ONEOK Gas Marketing, Inc., Plains All American, Inc., and Western Gas Resources accounted for 10.0%, 13.2%, and 12.7% of total revenues, respectively.
Competition
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 staffs 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.
We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has 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 unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.
Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.
Applicable laws and regulations
U.S. regulations
The availability of a ready market for oil and natural gas production depends upon numerous factors beyond our control. These factors include state and federal regulation of oil and natural gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an over-supply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and gas plants also are subject to the jurisdiction of various federal, state and local agencies.
Our sales of natural gas are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. The FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate natural gas pipelines may charge for their services. The final rule revises FERC's pricing policy and current regulatory
18
framework to improve the efficiency of the market and further enhance competition in natural gas markets.
In the event we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, or BLM, or Minerals Management Service or other appropriate federal or state agencies.
The pipelines we use to gather and transport our oil and natural gas may be subject to regulation by the Department of Transportation, or DOT, under the Hazardous Liquids Pipeline Safety Act of 1979, as amended, or the HLPSA. The HLPSA governs the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Where applicable, the HLPSA requires us and other pipeline operators to comply with regulations issued pursuant to HLPSA that are designed to permit access to and allow copying of records and to make certain reports available and provide information as required by the Secretary of Transportation.
The Pipeline Safety Act of 1992 amends the HLPSA in several important respects. The Pipeline Safety Act requires the Research and Special Programs Administration of DOT, or the RSPA, to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by DOT of pipeline operator qualification rules requiring minimum training requirements for operators and requires that pipeline operators provide maps and records to RSPA. It also authorizes RSPA to require certain pipeline modifications as well as operational and maintenance changes. The Research and Special Program Improvements Act of 2004, or RSPIA, further amends the HLPSA, and transfers the authority of the RSPA to the newly-formed Pipeline and Hazardous Materials Safety Administration of DOT, or the PHMSA. In October 2005, the PHMSA proposed new regulations regarding the definition of, and safety standards for, gas gathering pipelines, which propose to establish a new risk-based approach to determine which gathering pipelines are subject to regulation, and what safety standards regulated pipelines must meet. We do not yet know whether new regulations might arise out of this rulemaking process will impose new or additional requirements on our pipelines. If so, we could incur significant expenses.
U.S. federal taxation
The federal government may propose tax initiatives that affect us. We are unable to determine what effect, if any, future proposals would have on product demand or our results of operations.
U.S. environmental regulations
The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to federal environmental laws and regulations, including, but not limited to:
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Our domestic activities are also controlled by state regulations promulgated under comparable state statutes. We also are subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain of our activities, limit or prohibit other activities because of protected areas or species, can impose certain substantial liabilities for the clean-up of pollution, impose certain reporting requirements, regulate remedial plugging operations to prevent future contamination and can require substantial expenditures for compliance. We cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.
Under CWA, which was amended and augmented by OPA, our release or threatened release of oil or hazardous substances into or upon waters of the United States, adjoining shorelines and wetlands and offshore areas could result in our being held responsible for: (1) the costs of removing or remediating a release; (2) administrative, civil or criminal fines or penalties; or (3) OPA specified damages, such as loss of use, and natural resource damages. The extent of our liability could be extensive depending upon the circumstances of the release. Liability can be joint and several and without regard to fault. The CWA also may impose permitting requirements for certain discharges of pollutants and requirements to develop Spill Prevention Control and Countermeasure Plans and Facility Response Plans to address potential discharges of oil into or upon waters of the United States and adjoining shorelines. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters.
CERCLA and comparable state statutes, also known as Superfund laws, can impose joint, several and retroactive liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a "hazardous substance" into the environment. In practice, clean-up costs are usually allocated among various persons. These classes of persons, or so-called potentially responsible parties, or PRPs, include the current and certain past owners and operators of a facility where there has been a release or threat of release of a hazardous substance and persons who disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the cost of such action. Liability can arise from conditions on properties where operations are conducted and/or from conditions at third party disposal facilities where wastes from operations were sent. Although CERCLA, as amended, currently exempts petroleum (including oil, natural gas and NGLs) from the definition of hazardous substance, some similar state statutes do not provide such an exemption. We cannot assure you that the exemption will be preserved in any future amendments of the act. Such amendments could have a significant impact on our costs or operations. Additionally, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA and similar state statutes at a future date. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA. We also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. Certain states have comparable statutes. In the event contamination is discovered at a site on which we are or have been an owner or operator, we could be liable for costs of investigation and remediation and natural resource damages.
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RCRA and comparable state and local programs impose requirements on the management, treatment, storage and disposal of both hazardous and nonhazardous solid wastes. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties we own or lease or the locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. We have not had control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. We also generate hazardous and nonhazardous solid waste in our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling and production operations, as "hazardous wastes" under RCRA, which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal and clean-up requirements. Adoption of these proposals could have a significant impact on our operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact on our operations.
Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Smaller sources may qualify for exemption from permit requirement of existing authorizations such as permits by rule or general permits. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forgo construction, modification or operation of certain air emission sources.
Oil and natural gas exploration and production, and possibly other activities, have been conducted at the majority of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances may require remediation. In some instances, we have agreed to indemnify the sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with the properties. We do not believe the costs to be incurred by us for compliance and remediating previously or currently owned or operated properties will be material, but we cannot guarantee that result.
If in the course of our routine oil and natural gas operations surface spills and leaks occur, including casing leaks of oil or other materials, we may incur penalties and costs for waste handling, remediation and third party actions for damages. Moreover, we are only able to directly control the operations of the wells that we operate. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with applicable environmental regulations may be attributable to us and may create legal liabilities for us.
There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation's coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development. States, such as Texas, also have coastal management programs, which provide for, among other things, the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. Coastal management programs also may provide for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the state coastal management plan. In the event our activities trigger these programs, this review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by us.
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We do not anticipate that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program complying with current environmental laws and regulations. As these laws and regulations are frequently changed and are subject to interpretation, our assessment regarding the cost of compliance or the extent of liability risks may change in the future. We are also unable to assure you that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with environmental laws and regulations in the future. If substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Although we maintain insurance coverage we consider to be customary in the industry, we are not fully insured against all of these risks, either because insurance is not available or because of high premiums. Accordingly, we may be subject to liability or may lose substantial portions of properties due to hazards that cannot be insured against or have not been insured against due to prohibitive premiums or for other reasons. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.
OSHA and other regulations
We are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Title to our properties
When we acquire developed properties, we conduct a title investigation. However, when we acquire undeveloped properties, as is common industry practice, we usually conduct little or no investigation of title other than a preliminary review of local mineral records. We do conduct title investigations and, in most cases, obtain a title opinion of local counsel before we begin drilling operations. We believe that the methods we utilize for investigating title prior to acquiring any property are consistent with practices customary in the oil and natural gas industry and that our practices are adequately designed to enable us to acquire good title to properties. However, some title risks cannot be avoided, despite the use of customary industry practices.
Our properties are generally burdened by:
We believe that none of these burdens either materially detract from the value of our properties or materially interfere with property used in the operation of our business. Substantially all of our properties are pledged as collateral under our credit agreement.
Our employees
As of December 31, 2005, we employed 314 persons of which 145 were involved in field operations and 169 were engaged in technical, office or administrative activities. None of our employees are represented by unions or covered by collective bargaining agreements. To date, we have not experienced any strikes or work stoppages due to labor problems, and we consider our relations with our employees to be good. We also utilize the services of independent consultants on a contract basis.
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This annual report contains forward-looking statements, as defined in Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements relate to, among other things, the following:
We have based these forward-looking statements on our current assumptions, expectations and projections about future events.
We use the words "may," "expect," "anticipate," "estimate," "believe," "continue," "intend," "plan," "budget" and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other "forward-looking" information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this annual report, including, but not limited to:
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We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. When considering our forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this annual report. The risk factors noted in this annual report and other factors noted throughout this annual report provide examples of risks, uncertainties and events that may cause our actual results to differ materially from those contained in any forward-looking statement. Please see "Item 1A. Risk factors" for a discussion of certain risks of our business and an investment in our common stock.
Glossary of selected oil and natural gas terms
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this annual report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Btu. British thermal unit, which is the heat required to raise the temperature of a one pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Infill drilling. Drilling of a well between known producing wells to better exploit the reservoir.
Mbbl. One thousand stock tank barrels.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Mmbbl. One million stock tank barrels.
Mmbtu. One million British thermal units.
Mmcf. One million cubic feet of natural gas.
Mmcfe. One million cubic feet equivalent calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Mmcfe/d. One million cubic feet equivalent per day calculated by converting one Bbl of oil or NGLs to six Mcf of natural gas.
Mmmbtu. One billion British thermal units.
NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX. New York Mercantile Exchange.
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Overriding royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to commodity price risk management activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil, natural gas and NGL prices and operating costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids 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, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units
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can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Recompletion. An operation within an existing well bore to make the well produce oil and/or gas from a different, separately producible zone other than the zone from which the well had been producing.
Reserve Life. The estimated productive life, in years, of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this annual report, reserve life is calculated by dividing the Proved Reserves (on a Mmcfe basis) at the end of the period by production volumes for the previous 12 months.
Royalty interest. An interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
Standardized Measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end Proved Reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Workovers. Operations on a producing well to restore or increase production.
Available Information
We make our filings with the SEC available on our website atwww.excoresources.com.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXCO RESOURCES, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Contents
Financial information for the periods prior to July 29, 2003, the date of our going private transaction, represents predecessor (Public Predecessor) basis financial statements. Financial information for the 156 day period from July 29, 2003 to December 31, 2003, calendar year 2004, and the 275 day period from January 1, 2005 to October 2, 2005, represents predecessor (Private 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.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of EXCO Resources, Inc.:
In our opinion, the accompanying consolidated statements of operations, of comprehensive income, of shareholder's 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 (Public Predecessor Company) for the period from January 1, 2003 to July 28, 2003 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 2 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations," as of January 1, 2003 and changed the manner in which it accounts for asset retirement costs.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 18, 2004, except as to
Note 2, for which the date is
November 22, 2005
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of EXCO Resources, Inc.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of shareholder's equity and of cash flows present fairly, in all material respects, the financial position of EXCO Resources, Inc. and its subsidiaries (Private Predecessor Company) at December 31, 2004, and the results of their operations and their cash flows for the period from January 1, 2005 to October 2, 2005, the year ended December 31, 2004 and period from July 29, 2003 to December 31, 2003 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 audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 31, 2006
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of EXCO Resources, Inc.:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of shareholder's 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 the 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.
/s/ PRICEWATERHOUSECOOPERS LLP
Dallas, Texas
March 31, 2006
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EXCO Resources, Inc.
Consolidated balance sheets
| | December 31, | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2004 | 2005 | ||||||||
| (in thousands, except per share amounts) | Private predecessor | Successor | ||||||||
| Assets | ||||||||||
| Current assets: | ||||||||||
| Cash and cash equivalents | $ | 16,007 | $ | 224,991 | ||||||
| Accounts receivable: | ||||||||||
| Oil and natural gas sales | 18,130 | 36,895 | ||||||||
| Joint interest | 2,213 | 1,081 | ||||||||
| Canadian income taxes receivable | — | 18,483 | ||||||||
| Interest and other | 418 | 12,189 | ||||||||
| Related party | — | 2,621 | ||||||||
| Deferred income taxes | — | 29,968 | ||||||||
| Deferred costs of initial public offering | — | 3,380 | ||||||||
| Oil and natural gas derivatives | 242 | — | ||||||||
| Marketable securities | 69 | — | ||||||||
| Other | 3,962 | 10,898 | ||||||||
| Current assets of discontinued operations | 34,807 | — | ||||||||
| Total current assets | 75,848 | 340,506 | ||||||||
| Oil and natural gas properties (full cost accounting method): | ||||||||||
| Unproved oil and natural gas properties | 18,829 | 53,121 | ||||||||
| Proved developed and undeveloped oil and natural gas properties | 454,328 | 873,595 | ||||||||
| Accumulated depreciation, depletion and amortization | (31,707 | ) | (13,281 | ) | ||||||
| Oil and natural gas properties, net | 441,450 | 913,435 | ||||||||
| Gas gathering, office and field equipment, net | 27,014 | 33,271 | ||||||||
| Assets of discontinued operations | 346,926 | — | ||||||||
| Deferred financing costs, net | 10,779 | — | ||||||||
| Goodwill | 19,984 | 220,006 | ||||||||
| Other assets | 22 | 419 | ||||||||
| Total assets | $ | 922,023 | $ | 1,507,637 | ||||||
See accompanying notes.
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EXCO Resources, Inc.
Consolidated balance sheets (continued)
| | December 31, | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| | 2004 | 2005 | |||||||
| (in thousands, except per share amounts) | Private predecessor | Successor | |||||||
| Liabilities and Shareholder's Equity | |||||||||
| Current liabilities: | |||||||||
| Interim bank loan | $ | — | $ | 350,000 | |||||
| Accounts payable and accrued liabilities | 21,919 | 24,781 | |||||||
| Related party payable | — | 6,056 | |||||||
| Accrued interest payable | 14,877 | 23,779 | |||||||
| Revenues and royalties payable | 7,249 | 11,266 | |||||||
| Income taxes payable | 1,460 | 901 | |||||||
| Deferred income taxes | 710 | — | |||||||
| Current portion of asset retirement obligations | 2,418 | 1,408 | |||||||
| Oil and natural gas derivatives | 22,458 | 53,189 | |||||||
| Current liabilities of discontinued operations | 34,604 | — | |||||||
| Total current liabilities | 105,695 | 471,380 | |||||||
| Long-term debt | 34,500 | 1 | |||||||
| 71/4% senior notes due 2011 | 452,953 | 461,801 | |||||||
| Asset retirement obligations and other long-term liabilities | 11,534 | 15,766 | |||||||
| Deferred income taxes | 15,794 | 134,602 | |||||||
| Oil and natural gas derivatives | 25,961 | 81,406 | |||||||
| Liabilities from discontinued operations | 71,835 | — | |||||||
| Commitments and contingencies | — | — | |||||||
| Shareholder's equity: | |||||||||
| Common stock, $.01 par value: Authorized shares—100,000; Issued and outstanding shares—1,000 at December 31, 2004 and 2005 | 1 | 1 | |||||||
| Additional paid-in capital | 172,045 | 326,716 | |||||||
| Retained earnings | 10,338 | 15,964 | |||||||
| Accumulated other comprehensive income: | |||||||||
| Foreign currency translation adjustments | 21,384 | — | |||||||
| Unrealized loss on equity investments | (17 | ) | — | ||||||
| Total shareholder's equity | 203,751 | 342,681 | |||||||
| Total liabilities and shareholder's equity | $ | 922,023 | $ | 1,507,637 | |||||
See accompanying notes.
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EXCO Resources, Inc.
Consolidated statements of operations
| | Public predecessor | Private predecessor | Successor | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands, except per share data) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | 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 | |||||||||||||
| Revenues and other income: | ||||||||||||||||||
| Oil and natural gas | $ | 22,403 | $ | 21,767 | $ | 141,993 | $ | 132,821 | $ | 70,061 | ||||||||
| Commodity price risk management activities | — | (10,800 | ) | (50,343 | ) | (177,253 | ) | (256 | ) | |||||||||
| Other income (loss) | (1,129 | ) | (161 | ) | 1,141 | 7,075 | 2,365 | |||||||||||
| Total revenues and other income | 21,274 | 10,806 | 92,791 | (37,357 | ) | 72,170 | ||||||||||||
| Cost and expenses: | ||||||||||||||||||
| Oil and natural gas production | 11,380 | 7,331 | 28,256 | 22,157 | 8,949 | |||||||||||||
| Depreciation, depletion and amortization | 5,125 | 5,413 | 28,519 | 24,687 | 14,071 | |||||||||||||
| Accretion of discount on asset retirement obligations | 320 | 205 | 800 | 617 | 226 | |||||||||||||
| General and administrative (includes $3.6 million, $44.1 million and $2.2 million of non-cash compensation expense for the period from January 1, 2003 to July 28, 2003, the period from January 1, 2005 to October 2, 2005 and the period from October 3, 2005 to December 31, 2005, respectively) | 11,347 | 3,823 | 15,275 | 89,344 | 6,225 | |||||||||||||
| Interest | 1,058 | 1,921 | 34,570 | 26,675 | 19,414 | |||||||||||||
| Total cost and expenses | 29,230 | 18,693 | 107,420 | 163,480 | 48,885 | |||||||||||||
| Income (loss) before income taxes | (7,956 | ) | (7,887 | ) | (14,629 | ) | (200,837 | ) | 23,285 | |||||||||
| Income tax expense (benefit) | (181 | ) | (7,764 | ) | 5,126 | (63,698 | ) | 7,321 | ||||||||||
| Income (loss) before discontinued operations and cumulative effect of change in accounting principle | (7,775 | ) | (123 | ) | (19,755 | ) | (137,139 | ) | 15,964 | |||||||||
| Discontinued operations: | ||||||||||||||||||
| Income (loss) from operations | 13,534 | 6,217 | 36,274 | (4,403 | ) | — | ||||||||||||
| Gain on disposition of Addison Energy Inc | — | — | — | 175,717 | — | |||||||||||||
| Income tax expense (benefit) | 4,982 | 1,917 | 10,358 | 49,282 | — | |||||||||||||
| Income from discontinued operations | 8,552 | 4,300 | 25,916 | 122,032 | — | |||||||||||||
| Income (loss) before cumulative effect of change in accounting principle | 777 | 4,177 | 6,161 | (15,107 | ) | 15,964 | ||||||||||||
| Cumulative effect of change in accounting principle, net of income taxes of $696,000 | 255 | — | — | — | — | |||||||||||||
| Net income (loss) | 1,032 | $ | 4,177 | $ | 6,161 | $ | (15,107 | ) | $ | 15,964 | ||||||||
| Dividends on preferred stock | 2,620 | |||||||||||||||||
| Loss on common stock | $ | (1,588 | ) | |||||||||||||||
| Basic and diluted loss per share from continuing operations | $ | (1.25 | ) | |||||||||||||||
| Basic and diluted net loss per share | $ | (0.19 | ) | |||||||||||||||
| Weighted average number of common and common equivalent shares outstanding: | ||||||||||||||||||
| Basic and diluted | 8,084 | |||||||||||||||||
See accompanying notes.
33
EXCO Resources, Inc.
Consolidated statements of cash flows
| | Public predecessor | Private predecessor | Successor | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 Day period from January 1, 2003 to July 28, 2003 | For the 156 Day period from July 29, 2003 to December 31, 2003 | 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 | ||||||||||||||
| | (Revised) | (Revised) | (Revised) | | | ||||||||||||||
| Operating Activities: | |||||||||||||||||||
| Net income (loss) | $ | 1,032 | $ | 4,177 | $ | 6,161 | $ | (15,107 | ) | $ | 15,964 | ||||||||
| Income from discontinued operations | (8,552 | ) | (4,300 | ) | (25,916 | ) | (122,032 | ) | — | ||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||||||
| Gain on sale of other assets | — | — | — | (373 | ) | — | |||||||||||||
| Depreciation, depletion and amortization | 5,125 | 5,413 | 28,519 | 24,688 | 14,071 | ||||||||||||||
| Stock option compensation expense | 3,567 | — | — | 44,092 | 2,207 | ||||||||||||||
| Accretion of discount on asset retirement obligations | 320 | 205 | 800 | 617 | 226 | ||||||||||||||
| Non-cash change in fair value of derivatives | — | 5,423 | 24,260 | 114,410 | (21,954 | ) | |||||||||||||
| Cumulative effect of change in accounting principle, net of income tax | (255 | ) | — | — | — | — | |||||||||||||
| Deferred income taxes | — | (7,764 | ) | 3,681 | (59,467 | ) | 15,654 | ||||||||||||
| Amortization of deferred financing costs | 358 | 100 | 3,859 | 1,320 | 2,381 | ||||||||||||||
| Proceeds from sale of Enron claim | — | — | 4,750 | — | — | ||||||||||||||
| Income from derivative ineffectiveness and terminated hedges | (187 | ) | — | — | — | — | |||||||||||||
| (Gains) losses from sales of marketable securities | (245 | ) | 30 | (14 | ) | 3 | — | ||||||||||||
| Other, net | 205 | (12 | ) | — | — | — | |||||||||||||
| Effect of changes in: | |||||||||||||||||||
| Accounts receivable | 1,553 | 4,983 | (2,487 | ) | (24,512 | ) | (2,533 | ) | |||||||||||
| Other current assets | (1,419 | ) | 404 | (1,350 | ) | (343 | ) | 1,097 | |||||||||||
| Accounts payable and other current liabilities | (530 | ) | 1,688 | 21,599 | 25,456 | (19,373 | ) | ||||||||||||
| Net cash provided by (used in) operating activities of discontinued operations | 19,446 | 11,373 | 54,771 | (69,772 | ) | — | |||||||||||||
| Net cash provided by (used in) operating activities | 20,418 | 21,720 | 118,633 | (81,020 | ) | 7,740 | |||||||||||||
| Investing Activities: | |||||||||||||||||||
| Acquisition of North Coast Energy, Inc., less cash acquired | — | — | (215,133 | ) | — | — | |||||||||||||
| Additions to oil and natural gas properties, gathering systems and equipment | (4,201 | ) | (21,722 | ) | (139,521 | ) | (151,144 | ) | (13,207 | ) | |||||||||
| Proceeds from disposition of property and equipment | 6,020 | 2,303 | 51,865 | 46,010 | (393 | ) | |||||||||||||
| Advances/investments with affiliates | — | 1,949 | 151 | — | — | ||||||||||||||
| Proceeds from sales of marketable securities | 422 | 1,393 | 1,296 | 59 | — | ||||||||||||||
| Other investing activities | (1 | ) | 467 | — | 209 | — | |||||||||||||
| Proceeds from sale of Addison Energy Inc., net of cash sold of $1,415 (discontinued operations) | — | — | — | 443,397 | — | ||||||||||||||
| Net cash used in investing activities of discontinued operations | (25,760 | ) | (22,918 | ) | (79,983 | ) | (442 | ) | — | ||||||||||
| Net cash provided by (used in) investing activities | (23,520 | ) | (38,528 | ) | (381,325 | ) | 338,089 | (13,600 | ) | ||||||||||
| Financing Activities: | |||||||||||||||||||
| Proceeds from long-term debt | 20,638 | 58,520 | 546,350 | 41,300 | 9,999 | ||||||||||||||
| Payments on long-term debt | (11,750 | ) | (56,000 | ) | (158,070 | ) | (148,247 | ) | (15,279 | ) | |||||||||
| Proceeds from exercise of stock options | 12,737 | — | — | — | — | ||||||||||||||
| Purchase of common stock from employees in connectioin with the merger | (17,874 | ) | — | — | — | — | |||||||||||||
| Purchase of director and employee stock options in connection with the merger | (3,567 | ) | — | — | — | — | |||||||||||||
| Payment of fees and expenses in connection with the merger | (563 | ) | — | — | — | — | |||||||||||||
| Preferred stock dividends | (2,620 | ) | — | — | — | — | |||||||||||||
| Deferred financing costs | (1,136 | ) | (1,592 | ) | (13,431 | ) | — | — | |||||||||||
| Other financing activities | 172 | 1 | — | — | — | ||||||||||||||
| Net cash provided by (used in) financing activities of discontinued operations | 13,945 | 14,035 | (91,397 | ) | 59,601 | — | |||||||||||||
| Net cash provided by (used in) financing activities | 9,982 | 14,964 | 283,452 | (47,346 | ) | (5,280 | ) | ||||||||||||
| Net increase (decrease) in cash | 6,880 | (1,844 | ) | 20,760 | 209,723 | (11,140 | ) | ||||||||||||
| Effect of exchange rates on cash and cash equivalents | 58 | 297 | (1,685 | ) | — | — | |||||||||||||
| Cash at beginning of period | 1,942 | 8,880 | 7,333 | 26,408 | 236,131 | ||||||||||||||
| Cash at end of period including cash of discontinued operations | 8,880 | 7,333 | 26,408 | 236,131 | 224,991 | ||||||||||||||
| Cash of discontinued operations at end of period | 1,697 | 3,961 | 10,401 | — | — | ||||||||||||||
| Cash at end of period | $ | 7,183 | $ | 3,372 | $ | 16,007 | $ | 236,131 | $ | 224,991 | |||||||||
| Supplemental Cash Flow Information: | |||||||||||||||||||
| Interest paid | $ | 618 | $ | 1,658 | $ | 17,102 | $ | 33,099 | $ | 124 | |||||||||
| Income taxes paid | $ | — | $ | — | $ | — | $ | 38,213 | $ | 15,500 | |||||||||
| Supplemental non cash investing: | |||||||||||||||||||
| Capitalized stock option compensation | $ | — | $ | — | $ | — | $ | — | $ | 1,034 | |||||||||
See accompanying notes.
34
EXCO Resources, Inc.
Consolidated statements of changes in shareholder's equity
| | 5% Preferred Stock | Common Stock | | | Notes receivable - -officers and employees | | | Accumulated other comprehensive income (loss) | | |||||||||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | Additional paid-In capital | Deferred compensation | Treasury stock | Retained earnings (deficit) | Total shareholders' equity | |||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | |||||||||||||||||||||||||||||
| Public predecessor: | ||||||||||||||||||||||||||||||||
| Balance, December 31, 2002 | 5,005 | $ | 101,175 | 7,263 | $ | 145 | $ | 53,107 | $ | (705 | ) | $ | (173 | ) | $ | (3,562 | ) | $ | (44,399 | ) | $ | (5,704 | ) | $ | 99,884 | |||||||
| Conversion of 5% Preferred Stock | (5,005 | ) | (101,175 | ) | 5,005 | 100 | 101,074 | — | — | — | — | — | (1 | ) | ||||||||||||||||||
| Exercise of stock options and warrants | — | — | 1,133 | 23 | 12,716 | — | — | — | — | — | 12,739 | |||||||||||||||||||||
| Repayment of note for stock | — | — | — | — | — | — | 173 | — | — | — | 173 | |||||||||||||||||||||
| Deferred compensation | — | — | — | — | (594 | ) | — | — | — | — | — | (594 | ) | |||||||||||||||||||
| Amortization of deferred compensation | — | — | — | — | — | 705 | — | — | — | — | 705 | |||||||||||||||||||||
| Purchase of treasury stock | — | — | — | — | — | — | — | (17,874 | ) | — | — | (17,874 | ) | |||||||||||||||||||
| Dividends on preferred stock | — | — | — | — | — | — | — | — | (2,620 | ) | — | (2,620 | ) | |||||||||||||||||||
| Foreign currency translation adjustments | — | — | — | — | — | — | — | — | — | 2,791 | 2,791 | |||||||||||||||||||||
| Equity investments | — | — | — | — | — | — | — | — | — | 590 | 590 | |||||||||||||||||||||
| Hedging activities | — | — | — | — | — | — | — | — | — | (1,602 | ) | (1,602 | ) | |||||||||||||||||||
| Net income | — | — | — | — | — | — | — | — | 1,032 | — | 1,032 | |||||||||||||||||||||
| Balance, for the 209 day period ended July 28, 2003, public predecessor | — | $ | — | 13,401 | $ | 268 | $ | 166,303 | $ | — | $ | — | $ | (21,436 | ) | $ | (45,987 | ) | $ | (3,925 | ) | $ | 95,223 | |||||||||
Private predecessor: | ||||||||||||||||||||||||||||||||
| Beginning Balance, July 29, 2003. | — | $ | — | 1 | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
| Capital contributed by parent | — | — | — | — | 172,045 | — | — | — | — | — | 172,045 | |||||||||||||||||||||
| Foreign currency translation adjustments | — | — | — | — | — | — | — | — | — | 7,680 | 7,680 | |||||||||||||||||||||
| Equity investments | — | — | — | — | — | — | — | — | — | (34 | ) | (34 | ) | |||||||||||||||||||
| Net income | — | — | — | — | — | — | — | — | 4,177 | — | 4,177 | |||||||||||||||||||||
| Balance, for the 156 day period ended December 31, 2003 | — | — | 1 | 1 | 172,045 | — | — | — | 4,177 | 7,646 | 183,869 | |||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | — | — | — | — | — | — | 13,704 | 13,704 | |||||||||||||||||||||
| Equity investments | — | — | — | — | — | — | — | — | — | 17 | 17 | |||||||||||||||||||||
| Net income | — | — | — | — | — | — | — | — | 6,161 | 6,161 | ||||||||||||||||||||||
| Balance, December 31, 2004 | — | — | 1 | 1 | 172,045 | — | — | — | 10,338 | 21,367 | 203,751 | |||||||||||||||||||||
Foreign currency translation adjustments | — | — | — | — | — | — | — | — | — | (21,399 | ) | (21,399 | ) | |||||||||||||||||||
| Unrealized gain on equity investments | — | — | — | — | — | — | — | — | — | 32 | 32 | |||||||||||||||||||||
| Stock based compensation | — | — | — | — | 44,092 | — | — | — | — | — | 44,092 | |||||||||||||||||||||
| Net loss | — | — | — | — | — | — | — | — | (15,107 | ) | — | (15,107 | ) | |||||||||||||||||||
| Balance, for the 275 day period ended October 2, 2005, public predecessor | — | $ | — | 1 | $ | 1 | $ | 216,137 | $ | — | $ | — | $ | — | $ | (4,769 | ) | $ | — | $ | 211,369 | |||||||||||
Successor: | ||||||||||||||||||||||||||||||||
| Acquisition by Holdings II | — | $ | — | 1 | $ | 1 | $ | 323,199 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 323,200 | ||||||||||||
| Stock based compensation | — | — | — | — | 3,517 | — | — | — | — | — | 3,517 | |||||||||||||||||||||
| Net income | — | — | — | — | — | — | — | — | 15,964 | — | 15,964 | |||||||||||||||||||||
| Balance, for the 90 day period ended December 31, 2005 | — | $ | — | 1 | $ | 1 | $ | 326,716 | $ | — | $ | — | $ | — | $ | 15,964 | $ | — | $ | 342,681 | ||||||||||||
See accompanying notes.
35
EXCO Resources, Inc.
Consolidated statements of comprehensive income (loss)
| | Public predecessor | Private predecessor | Successor | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | 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 | ||||||||||||
| Net income (loss) | $ | 1,032 | $ | 4,177 | $ | 6,161 | $ | (15,107 | ) | $ | 15,964 | ||||||
| Other comprehensive income (loss): | |||||||||||||||||
| Hedging activities: | |||||||||||||||||
| Effective changes in fair value, net of tax of $0 | 14,701 | — | — | — | — | ||||||||||||
| Reclassification adjustments for settled contracts, net of tax of $0 | (14,540 | ) | — | — | — | — | |||||||||||
| Amortization of terminated contracts, net of tax of $0 | (1,763 | ) | — | — | — | — | |||||||||||
| Total hedging activities | (1,602 | ) | — | — | — | — | |||||||||||
| Reclassification adjustment of foreign currency translation adjustment | 2,791 | 7,680 | 13,704 | — | — | ||||||||||||
| Reclassification adjustment for impairment of marketable securities | — | — | — | — | — | ||||||||||||
| Unrealized gain (loss) on equity investments, net of taxes of $0, $(18) and $9 for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from from July 29, 2003 to December 31, 2003 and the year ended December 31, 2004 | 590 | (34 | ) | 17 | — | — | |||||||||||
| Total comprehensive income (loss) | $ | 2,811 | $ | 11,823 | $ | 19,882 | $ | (15,107 | ) | $ | 15,964 | ||||||
See accompanying notes.
36
EXCO Resources, Inc.
Notes to consolidated financial statements
1. Organization
EXCO Resources, Inc., a Texas corporation, was formed in October 1955 and became a wholly-owned subsidiary of EXCO Holdings Inc. (Holdings) on July 29, 2003 pursuant to the going private transaction described below. On October 3, 2005, Holdings was acquired by EXCO Holdings II Inc. pursuant to the Equity Buyout described below. Our operations consist primarily of acquiring interests in producing oil and natural gas properties located in the continental United States and, until February 10, 2005, Canada. We also act as the operator of some of these properties and receive overhead reimbursement fees as a result.
The going private transaction
Holdings, a Delaware corporation, was formed March 4, 2003 and had no operations prior to July 29, 2003 when it acquired all of the outstanding common stock and stock options of EXCO Resources, Inc. (EXCO, Resources, we) (the going private transaction). Prior to July 29, 2003, EXCO was a public company whose common stock was traded on the NASDAQ National Market (NASDAQ). For the period from March 4, 2003 (date of inception) and after the acquisition of EXCO on July 29, 2003, through October 3, 2005, the date of the Equity Buyout, Holdings and EXCO are collectively referred to herein as the Company. On July 29, 2003, pursuant to an Agreement and Plan of Merger, ER Acquisition, Inc., a Texas corporation, and wholly-owned subsidiary of Holdings merged into Resources. Prior to July 29, 2003 EXCO's financial statements are referred to as Public Predecessor and subsequent to that date through October 3, 2005, the date of the Equity Buyout, they are referred to as Private Predecessor and include purchase accounting adjustments related to this change in control.
Holdings was formed by our chairman and chief executive officer, Douglas H. Miller, and his buying group for the purpose of entering into the merger agreement. The holders of EXCO's common stock, other than Holdings and its subsidiaries, received cash of $18.00 per share. The buyout of EXCO was funded with borrowings from EXCO's existing credit facilities of approximately $53.6 million and approximately $172.0 million of Holdings' equity. The equity capital for Holdings was provided by:
Upon completion of the merger transaction, EXCO's common stock was delisted from trading on the NASDAQ or any other exchange and EXCO's common stock registration pursuant to Section 12(g)(4) of the Securities Exchange Act of 1934 was terminated.
The total purchase price for EXCO was $353.5 million representing the purchase of all outstanding common stock and stock options including the amounts contributed to Holdings by management and
37
key employees and other investors, and liabilities assumed as detailed below and was allocated as follows (in thousands):
| Purchase price calculations: | |||||
| Payments for tendered shares including options | $ | 195,327 | |||
| Value of EXCO shares contributed by management | 8,429 | ||||
| Value of EXCO shares contributed by other investors | 17,966 | ||||
| Assumption of debt | 130,003 | ||||
| Merger related costs | 1,819 | ||||
| Total EXCO acquisition costs | $ | 353,544 | |||
Allocation of purchase price: | |||||
| Oil and natural gas properties—proved | $ | 358,111 | |||
| Oil and natural gas properties—unproved | 9,967 | ||||
| Goodwill | 51,120 | ||||
| Other property and equipment and other assets | 3,678 | ||||
| Current assets | 36,705 | ||||
| Deferred income taxes(1) | (50,733 | ) | |||
| Accounts payable and accrued expenses | (37,757 | ) | |||
| Asset retirement obligations | (15,744 | ) | |||
| Fair value of oil and natural gas derivatives | (1,803 | ) | |||
| Total allocation | $ | 353,544 | |||
As a result of the change in control, generally accepted accounting principles (GAAP) requires the acquisition by Holdings to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards (SFAS) No. 141, "Business Combinations." Accordingly, the financial statements for periods subsequent to July 28, 2003, reflect Holdings' stepped-up basis resulting from the acquisition. The aggregate purchase price was allocated to the underlying assets and liabilities based upon the respective estimated fair values at July 29, 2003 (date of acquisition). Carryover basis accounting applies for tax purposes. All financial information presented prior to July 29, 2003 represents the Public Predecessor basis of accounting.
The purchase price allocation resulted in $51.1 million of goodwill, $24.2 million in the EXCO operating segment and $26.9 million in the Canadian geographic operating segment (reflected on the consolidated balance sheet at December 31, 2004 as Assets of discontinued operations). None of the goodwill is deductible for income tax purposes. See "Note 2. Summary of significant accounting policies" for a description of our accounting policies concerning goodwill.
38
Pro forma results of operations
The following table reflects the pro forma results of operations as though the merger had been consummated at January 1, 2003:
| (in thousands, unaudited) | Year ended December 31, 2003 | ||
|---|---|---|---|
| Revenues and other income | $ | 32,080 | |
| Income before cumulative effect of change in accounting principle | 10,169 | ||
| Net income | 10,424 | ||
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 is 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:
| (in thousands) | | |||||
|---|---|---|---|---|---|---|
| Acquisition cost: | ||||||
| Payments for shares | $ | 478,836 | ||||
| Exchange of Holdings II shares for Holdings shares | 166,884 | |||||
| Assumption of senior notes ($452,643 aggregate book value plus $15,357 premium to fair value) | 468,000 | |||||
| Assumption of long-term debt | 1 | |||||
| Less cash assumed of $236,371, less cash compensation payments related to the Equity Buyout | (206,507 | ) | ||||
| Total Holdings acquisition cost | $ | 907,214 | ||||
39
Allocation of acquisition cost: | ||||||
| Oil and natural gas properties—proved | $ | 852,122 | ||||
| Oil and natural gas properties—unproved | 58,573 | |||||
| Total oil and natural gas properties | 910,695 | |||||
| Gas gathering assets and other equipment | 33,073 | |||||
| Deferred tax asset ($3,471 reclassified to deferred tax liability) | — | |||||
| Other assets, reflecting the reduction of deferred debt issuance costs of $8,862 to zero | 285 | |||||
| Goodwill | 220,006 | |||||
| Other current assets | 50,898 | |||||
| Accounts payable and accrued expenses | (44,703 | ) | ||||
| Asset retirement obligations and other long-term liabilities | (17,538 | ) | ||||
| Oil and natural gas derivative liabilities | (156,549 | ) | ||||
| Deferred tax liability of $131,916 at an average marginal tax rate of 39.5%(1), net of $42,963 reclassification of Holdings historical deferred tax asset | (88,953 | ) | ||||
| Total allocation | $ | 907,214 | ||||
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:
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.
40
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.
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. As of December 31, 2005, a total of 4,979,575 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. As a result, we recorded non-cash compensation of $2.2 million as general and administrative expenses and capitalized $1.0 million as oil and natural gas properties during the 90 day period from October 3, 2005 to December 31, 2005.
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 sheet as of December 31, 2005 and the results of operations, cash flows and comprehensive income for the 90 day period from October 3, 2005 to December 31, 2005 are for EXCO and its subsidiaries and represents the stepped up Successor basis of accounting following the Equity Buyout transaction.
The accompanying consolidated balance sheet as of December 31, 2004 and the results of operations, cash flows and comprehensive income for the 156 day period from July 29, 2003 to December 31, 2003, 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 Private Predecessor basis of accounting following the going private transaction.
The accompanying consolidated statements of operations, cash flows and comprehensive income for the 209 day period from January 1, 2003 to July 28, 2003 are for EXCO and its subsidiaries and represent the Public Predecessor basis of accounting.
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The financial statements for all periods prior to January 1, 2005 have been restated to reflect the financial position, operations, cash flow and comprehensive income of Addison Energy Inc. (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, natural gas and NGL reserve volumes, future development, dismantlement and abandonment costs, share-based compensation expenses, estimates relating to certain oil, natural gas and NGL revenues and expenses and the fair market value of derivatives and equity securities. Actual results may differ from management's estimates.
Cash equivalents and marketable securities
We consider all highly liquid investments with maturities of three months or less when purchased, to be cash equivalents.
We have evaluated our investment policies in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" and determined that all of our marketable securities, other than cash equivalents, are to be classified as available for sale. Available for sale securities are carried at fair value, with the unrealized gains and losses reported in other comprehensive income. Realized gains and losses are included in other income in the consolidated statement of operations. Declines in value that are considered to be "other than temporary" on available for sale securities are shown separately in the consolidated statement of operations. Realized gains and losses are determined using the first-in, first-out method.
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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, natural gas or NGLs 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, natural gas and NGL sales are generally uncollateralized. We have provided for credit losses in the financial statements and these losses have been within management's expectations. The allowance for doubtful accounts receivable (including current assets of discontinued operations) aggregated $1.5 million and $1.6 million at December 31, 2004 and 2005, 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 13. Derivative financial instruments."
Derivative financial instruments
We engage in commodity price risk management activities in connection with the incurrence of debt related to our acquisition activities. Our objective in entering into these commodity price risk management transactions is to manage price fluctuations and achieve a more predictable cash flow for our development and acquisition activities. These derivatives are not held for trading purposes.
Prior to July 28, 2003, EXCO's derivative financial instruments were designated as cash flow hedges under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." On the date the derivative contract was entered into, it designated the derivative as a hedge. Changes in the fair value of a derivative that was highly effective as a cash flow hedge were recorded in other comprehensive income, until the underlying transactions occur.
EXCO formally documented all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process included linking all derivatives that were designated as cash flow hedges to forecasted transactions. EXCO also formally assessed, both at the hedge's inception and on an ongoing basis, whether the derivatives that were used in hedging transactions were highly effective in offsetting changes in cash flows of hedged items. When it was determined that a derivative was not highly effective as a hedge or that it had ceased to be a highly effective hedge, EXCO discontinued hedge accounting prospectively, as discussed below.
EXCO discontinued hedge accounting prospectively when: (1) it was determined that the derivative was no longer highly effective in offsetting changes in cash flows of a hedged item; (2) the derivative expired or was sold, terminated or exercised; (3) the derivative was not designated as a hedge instrument, because it was unlikely that a forecasted transaction would occur; or (4) management determined that designation of the derivative as a hedge instrument was no longer appropriate.
Effective as of November 30, 2001, EXCO ceased hedge accounting for its hedge transactions then in place with Enron North America Corp., the counterparty to its swap agreements, due to Enron
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North America's bankruptcy filing. See "Note 13. Derivative financial instruments" for a discussion of these derivative transactions.
Effective July 29, 2003, in connection with the going private transaction, we discontinued hedge accounting for all existing derivatives. Currently, we do not designate derivative transactions as hedges for accounting purposes; accordingly, all derivatives are recorded at fair value on our consolidated balance sheets and changes in the fair value of derivative financial instruments including interest rate swaps are recognized currently in our consolidated statements of operations. We continue to designate derivative financial instruments as hedges for income tax purposes.
For the 209 day period from January 1, 2003 to July 28, 2003, EXCO recorded as other income in the statements of operations, a loss of $2.5 million from hedge ineffectiveness. For the 209 day period from January 1, 2003 to July 28, 2003, EXCO also recorded as other income in the statements of operations $1.8 million from derivative transactions for which hedge accounting was discontinued.
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 intangible 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, 2004 and 2005, the $18.8 million and $53.1 million, respectively, in unproved oil and natural gas properties resulted from the allocation of the estimated fair value of undeveloped acreage and possible and probable 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.
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.
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
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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 Securities and Exchange Commission (SEC) issued SAB No. 106, which clarifies the calculation of the full cost ceiling and depreciation, depletion, and amortization of oil and natural gas properties in conjunction with accounting for asset retirement obligations under SFAS No. 143. The guidance in SAB No. 106 has not had a significant impact on our consolidated financial statements.
Gas gathering, office and field equipment
Gas gathering, office and field equipment are capitalized at cost and depreciated on a straight line basis over their estimated useful lives. Gathering systems are depreciated over estimated useful lives ranging from 10 to 25 years. Field and office 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.
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The following table reflects our balances for goodwill as of December 31, 2004 and 2005 (in thousands):
| Private Predecessor: | ||||
Balance as of December 31, 2003 | $ | 24,218 | ||
| Activity during the year ended December 31, 2004: | ||||
| Sales of oil and natural gas properties | (2,954 | ) | ||
| Sale of the Enron claim | (1,280 | ) | ||
| Balance as of December 31, 2004(1) | $ | 19,984 | ||
Successor: | ||||
Equity Buyout (see "Note 1—Organization") | $ | 220,006 | ||
| Activity during the 90 day period from October 3, 2005 to December 31, 2005 | — | |||
| Balance as of December 31, 2005 | $ | 220,006 | ||
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.
Deferred abandonment and asset retirement obligations
Prior to 2003, EXCO did not provide for site restoration costs on its United States properties as it estimated that salvage values would exceed the asset retirement costs.
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. EXCO adopted the new rules on asset retirement obligations on January 1, 2003. Application of the new rules resulted in an increase in net proved developed and undeveloped oil and natural gas properties of approximately $5.6 million, recognition of an asset retirement obligation liability of approximately $6.1 million, and a cumulative effect of adoption that increased net income and stockholder's equity by approximately $0.3 million.
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The following is a reconciliation of our asset retirement obligations for the periods indicated (in thousands):
| | Public predecessor | Private predecessor | Successor | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | 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 | |||||||||||
| Asset retirement obligation at beginning of period | $ | — | $ | 6,077 | $ | 6,687 | $ | 13,247 | $ | 14,275 | ||||||
| Activity during the period: | ||||||||||||||||
| Cumulative effect of change in accounting principle | 6,164 | — | — | — | — | |||||||||||
| Adjustment to liability due to purchase of EXCO by Holdings in 2003 and Holdings II in 2005 | — | 444 | — | — | 1,607 | |||||||||||
| Liabilities incurred during period | 37 | 49 | 8,462 | 1,686 | 51 | |||||||||||
| Liabilities settled during period | (444 | ) | (88 | ) | (2,702 | ) | (1,275 | ) | (336 | ) | ||||||
| Accretion of discount | 320 | 205 | 800 | 617 | 226 | |||||||||||
Asset retirement obligation at end of period | 6,077 | 6,687 | 13,247 | 14,275 | 15,823 | |||||||||||
| Less current portion | — | — | 2,418 | 1,713 | 1,408 | |||||||||||
| Long-term portion | $ | 6,077 | $ | 6,687 | $ | 10,829 | $ | 12,562 | $ | 14,415 | ||||||
We have no assets that are legally restricted for purposes of settling asset retirement obligations.
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, 2004 and 2005 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 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, 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, we have capitalized $0.5 million, $0.5 million, $1.6 million, $1.2 million and $1.5 million, respectively. Included in the $1.5 million for the 90 day period from October 3, 2005 to December 31, 2005 is $1.0 million of share based compensation resulting from the adoption of SFAS No. 123(R) on October 3, 2006. See "Note 8. Stock transactions" for further discussion.
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Overhead reimbursement fees
We have classified fees from overhead charges billed to working interest owners, including ourselves, of $1.3 million, $0.9 million, $2.1 million, $1.3 million and $0.5 million for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, 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, respectively, as a reduction of general and administrative expenses in the accompanying statements of operations. Our share of these charges was $0.9 million, $0.7 million, $1.5 million, $0.8 million and $0.3 million for the 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, 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, respectively, and are classified as oil and natural gas production costs.
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
SFAS No. 128, "Earnings per share," requires companies to present two calculations of earnings per share; basic and diluted. Basic earnings per common share for the 209 day period from January 1, 2003 to July 28, 2003 equals the net income plus cumulative effect change in accounting principle less preferred stock dividends divided by the weighted average common shares outstanding during the period. Diluted earnings per common share for the 209 day period from January 1, 2003 to July 28, 2003 equals net income divided by the sum of weighted average common shares outstanding during the period plus any dilutive common stock equivalents assumed to be issued. Common stock equivalents for the 209 day period from January 1, 2003 to July 28, 2003 are shares assumed to be issued if (1) EXCO's outstanding stock options were in-the-money and exercised, and (2) the outstanding 5% convertible preferred stock was converted to common stock.
For the 209 day period from January 1, 2003 through July 28, 2003, EXCO reported a loss from continuing operations of $7.8 million. As a result, the common stock equivalents of director and employee stock options and the 5% convertible preferred stock, which would have increased the weighted average number of shares outstanding by approximately 535,000 and 4,363,000 shares, respectively, are considered to be anti-dilutive and are not considered in the earnings per share calculation due to a loss from continuing operations being reported for that period.
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The following table presents the basic and diluted earnings (loss) per share computations for the 209 day period from January 1, 2003 through July 28, 2003:
| (in thousands, except per share amounts) | 209 day period ended July 28, 2003 | ||||||
|---|---|---|---|---|---|---|---|
| Basic and diluted earnings (loss) per common share: | |||||||
| Loss from continuing operations | $ | (7,775 | ) | ||||
| Dividends of preferred stock | (2,620 | ) | |||||
| Cumulative effect of change in accounting principle | 255 | ||||||
| Loss on common stock | $ | (10,140 | ) | ||||
| Income from discontinued operations | $ | 8,552 | |||||
| Shares: | |||||||
| Weighted average number of common shares outstanding | 8,084 | ||||||
| Basic and diluted earnings (loss) per common share | |||||||
| Continuing operations | $ | (1.25 | ) | ||||
| Discontinued operations | 1.06 | ||||||
| Total basic loss per common share | $ | (0.19 | ) | ||||
Earnings per share for all periods after July 28, 2003 are not presented since we are wholly-owned by Holdings, and its successor, Holdings II, our parent.
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 8. 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.
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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. As a result, SFAS 123 had no effect on EXCO's results of operations for the 209 day period from January 1, 2003 to July 28, 2003. Stock based compensation expense reflected in the table below for the 209 day period from January 1, 2003 to July 28, 2003, is a result of options issued under EXCO's 1998 Stock Option Plan that were issued subject to shareholders' approval and options that were issued to the management and key employees of Addison. See "Note 8. Stock transactions" for a further description of these stock options.
Had compensation costs for these plans been determined consistent with SFAS No. 123, EXCO's net income and earnings (loss) per share (EPS) would have been adjusted to the following pro forma amounts (See "Note 8. Stock transactions" for assumptions used in fair value method):
| (in thousands) | period from January 1, 2003 to July 28, 2003 | |||
|---|---|---|---|---|
| Net income applicable to common stockholders, as reported | $ | (1,588 | ) | |
| Add: Stock-based compensation expense, as reported (net of taxes) | 2,578 | |||
| Less: Total stock-based compensation expense determined under the fair value method for employee stock awards, net of taxes | (6,969 | ) | ||
| Net income applicable to common stockholders, proforma | $ | (5,979 | ) | |
Basic and diluted net loss per share, as reported | $ | (0.19 | ) | |
| Basic and diluted net loss per share, proforma | $ | (0.74 | ) | |
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.
Effective with the grant of these options on June 3 and June 4, 2004, we elected to utilize the accounting method prescribed by APB 25 under which no compensation expense was required to be recognized upon the issuance of stock options to our employees as the exercise price of the option is equal to or higher than the fair value of the underlying common stock at the date of grant.
Under the minimum value method as prescribed under SFAS No. 123, no compensation expense would have been incurred during the year ended December 31, 2004 from the granting of these stock options and, as such, no pro forma disclosure is required.
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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. 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. We have recorded a receivable in the amount of Cdn. $21.5 million (U.S. $18.9 million) for our estimate of the excess of the amount withheld for Canadian income taxes from the sales proceeds over the estimated amount of Canadian income taxes that are actually owed on the gain from the sale. 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 is also 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 makes an employment offer to a terminated employee and the employee accepts the offer, Purchaser is obligated to pay EXCO an amount equal to
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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 have 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 has been eliminated. These amounts were considered in the determination of the gain on the sale.
The net carrying value of Addison's assets and liabilities as of December 31, 2004 are as follows (in thousands of U.S. dollars):
| | December 31, 2004 | |||
|---|---|---|---|---|
| Cash | $ | 10,401 | ||
| Other current assets | 24,406 | |||
| Oil and natural gas properties, net | 315,144 | |||
| Gas gathering, office and field equipment, net | 267 | |||
| Goodwill | 31,432 | |||
| Other assets | 83 | |||
| Total assets | 381,733 | |||
| Current liabilities | 34,604 | |||
| Long-term debt | 12,896 | |||
| Deferred income taxes | 43,308 | |||
| Other liabilities | 15,631 | |||
| Total liabilities | 106,439 | |||
| Net investment in Addison | $ | 275,294 | ||
The following table presents the summary operating results for Addison, which has been reported as a discontinued operation:
| | Public Predecessor | Private Predecessor | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | Year ended December 31, 2004 | For the 275 day period from January 1, 2005 to October 2, 2005 | |||||||||
| Revenues | $ | 39,109 | $ | 24,426 | $ | 85,219 | $ | 4,490 | |||||
| Costs and expenses | 25,575 | 18,209 | 48,945 | 8,893 | |||||||||
| Income (loss) from operations | 13,534 | 6,217 | 36,274 | (4,403 | ) | ||||||||
| Gain on disposition | — | — | — | 175,717 | |||||||||
| Income tax expense | 4,982 | 1,917 | 10,358 | 49,282 | |||||||||
| Income from discontinued operations, net of income tax | $ | 8,552 | $ | 4,300 | $ | 25,916 | $ | 122,032 | |||||
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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 209 day period beginning January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003 and 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.
Our current presentation of cash flow includes net income from discontinued operations as a separate adjustment to reconcile cash flows from operations. The cash flow from discontinued operations includes cash flows from our discontinued Canadian operations and the cash flows related to the sale of these operations.
4. Marketable securities
Marketable securities at December 31, 2004 were common stock investments in public corporations, which are classified as available for sale securities. At December 31, 2004, our cost basis of marketable securities was $37,000 while the aggregate fair value was $69,000. In May 2005, we sold our remaining marketable securities. We had no marketable securities at December 31, 2005.
In May 2004, we received common stock of a public corporation valued at approximately $0.5 million as a portion of the proceeds from the sale of oil and natural gas properties. We sold all of these shares in September 2004 for approximately $0.5 million.
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At December 31, 2004, we had gross unrealized holding gains from available for sale securities of $32,000. Investment income is presented in the following table:
| | Public predecessor | Private Predecessor | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 day period from January 1, 2003 To July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | December 31, 2004 | For the 275 day period from January 1, 2005 to October 2, 2005 | ||||||||
| Gross proceeds from sales of marketable securities | $ | 442 | $ | 1,393 | $ | 1,296 | $ | 59 | ||||
| Gross realized gains from sales of marketable securities | 245 | — | 14 | 3 | ||||||||
| Gross realized losses from sales of marketable securities | — | (30 | ) | — | — | |||||||
| Unrealized net gain (loss) included in other comprehensive income | 590 | (34 | ) | 17 | — | |||||||
There were no marketable securities activities during the 90 day period from October 3, 2005 to December 31, 2005.
5. 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.
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The total purchase price for North Coast was $225.1 million representing the purchase of all outstanding common stock and liabilities assumed as detailed below and has been allocated as follows (in thousands):
| Purchase price calculations: | |||||
| Payments for tendered shares including options and warrants | $ | 167,781 | |||
| Assumption of debt including interest | 57,148 | ||||
| Merger related costs | 156 | ||||
| Total North Coast acquisition costs (before cash acquired) | $ | 225,085 | |||
| Allocation of purchase price: | |||||
| Oil and natural gas properties—proved | $ | 192,035 | |||
| Oil and natural gas properties—unproved | 7,258 | ||||
| Gas gathering assets and other equipment | 21,454 | ||||
| Cash | 10,429 | ||||
| Other assets | 412 | ||||
| Deferred income tax asset | 942 | ||||
| Other current assets | 11,080 | ||||
| Accounts payable and accrued expenses | (10,340 | ) | |||
| Asset retirement obligations | (5,639 | ) | |||
| Liabilities from commodity price risk management activities | (2,546 | ) | |||
| Total allocation | $ | 225,085 | |||
The following table reflects the pro forma results of operations for the years ended December 31, 2003 and 2004. The information for the year ended December 31, 2003 has been derived from EXCO's audited consolidated statement of operations for the 209 day period ended July 28, 2003 and our audited consolidated statement of operations for the 156 day period ended December 31, 2003, and North Coast's audited financial statements for the year ended December 31, 2003. 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 following events as if each occurred on January 1 of each respective year.
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During North Coast's year ended December 31, 2003 and the 26 day period from January 1, 2004 to January 26, 2004, there were $1.5 million and $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.
| (in thousands) | For the year ended December 31, 2003 | For the year ended December 31, 2004 | ||||
|---|---|---|---|---|---|---|
| Revenues and other income | $ | 94,954 | $ | 99,544 | ||
| Net income (loss) | $ | (8,262 | ) | $ | 8,306 | |
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.
6. Long-term debt and interim bank loan
Long-term debt is summarized as follows:
| | December 31, | |||||
|---|---|---|---|---|---|---|
| (in thousands) | ||||||
| 2004 | 2005 | |||||
| Notes payable | $ | 34,500 | $ | 1 | ||
| 71/4% senior notes due 2011 | 452,953 | 461,801 | ||||
| Long-term debt | $ | 487,453 | $ | 461,802 | ||
Credit agreements
Credit agreement. At December 31, 2003, our former restated U.S. credit agreement provided for borrowings of up to $124.0 million under a revolving credit facility with a borrowing base of $95.0 million. At December 31, 2003, we had approximately $49.5 million of outstanding indebtedness, letter of credit commitments of $275,000 and approximately $45.2 million available for borrowing.
On January 27, 2004, our credit agreement was amended and restated to provide for borrowings up to $250.0 million with a borrowing base of $120.0 million. The amendment also provided for an extension of the credit agreement maturity date to January 27, 2007. Upon the issuance of the $100.0 million in additional senior notes on April 13, 2004, the credit agreement borrowing base was reduced to $95.0 million. Effective June 28, 2004, the borrowing base was redetermined at $145.0 million. Effective October 8, 2004 and August 12, 2005, the borrowing base was redetermined at $145.0 million, and will be redetermined each May 1 and November 1 thereafter. 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. At December 31, 2004, we had $34.5 million of outstanding indebtedness and letter of credit commitments of $0.3 million and
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approximately $110.2 million available for borrowing. At December 31, 2005, we had $1,000 of outstanding indebtedness under our credit agreement. At December 31, 2005, the six month LIBOR rate was 4.70%, which would result in an interest rate of approximately 5.95% of any new indebtedness we may incur under the credit agreement. Borrowings under our amended and restated credit agreement are collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus .50% plus an applicable margin or (ii) LIBOR (London InterBank Offered Rate) plus an applicable margin. At December 31, 2004 and 2005, the six month LIBOR rate was 2.78% and 4.70%, respectively, which would result in an interest rate of approximately 4.03% and 5.95% on any new indebtedness we may incur under the U.S. credit agreement.
On September 30, 2005, we entered into the Fourth Amendment to the U.S. credit agreement, which amended the credit agreement to, among other things (i) permit the acquisition of Holdings by Holdings II, (ii) adjust the restriction on sales of assets by the borrowers and certain subsidiary guarantors under the credit agreement and the application of the proceeds from such sales of assets and (iii) permit the redemption of our senior notes pursuant to the terms of the indenture. Pursuant to the interim bank loan incurred by Holdings II in connection with the Equity Buyout on October 3, 2005, total advances under our credit agreement could not exceed $10.0 million until the interim bank loan was repaid in full in connection with our initial public offering which closed on February 14, 2006.
Canadian credit agreement. At December 31, 2004, we had approximately $12.9 million of outstanding indebtedness under our Canadian credit agreement (which has been reclassified as Liabilities from discontinued operations on the Consolidated Balance Sheet at December 31, 2004). Borrowings under the Canadian credit agreement were collateralized by a first lien mortgage providing a security interest in 90% of our Canadian oil and natural gas properties. We repaid all outstanding indebtedness under our Canadian credit agreement in full on February 10, 2005 with a portion of the proceeds received from the sale of Addison.
Financial covenants and ratios. Our amended and restated U.S. credit agreement contains certain financial covenants and other restrictions which require that we:
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Additionally, the credit agreements 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 prohibit the payment of dividends on our common stock. At December 31, 2004, we were in compliance with the covenants contained in our U.S. and Canadian credit agreements. At December 31, 2005, we were in compliance with the covenants contained in our U.S. credit agreement.
U.S. senior term loan. On October 17, 2003, we entered into a $50.0 million senior term credit agreement. We borrowed all $50.0 million under the senior term credit agreement and we used the proceeds to repay a portion of our indebtedness under our U.S. credit agreement. The U.S. senior term loan was paid in full on January 27, 2004 from the proceeds of the $350 million senior notes issued on January 20, 2004.
Dividend restrictions. 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 U.S. credit agreement currently prohibits us from paying dividends on our common stock. Even if our U.S. 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.
71/4% senior notes due January 15, 2011
On January 20, 2004, EXCO completed the private placement of $350.0 million aggregate principal amount of 71/4% 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.
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In accordance with the terms of the indenture governing our senior notes, at the time of the closing of the sale of Addison Energy Inc. (See "Note 3. Sale of Addison Energy, Inc."), the security interest of the holders of our senior notes in two-thirds of the common stock of Addison was released and a second lien security interest (behind the first lien security interest under our U.S. credit agreement) was effected in U.S. $120.6 million of cash equivalents, which represents two-thirds of the net cash proceeds from the sale of the Addison stock. An additional U.S. $75.8 million of proceeds from the Addison disposition were applied to temporarily pay down borrowings under our U.S. credit agreement to a nominal amount. The remaining Addison disposition proceeds of U.S. $130.3 million were invested in short-term investments as permitted under our U.S. credit agreement and our senior notes. The net cash proceeds from the Addison disposition as determined under the indenture governing our senior notes was U.S. $326.8 million and may be used only in accordance with the terms of the indenture. The indenture provides that the net cash proceeds from an asset disposition must be used to permanently reduce debt, reinvest in our business or make an offer to the holders to repurchase their senior notes.
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 will be amortized over the remaining life of the senior notes. The unamortized premium was $17.1 million at December 31, 2005. The purchase of the $5.3 million in aggregate principal amount of senior notes tendered to us as discussed above has reduced the premium to be amortized by approximately $202,000.
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The indenture governing the senior notes contains covenants which limit our ability and the ability of certain of our subsidiaries to:
The estimated fair value of our senior notes at December 31, 2005 was $453.6 million as compared to the carrying amount of $461.8 million (including $17.1 million of unamortized premium). The fair value of the senior notes is estimated based on quoted market prices for the senior notes.
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 our common stock. The maturity date of the loan is July 3, 2006, with an interest rate of 10%. The loan agreement contains representations and warranties, covenants and conditions usual for a transaction of this type. Covenants contained in this 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. The interim bank loan could be prepaid, in whole or in part, at the option of Holdings II, at any time upon three days' prior notice.
The interim bank loan is legally in the name of Holdings II. The Equity Buyout resulted in a change of control. GAAP requires the acquisition by Holdings II to be accounted for as a purchase transaction in accordance with SFAS No. 141. In addition, GAAP requires the application of "push down accounting" in situations where the ownership of an entity has changed, meaning that the post transaction financial statements of the acquired entity (EXCO) reflect the new basis of accounting in accordance with SAB 54. In addition to the stepped-up basis resulting from the acquisition, the interim bank loan has been "pushed- down" to EXCO and is presented as a component of consolidated debt.
On February 14, 2006, upon closing of the initial public offering (IPO), the interim bank loan, together with accrued interest was paid in full.
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7. Income taxes
The income tax provision attributable to our income (loss) before income taxes consists of the following:
| | Public Predecessor | Private Predecessor | Successor | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | 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 | |||||||||||||
| Current expenses (benefit): | ||||||||||||||||||
| U.S. | ||||||||||||||||||
| Federal | $ | — | $ | — | $ | — | $ | (3,563 | ) | $ | (7,020 | ) | ||||||
| State | (181 | ) | — | 1,445 | (668 | ) | (1,315 | ) | ||||||||||
| Total current income tax (benefit) | (181 | ) | — | 1,445 | (4,231 | ) | (8,335 | ) | ||||||||||
| Deferred: | ||||||||||||||||||
| U.S. | ||||||||||||||||||
| Federal | — | (2,692 | ) | 4,681 | (49,881 | ) | 12,656 | |||||||||||
| State | — | (131 | ) | (91 | ) | (9,586 | ) | 3,000 | ||||||||||
| Canadian | — | (4,941 | ) | (909 | ) | — | — | |||||||||||
| Total deferred income tax (benefit) | — | (7,764 | ) | 3,681 | (59,467 | ) | 15,656 | |||||||||||
| Total income tax (benefit) | $ | (181 | ) | $ | (7,764 | ) | $ | 5,126 | $ | (63,698 | ) | $ | 7,321 | |||||
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 $7.4 million of the NOLs limited by Section 382 will expire prior to their utilization. Expiration is expected to occur from 2005 through 2019. Accordingly, a valuation allowance of $2.6 million was established to reserve a portion of NOLs in excess of the Section 382 limitations, which we believe will more likely than not expire unutilized. Prior to the Equity Buyout, this valuation allowance and its associated deferred tax asset was written off because it was deemed worthless.
At December 31, 2002, EXCO had a valuation allowance to offset its U.S. deferred tax assets. During the 209 day period from January 1, 2003 to July 28, 2003, we had a U.S. operating loss and accordingly increased our valuation allowance to reflect that loss. As a result of the going private transaction, we were in a deferred tax liability position in the United States at the time of the transaction due to the step up in basis for book purposes related to purchase accounting and the carryover of tax basis. Except for the valuation allowance against NOLs limited by Section 382 described above, no valuation allowance was recognized in the purchase price allocation resulting from
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the going private transaction at December 31, 2003, December 31, 2004, or at the Equity Buyout on October 3, 2005. During the 275 day period from January 1, 2005 to October 2, 2005, the valuation allowance against NOLs limited by Section 382 and its associated deferred tax asset was written off.
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.
For the 156 day period ended December 31, 2003 and for the year ended December 31, 2004, we recognized a deferred income tax benefit of approximately $4.9 million and $0.9 million, respectively, related to Canadian legislation which became effective in November 2003 and May 2004 to phase in reduced income tax rates and allow for deductibility of crown royalties. These amounts have been reflected as income tax benefits in continuing operations pursuant to the provisions of SFAS No. 109 and EITF 93-13 as discussed above.
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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:
| | December 31, | |||||||
|---|---|---|---|---|---|---|---|---|
| | 2004 | 2005 | ||||||
| (in thousands) | Private predecessor | Successor | ||||||
| Current deferred tax assets (liabilities): | ||||||||
| Basis difference in fair value of derivative financial instruments | $ | — | $ | 26,605 | ||||
| Other | (710 | ) | 3,363 | |||||
| Total current deferred tax assets (liabilities) | (710 | ) | 29,968 | |||||
Long-term deferred tax assets: | ||||||||
| Net operating loss carryforwards — U.S | 17,807 | 1,879 | ||||||
| Basis difference in fair value of derivative financial instruments | 13,127 | 34,300 | ||||||
| Credit carryforwards | 5 | — | ||||||
| Purchase accounting adjustment to bond premium | — | 5,456 | ||||||
| Share-based compensation | — | 437 | ||||||
| Other | 1,050 | 3 | ||||||
| Valuation allowance for deferred tax assets | (2,673 | ) | — | |||||
| Total long-term deferred tax assets | $ | 29,316 | $ | 42,075 | ||||
Deferred tax liabilities: | ||||||||
| Book basis of oil and natural gas properties in excess of tax basis — U.S | $ | (36,873 | ) | $ | (176,677 | ) | ||
| Taxes on undistributed earnings of foreign subsidiary — U.S | (8,237 | ) | — | |||||
| Total deferred liabilities | $ | (45,110 | ) | $ | (176,677 | ) | ||
Net noncurrent deferred tax liabilities | $ | (15,794 | ) | $ | (134,602 | ) | ||
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 209 day period from January 1, 2003 to July 28, 2003, the 156 day period from July 29, 2003 to December 31, 2003, for the
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year ended December 31, 2004, 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 is presented in the following table:
| | Public predecessor | Private predecessor | Successor | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | 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 2, 2005 to December 31, 2005 | ||||||||||||
| United States federal income taxes (benefit) at statutory rate of 35% | $ | (2,785 | ) | $ | (2,760 | ) | $ | (5,120 | ) | $ | (70,293 | ) | $ | 8,150 | |||
| Increases (reductions) resulting from: | |||||||||||||||||
| Undistributed earnings of foreign subsidiary | — | — | 8,237 | — | — | ||||||||||||
| Foreign tax items | — | — | — | 644 | (2,996 | ) | |||||||||||
| Change in Canadian tax rates | — | (4,941 | ) | (909 | ) | — | — | ||||||||||
| Change in U.S. tax law related to Canadian dividend | — | — | — | (2,075 | ) | — | |||||||||||
| Adjustments to the valuation allowance | 2,447 | — | — | — | — | ||||||||||||
| Non-deductible compensation | — | — | — | 15,432 | 604 | ||||||||||||
| Non-deductible intercompany foreign interest expense | — | — | 1,840 | — | — | ||||||||||||
| State taxes net of federal benefit | (118 | ) | (85 | ) | 880 | (6,665 | ) | 1,095 | |||||||||
| Other | 275 | 22 | 198 | (741 | ) | 468 | |||||||||||
| Income tax expense (benefit) before cumulative effect of change in accounting principles | $ | (181 | ) | $ | (7,764 | ) | $ | 5,126 | $ | (63,698 | ) | $ | 7,321 | ||||
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8. Stock transactions
Stock options
The following table summarizes EXCO's stock option activity during the period from January 1, 2003 through December 31, 2003:
| | Stock options | Weighted average exercise price per share | ||||
|---|---|---|---|---|---|---|
| Options outstanding at December 31, 2002 | 2,049,831 | $ | 10.85 | |||
| Granted | — | — | ||||
| Expired or canceled | (916,446 | ) | 10.37 | |||
| Exercised | (1,133,385 | ) | 11.24 | |||
| Options outstanding at December 31, 2003(1) | — | $ | — | |||
The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used for the EXCO options included in the above table:
| Fair market value of stock at date of grant | $6.00 to $20.62 | |
| Option exercise prices | $6.00 to $20.62 | |
| Expected life | 4 years | |
| Risk-free rate of return | 10-year U.S. Treasury Notes | |
| Volatility | Based upon daily stock prices from January 1, 2000 through December 31, 2002 | |
| Dividend yield | 0% | |
| Calculated Black-Scholes values | $2.60 to $8.94 per option |
See "Note 2. Summary of significant accounting policies" for a comparison of our net income/(loss) and net income/(loss) per share as reported and as adjusted for the pro forma effects of determining compensation expense in accordance with SFAS No. 123. All outstanding stock options were either exercised prior to or cashed out as a result of the going private transaction.
During the 209 day period from January 1, 2003 to July 28, 2003, EXCO recognized $3.6 million of stock-based compensation expense in general and administrative expense. This amount was paid to option holders at the time of the going private transaction to cancel all unexercised stock options outstanding at that time. The amount represented the cumulative difference between the $18.00 per share proceeds and the exercise price of the outstanding stock options times the number of stock options outstanding.
As an incentive to the management and certain key employees of Addison, the board of directors of Addison established the Addison Energy Inc. stock option plan effective June 30, 2002. Addison stock options were issued as of June 30, 2002, under the plan that, if fully exercised, would allow the participants to own in the aggregate 1,000 shares of Addison common stock, approximately 10% of the shares of common stock in Addison on a fully-diluted basis. The Addison stock options were
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exercisable for a term of five years from the date of the grant. The Addison stock options were subject to vesting. The vesting schedule was as follows:
| Vesting date | Cumulative percent Vested | |
|---|---|---|
| Prior to April 26, 2003 | None | |
| April 26, 2003 | 50% | |
| April 26, 2004 | 75% | |
| April 26, 2005 | 100% |
The exercise price under the Addison stock option plan as of June 30, 2002 was Cdn. $1,031.61 per share. The price was determined by using a formula as set forth in the Addison stock option agreement. The formula was based upon:
This formula was to be calculated as of December 31 of each year, beginning December 31, 2002, to determine the value of each share of Addison's common stock.
If an Addison stock option were exercised, we would be obligated to purchase the shares of Addison common stock from the employee six months later at the then-current price as calculated using the above formula. Each employee receiving an Addison stock option entered into an agreement that restricted their ability to sell or transfer any Addison common stock acquired under the Addison stock option plan to any party other than to us.
The Addison stock options became fully vested and exercisable if any of the following occurs:
The going private transaction was a triggering event under the Addison stock option plan. We calculated the value of each share of Addison common stock as of the date of the event to be Cdn. $10,014.50 per share. We paid approximately Cdn. $9.0 million in cash to the holders of the
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Addison stock options, which represented the difference between the calculated value per share and the Addison stock option exercise price times the number of shares of Addison common stock that the participant had the right to purchase under the Addison stock option plan.
The value of a share of Addison common stock was calculated to be Cdn. $7,013.94 per share as of December 31, 2002. The following table summarizes our Addison stock option activity:
| | Stock options | Weighted average exercise price per share | ||||
|---|---|---|---|---|---|---|
| Options outstanding at December 31, 2002 | 1,000 | Cdn. $ | 1,031.61 | |||
| Granted | — | — | ||||
| Expired or canceled | 1,000 | Cdn. $ | 1,031.64 | |||
| Exercised | — | — | ||||
| Options outstanding at December 31, 2003 | — | — | ||||
During the 209 day period from January 1, 2003 to July 28, 2003, U.S. $5.5 million of stock-based compensation expense for the Addison stock option plan has been recognized in income from discontinued operations.
As discussed in Note 2. Summary of significant accounting policies, certain of our employees have been granted Holdings stock options under the Holdings Plan. The following table summarizes Holdings stock option activity under the Holdings Plan:
| | Stock options | Weighted average exercise price per share | ||||
|---|---|---|---|---|---|---|
| Options outstanding at December 31, 2003 | — | — | ||||
| Granted | 8,801,354 | $ | 3.00 | |||
| Expired or canceled | — | — | ||||
| Exercised | — | — | ||||
| Options outstanding at December 31, 2004 | 8,801,354 | $ | 3.00 | |||
| Granted | 194,630 | $ | 3.57 | |||
| Expired or canceled | 324,078 | $ | 3.00 | |||
| Exercised | — | — | ||||
| Cash-out in connection with Equity Buyout | 8,671,906 | $ | 3.01 | |||
| Options outstanding at October 3, 2005 | — | — | ||||
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 Holdings (formerly Holdings II) common stock. From October 5, 2005 to December 31, 2005,
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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. The options expire ten years following the date of grant and have a weighted average remaining life of 9.75 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, 2005, there were 5,026,925 shares available to be granted under the Plan.
The following table summarizes Holdings stock option activity related to our employees under the 2005 Incentive Plan:
| | Stock options | Weighted average exercise price per share | ||||
|---|---|---|---|---|---|---|
| Options outstanding at October 3, 2005 | — | — | ||||
| Granted | 4,992,650 | $ | 7.50 | |||
| Expired or canceled | 19,575 | $ | 7.50 | |||
| Exercised | — | — | ||||
| Options outstanding at December 31, 2005 | 4,973,075 | $ | 7.50 | |||
| Options exercisable at December 31, 2005 | 1,244,113 | $ | 7.50 | |||
The present value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. The following assumptions were used for the Holdings options included in the above table:
| Fair market value of stock at date of grant | $7.50 | |
| Option exercise prices | $7.50 | |
| Expected life | 4 years | |
| Risk-free rate of return | 10-year U.S. Treasury Notes | |
| Volatility | 30.4% | |
| Dividend yield | 0% | |
| Calculated Black-Scholes values | $2.29 per option |
As required by SFAS 123(R), the granting of options under the 2005 Incentive Plan by Holdings 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 Public Predecessor for 1.25 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 was $3.2 million, of which $2.2 million is included in general and administrative expense and $1.0 million was capitalized as part of proved developed and undeveloped oil and natural gas properties, as discussed in "Note 2. Summary of significant accounting policies." Total share-based compensation to be recognized on unvested awards is $7.5 million over a weighted average period of 2.83 years.
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Issuance of preferred stock
EXCO was authorized to issue up to 10,000,000 shares of preferred stock, $.01 par value per share. On June 29, 2001, EXCO closed its rights offering to existing shareholders that resulted in the sale of 5,004,869 shares of 5% convertible preferred stock at $21.00 per share. EXCO raised a total of approximately $105.1 million in gross proceeds (approximately $101.2 million in net proceeds after fees and commissions), through the exercise of 4,466,869 rights and the sale of 538,000 shares of 5% convertible preferred stock by dealer managers. We applied approximately $97.6 million of the offering proceeds to pay-off its bank loans and used the remaining proceeds for general corporate purposes. Dividends on the 5% convertible preferred stock were payable quarterly in cash and the dividend payment was approximately $1.3 million per quarter beginning September 30, 2001. Preferred stock dividends of approximately $2.7 million, $5.3 million and $2.6 million were paid during the years ended December 31, 2001 and 2002 and for the 209 day period from January 1, 2003 to July 28, 2003. Each share of 5% convertible preferred stock was converted into one share of common stock on or before June 30, 2003.
In July 2003, Holdings issued 115.9 million of its Class A common stock valued at $1.50 per share to institutional investors, members of EXCO's management and key employees, and other investors in exchange for cash, shares of EXCO common stock and, in the case of certain members of management and key employees, notes receivable. Also in July 2003, Holdings issued 11.9 million shares of Class B common stock valued at $0.001 per share to members of management and key employees for cash. The shareholder agreement governing the Class A and Class B common stock provided that, upon the occurrence of certain specified events, including a change in control as occurred upon the Equity Buyout, the Class A common stock was entitled to receive the first $175.0 million upon the sale or liquidation of Holdings. Thereafter, the Class A and Class B common stock shared all proceeds on a pro-rata basis. As discussed in Note 1. Organization, the Class B common stock was considered to be a "variable" plan for financial accounting 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.
9. 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 $155,000, $59,000, $404,000, $423,000 and $95,000 for the 209 day period from January 1, 2003 to July 28, 2003, for the 156 day period from July 29, 2003 to December 31, 2003, for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005 and for the 90 day period from October 3, 2005 to December 31, 2005, respectively, have been included as general and administrative expense.
10. Commitments and contingencies
We lease our offices and certain equipment. Our rental expenses were approximately $0.3 million, $0.2 million, $0.6 million, $0.6 million, and $0.2 million for the 209 day period from January 1, 2003 to July 28, 2003, for the 156 day period from July 29, 2003 to December 31, 2003, for the year ended December 31, 2004, for the 275 day period from January 1, 2005 to October 2, 2005, and the 90 day
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period from October 3, 2005 to December 31, 2005, respectively. Our future minimum rental payments under operating leases with remaining noncancellable lease terms at December 31, 2005, are as follows:
On November 4, 2005, we entered into an agreement with a contract drilling company which commits us to utilize, or to pay for if not utilized, the use of three drilling rigs in east Texas until December 31, 2007. As of December 31, 2005, the minimum amount that we are obligated to pay under the contract is $25.2 million.
| (in thousands) | Amount | ||
|---|---|---|---|
| 2006 | $ | 3,284 | |
| 2007 | 3,141 | ||
| 2008 | 3,067 | ||
| 2009 | 3,545 | ||
| 2010 | 771 | ||
| Thereafter | 856 | ||
| $ | 14,664 | ||
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. However, future costs associated with legal proceedings may be material to our operating results and liquidity.
11. 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.
12. Geographic operating segment information and oil and natural gas disclosures
We have operations in only one industry segment, that being the oil and natural gas exploration and production industry; however, we are organizationally structured along geographic operating segments. We have geographic operating segments in the United States and, until February 10, 2005, in Canada. Upon the acquisition of North Coast during 2004, our geographic operating segments in the United States were EXCO (excluding Appalachia) and Appalachia. The following tables provide our geographic operating segment data.
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The following table presents total capitalized costs of proved and unproved properties, accumulated depreciation, depletion and amortization related to oil and natural gas production, and total assets excluding information relating to Addison:
| | Private predecessor | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | EXCO (excluding Appalachia) | Appalachia | Total | |||||||
| As of December 31, 2004: | ||||||||||
| Oil and natural gas properties, including proved and unproved leasehold | $ | 206,356 | $ | 266,801 | $ | 473,157 | ||||
| Accumulated depreciation, depletion and amortization | (18,689 | ) | (13,018 | ) | (31,707 | ) | ||||
| Oil and natural gas properties, net | $ | 187,667 | $ | 253,783 | $ | 441,450 | ||||
| Goodwill | $ | 19,984 | $ | — | $ | 19,984 | ||||
| Total assets | $ | 241,032 | $ | 299,258 | $ | 540,290 | ||||
Successor | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| As of December 31, 2005: | ||||||||||
| Oil and natural gas properties, including proved and unproved leasehold | $ | 336,250 | $ | 590,466 | $ | 926,716 | ||||
| Accumulated depreciation, depletion and amortization | (5,473 | ) | (7,808 | ) | (13,281 | ) | ||||
| Oil and natural gas properties, net | $ | 330,777 | $ | 582,658 | $ | 913,435 | ||||
| Goodwill | $ | 76,786 | $ | 143,220 | $ | 220,006 | ||||
| Total assets | $ | 667,172 | $ | 840,465 | $ | 1,507,637 | ||||
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The results of operations from our oil and natural gas producing activities, excluding information relating to Addison, are as follows:
| | Public predecessor | Private predecessor | ||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | For the 209 day period from January 1, 2003 to July 28, 2003 | For the 156 day period from July 29, 2003 to December 31, 2003 | ||||||
| Oil and natural gas sales | $ | 22,403 | $ | 21,767 | ||||
| Commodity price risk management activities | — | (10,800 | ) | |||||
| Other loss | (1,129 | ) | (161 | ) | ||||
| Total revenues and other income | 21,274 | 10,806 | ||||||
| Production costs | 11,380 | 7,331 | ||||||
| Depreciation, depletion and amortization | 5,125 | 5,413 | ||||||
| Accretion of discount on asset retirement obligations | 320 | 205 | ||||||
| General and administrative | 11,347 | 3,823 | ||||||
| Interest | 1,058 | 1,921 | ||||||
| Total costs and expenses | 29,230 | 18,693 | ||||||
| Loss before income taxes, discontinued operations and cumulative effect of change in accounting principle | (7,956 | ) | (7,887 | ) | ||||
| Income tax benefit(1) | (181 | ) | (7,764 | ) | ||||
| Loss before discontinued operations and cumulative effect of change in accounting principle | $ | (7,775 | ) | $ | (123 | ) | ||
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| | Private predecessor | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | EXCO (excluding Appalachia) | Appalachia | Total | ||||||||
| Year ended December 31, 2004: | |||||||||||
| Oil and natural gas sales | $ | 67,003 | $ | 74,990 | $ | 141,993 | |||||
| Commodity price risk management activities | (18,055 | ) | (32,288 | ) | (50,343 | ) | |||||
| Other income | 402 | 739 | 1,141 | ||||||||
| Total revenues and other income | 49,350 | 43,441 | 92,791 | ||||||||
| Production costs | 16,893 | 11,363 | 28,256 | ||||||||
| Depreciation, depletion and amortization | 13,941 | 14,578 | 28,519 | ||||||||
| Accretion expense | 425 | 375 | 800 | ||||||||
| General and administrative | 11,413 | 3,862 | 15,275 | ||||||||
| Interest | 30,434 | 4,136 | 34,570 | ||||||||
| Total costs and expenses | 73,106 | 34,314 | 107,420 | ||||||||
| Income (loss) before income taxes and discontinued operations | (23,756 | ) | 9,127 | (14,629 | ) | ||||||
| Income tax expense(1) | 505 | 4,621 | 5,126 | ||||||||
| Income (loss) from continuing operations | $ | (24,261 | ) | $ | 4,506 | $ | (19,755 | ) | |||
| | Private predecessor | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | EXCO (excluding Appalachia) | Appalachia | Total | |||||||||
| For the 275 day period from January 1, 2005 to October 2, 2005: | ||||||||||||
| Revenues and other income: | ||||||||||||
| Oil and natural gas | $ | 55,177 | $ | 77,644 | $ | 132,821 | ||||||
| Commodity price risk management activities | (56,705 | ) | (120,548 | ) | (177,253 | ) | ||||||
| Other income | 5,806 | 1,269 | 7,075 | |||||||||
| Total revenues and other income | 4,278 | (41,635 | ) | (37,357 | ) | |||||||
| Costs and expenses: | ||||||||||||
| Oil and natural gas production | 11,407 | 10,750 | 22,157 | |||||||||
| Depreciation, depletion and amortization | 11,355 | 13,332 | 24,687 | |||||||||
| Accretion of discount on asset retirement obligations | 277 | 340 | 617 | |||||||||
| General and administrative | 79,219 | 10,125 | 89,344 | |||||||||
| Interest | 26,675 | — | 26,675 | |||||||||
| Total costs and expenses | 128,933 | 34,547 | 163,480 | |||||||||
| Loss from continuing operations before income taxes | (124,655 | ) | (76,182 | ) | (200,837 | ) | ||||||
| Income tax benefit | (21,538 | ) | (42,160 | ) | (63,698 | ) | ||||||
| Loss from continuing operations | $ | (103,117 | ) | $ | (34,022 | ) | $ | (137,139 | ) | |||
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Successor | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | EXCO (excluding Appalachia) | Appalachia | Total | |||||||||
| For the 90 day period from October 3, 2005 to December 31, 2005: | ||||||||||||
| Revenues and other income: | ||||||||||||
| Oil and natural gas | $ | 23,271 | $ | 46,790 | $ | 70,061 | ||||||
| Commodity price risk management activities | 2,856 | (3,112 | ) | (256 | ) | |||||||
| Interest and other income | 1,849 | 516 | 2,365 | |||||||||
| Total revenues and other income | 27,976 | 44,194 | 72,170 | |||||||||
| Costs and expenses: | ||||||||||||
| Oil and natural gas production | 4,569 | 4,380 | 8,949 | |||||||||
| Depreciation, depletion and amortization | 5,689 | 8,382 | 14,071 | |||||||||
| Accretion of discount on asset retirement obligations | 84 | 142 | 226 | |||||||||
| General and administrative | 4,838 | 1,387 | 6,225 | |||||||||
| Interest | 19,414 | — | 19,414 | |||||||||
| Total costs and expenses | 34,594 | 14,291 | 48,885 | |||||||||
| Income (loss) from continuing operations before income taxes | (6,618 | ) | 29,903 | 23,285 | ||||||||
| Income tax expense (benefit) | (3,415 | ) | 10,736 | 7,321 | ||||||||
| Income (loss) from continuing operations | $ | (3,203 | ) | $ | 19,167 | $ | 15,964 | |||||
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13. 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. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results from the hedged item on the income statement. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings in our public predecessor basis financial statements. Prior to July 29, 2003, all of EXCO's derivative financial instruments were designated as cash flow hedges. Beginning July 29, 2003, the date of the going private transaction, 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.
EXCO entered into several swap transactions during 2000 and 2001 with Enron North America Corp., an affiliate of Enron Corp. (the Enron Hedges). On December 2, 2001, Enron Corp. and other Enron related entities, including Enron North America, filed for bankruptcy under Chapter 11 of the United States Code in the United States Bankruptcy Court in the Southern District of New York. We terminated all of our hedging contracts with Enron North America, effective as of December 5, 2001. We believe that we were owed approximately $15.3 million, including settlements already due but not paid, but the exact amount of the claim was determined pursuant to the terms of the ISDA Master Agreement. In connection with the going private transaction, we valued the Enron derivative asset at $2.8 million, which represented our estimate of the fair market value of our bankruptcy claim against Enron North America. Our estimate of the value of our bankruptcy claim was based upon informal offers that we received from third parties attempting to purchase those claims as well as management's best estimate of the financial condition of Enron's bankruptcy estate as determined from published reports and court filings related to the bankruptcy. Our claim was sold to a third party in April 2004 for approximately $4.7 million. The difference between the $4.7 million received for the claim and the $2.8 million derivative asset was treated as a purchase price adjustment for the going private transaction. As a result, we reduced goodwill by $1.2 million and increased deferred income taxes payable by $0.7 million.
The following table sets forth our oil and natural gas derivatives as of December 31, 2005. The fair values at December 31, 2005 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, 2005. We
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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.
| (in thousands, except prices) | Volume Mmbtus/Bbls | Weighted average strike price per Mmbtu/Bbl | Fair value at December 31, 2005 | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Natural gas: | |||||||||
| Swaps: | |||||||||
| 2006 | 14,418 | $ | 6.93 | $ | (54,107 | ) | |||
| 2007 | 12,410 | 6.58 | (42,560 | ) | |||||
| 2008 | 10,980 | 7.62 | (16,860 | ) | |||||
| 2009 | 1,825 | 4.51 | (6,267 | ) | |||||
| 2010 | 1,825 | 4.51 | (5,025 | ) | |||||
| 2011 | 1,825 | 4.51 | (4,149 | ) | |||||
| 2012 | 1,830 | 4.51 | (3,627 | ) | |||||
| 2013 | 1,825 | 4.51 | (3,233 | ) | |||||
| Total Natural Gas | 46,938 | (135,828 | ) | ||||||
| Oil: | |||||||||
| Swaps: | |||||||||
| 2006 | 237 | 67.04 | 918 | ||||||
| 2007 | 201 | 64.99 | 214 | ||||||
| 2008 | 183 | 63.00 | 101 | ||||||
| Total Oil | 621 | 1,233 | |||||||
| Total Oil and Natural Gas | $ | (134,595 | ) | ||||||
At December 31, 2005, the average forward NYMEX oil prices per Bbl for calendar 2006 and 2007 were $63.19 and $63.98, respectively, and the average forward NYMEX natural gas prices per Mmbtu for calendar 2006 and 2007 were $10.77 and $10.26, 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.
14. Acquisitions and dispositions
Significant transactions that occurred during 2003
During the 209 day period from January 1, 2003 to July 28, 2003, we completed several oil and natural gas property acquisitions in the United States. The total purchase price for the acquisitions was approximately $1.8 million funded from surplus cash. During this period, we sold our interest in several oil and natural gas properties in the United States for total sales proceeds of approximately $6.1 million.
During the 156 day period from July 29, 2003 to December 31, 2003, we completed several oil and natural gas property acquisitions in the United States. The total purchase price for the acquisitions was
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approximately $14.4 million funded with borrowings under our Canadian credit agreement and from surplus cash. The most significant purchase during this period was the acquisition of additional interests in certain natural gas properties that we operate in the United States that we closed in October 2003. As of October 1, 2003, estimated total Proved Reserves net to our interest from these properties included approximately 19.8 Bcf of natural gas. The total purchase price for the properties was approximately $13.9 million (after contractual adjustments).
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. Estimated total Proved Reserves net to our interest from these acquisitions included approximately 0.3 Mmbbls of oil and NGLs and 52.1 Bcf of natural gas. The total purchase price for the acquisitions was approximately $88.4 million funded with borrowings under our U.S. credit agreement and from surplus cash. During 2004, since the date of the respective acquisitions, we recorded revenue of approximately $3.7 million and oil and natural gas production costs of $0.6 million on these properties.
During the year ended December 31, 2004, we completed 21 sales of oil and natural gas properties in the United States. As of January 1, 2004, estimated total Proved Reserves, net to our interest from these properties included approximately 5.2 Mmbbls of oil and NGLs and 27.9 Bcf of natural gas. The total sales proceeds we received were approximately $51.9 million. During 2003, we recorded revenue of approximately $16.3 million and oil and natural gas production costs of $6.9 million on these properties. During 2004, we recorded revenue of approximately $12.1 million and oil and natural gas production costs of $4.6 million on these properties through the date of their respective disposition.
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. Estimated total Proved Reserves net to our interest from the acquisitions included approximately 0.1 Mmbbls of oil and 59.8 Bcf of natural gas. 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 $45.3 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.
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Pro forma financial information has not been provided because the acquisitions, other than North Coast, and dispositions, other than Addison, were not material.
15. Bonus retention program
In connection with the going private transaction, Holdings established a bonus retention program 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. The first payments under the program were made on October 29, 2003. During the 156 day period from July 29, 2003 to December 31, 2003, and for the year ended December 31, 2004, we have included approximately $0.6 million and $1.4 million, respectively, in general and administrative expense and $0.2 million and $0.4 million, respectively, 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.
16. Concentration of credit risk
During 2005, sales of natural gas to an industrial customer accounted for 10.1% 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.
During 2004, sales of natural gas to an industrial customer accounted for 10.6% of our total oil and natural gas revenues. For the 209 day period from January 1, 2003 to July 28, 2003, sales of oil to Plains All American, Inc. and affiliates accounted for approximately 14.0% of total revenues. Sales to Western Gas Resources accounted for approximately 10.0% of total revenues for the same 209 day period. For the 156 day period from July 29, 2003 to December 31, 2003, sales to ONEOK Gas Marketing, Inc., Plains All American, Inc., and Western Gas Resources accounted for 10.0%, 13.2%, and 12.7% of total revenues, respectively.
17. Related party transactions
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
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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 $642.9 million. 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 is an obligor or guarantor with respect to these financings; however, Holdings has pledged its stock in TXOK as collateral security for payment of the TXOK credit facility and the TXOK term loan.
On October 7, 2005, EXCO advanced $4.0 million to Holdings (formerly Holdings II), which was used to partially fund an additional $20.0 million investment in TXOK Class B common stock by Holdings. 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 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. 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 (See "Note 18. Subsequent Events"). 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. At December 31, 2005, Holdings accounted for its investment in TXOK using the cost method of accounting.
Effective October 15, 2005, we entered into an agreement with TXOK to manage TXOK's business affairs. Mr. Pickens controls TXOK through BP EXCO Holdings LP's ownership of the TXOK preferred stock. The agreement provides that we will provide TXOK with general management, treasury, finance, legal, audit, tax, information technology, and payroll and benefit administration services. TXOK has 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 has 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 ONOEK and historically worked on these assets. TXOK reimburses 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.
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18. Subsequent Events
On February 8, 2006, our registration statement on Form S-1, as amended, was declared effective by the SEC, which allowed for the issuance of 50,000,000 shares of our $0.001 par value common stock at an initial offering price of $13.00 per share. Net proceeds from the offering after underwriting discount, but before other expenses, which closed on February 14, 2006, were approximately $617.5 million. Concurrent with the closing of the IPO, Holdings was merged into and with us and we became the surviving company. Each share of stock and stock options of Holdings was automatically converted into an equal number of like securities of EXCO.
We granted the underwriters of our IPO an over-allotment option, exercisable for 30 days from the effective date of our IPO, to purchase an aggregate of 7,500,000 additional shares of Common Stock (Option Shares) at $12.35 per share. On February 21, 2006, the underwriters exercised their option for the purchase of 3,615,200 shares of our Common Stock for net proceeds of approximately $44.7 million.
The net proceeds from the IPO, including the funds received from the over-allotment option, together with cash on hand and additional borrowings under the U.S. Credit Agreement, were used to:
Concurrent with the Closing of the IPO, including the redemption of the TXOK Preferred Stock, Holdings, our parent, merged with and into us, with EXCO being the surviving corporation. The outstanding shares of Holdings stock were cancelled as a result of the merger and such shares were exchanged for the same number of shares of our Common Stock. As a result of the merger, TXOK became a wholly-owned subsidiary of EXCO and TXOK and its subsidiaries became guarantors under EXCO's senior notes Indenture. EXCO also became a guarantor of certain collateralized revolving indebtedness of TXOK and TXOK likewise agreed to guarantee EXCO's collateralized revolving credit facility.
The TXOK Credit Facility is a $500.0 million revolving credit facility, subject to a semi-annually determined borrowing base. The initial borrowing base is $325.0 million, of which approximately $308.8 million was drawn down by TXOK to acquire ONEOK Energy Resources Company and ONEOK Energy Resources Holdings, L.L.C. As a result of the pay-down following the IPO, the outstanding balance was approximately $137.0 million plus accrued and unpaid interest.
80
The TXOK Credit Facility bears interest at a fluctuating rate of interest which is a variable margin in excess of reference rates based on either the prime rate or LIBOR. The margin increases with the borrowing base usage under the TXOK Credit Facility. The TXOK Credit Facility matures September 27, 2009 and is collateralized by a first priority lien and security interest in TXOK's oil and natural gas properties as well as the capital stock of its subsidiaries. The TXOK Credit Facility is guaranteed by all existing and future direct or indirect material domestic subsidiaries of TXOK as well as by EXCO and its subsidiaries.
The TXOK Credit Facility financial covenants include, among other covenants, the following:
On February 14, 2006, EXCO entered into the Sixth Amendment (Sixth Amendment) to its Credit Agreement. The Sixth Amendment permits the Borrowers to guarantee the debt and other obligations of TXOK under the TXOK Credit Facility. Upon consummation of the IPO, EXCO's access under the Credit Agreement to its full borrowing base of $145.0 million was restored.
On March 17, 2006, our U.S. credit agreement was amended to combine the TXOK credit facility into our credit agreement resulting in a new borrowing base of $750.0 million reflecting the addition of the TXOK assets. TXOK and its subsidiaries have become guarantors of our credit agreement. The amendment also provided for an extension of the credit agreement maturity date to December 31, 2010. The borrowing base will be redetermined each November 1 and May 1 thereafter. 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.
Borrowings under our amended and restated credit agreement were collateralized by a first lien mortgage providing a security interest in 90% of our U.S. oil and natural gas properties including North Coast. As of March 17, 2006, borrowings are now 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, (ii) the borrowing base or (iii) $300.0 million. The Aggregate Commitment minimum of $300.0 million can be raised, from time to time, up to borrowing base of $750.0 million at our sole discretion. At our election, interest on borrowings may be (i) the greater of the administrative agent's prime rate or the federal funds effective rate plus 0.50% plus an applicable margin or (ii) LIBOR plus an applicable margin.
On February 27, 2006, we entered into a revision of our office space lease in Dallas, Texas. This revision extends our lease two years to June 30, 2013 and obligates us to an additional $1.2 million of future minimum rental payments.
19. Consolidating Financial Statements (unaudited)
Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiary. The senior notes are jointly and severally guaranteed by
81
our current and 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 Subsidaries. Addison was not a guarantor of the senior notes. Instead, the notes were collateralized, subject to specified permitted liens and except as described below, by a second-priority security interest in 65% of the capital stock of Addison. This share pledge is limited such that, at any time, the aggregate par value, book value as carried by us or market value (whichever is greatest) of such pledged capital stock is not equal to or greater than 20% of then outstanding aggregate principal amount of the notes.
The following financial information presents consolidating financial statements, which include:
Rojo Pipeline, Inc., EXCO Investment I, LLC, and EXCO Investment II, LLC are guarantors of the senior notes. These companies have no material operations and, accordingly, these companies have been omitted from the guarantor financial information. 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.
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EXCO RESOURCES, INC.
CONSOLIDATING BALANCE SHEET (Unaudited)
December 31, 2004
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiary | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Assets | ||||||||||||||||
| Current assets: | ||||||||||||||||
| Cash and cash equivalents | $ | 8,535 | $ | 7,472 | $ | — | $ | — | $ | 16,007 | ||||||
| Other current assets | 12,132 | 12,902 | — | — | 25,034 | |||||||||||
| Current assets of discontinued operations | — | — | 34,807 | — | 34,807 | |||||||||||
| Total current assets | 20,667 | 20,374 | 34,807 | — | 75,848 | |||||||||||
Oil and natural gas properties (full cost accounting method): | ||||||||||||||||
| Unproved oil and natural gas properties | 783 | 18,046 | — | — | 18,829 | |||||||||||
| Proved developed and undeveloped oil and natural gas properties | 70,569 | 383,759 | — | — | 454,328 | |||||||||||
| Allowance for depreciation, depletion and amortization | (9,592 | ) | (22,115 | ) | — | — | (31,707 | ) | ||||||||
| Oil and natural gas properties, net | 61,760 | 379,690 | — | — | 441,450 | |||||||||||
| Gas gathering, office and field equipment, net | 1,935 | 25,079 | — | — | 27,014 | |||||||||||
| Goodwill | 19,984 | — | — | — | 19,984 | |||||||||||
| Investments in and advances to affiliates | 658,198 | — | — | (658,198 | ) | — | ||||||||||
| Assets of discontinued operations | — | — | 346,926 | — | 346,926 | |||||||||||
| Other assets, net | 10,779 | 22 | — | — | 10,801 | |||||||||||
| Total assets | $ | 773,323 | $ | 425,165 | $ | 381,733 | $ | (658,198 | ) | $ | 922,023 | |||||
Liabilities and Stockholder's Equity | ||||||||||||||||
| Current liabilities | $ | 60,807 | $ | 10,284 | $ | — | $ | — | $ | 71,091 | ||||||
| Current liabilities of discontinued operations | — | — | 34,604 | — | 34,604 | |||||||||||
| Long-term debt | 487,453 | — | — | — | 487,453 | |||||||||||
| Deferred income taxes | 7,448 | 8,346 | — | — | 15,794 | |||||||||||
| Other liabilities | 30,532 | 6,963 | — | — | 37,495 | |||||||||||
| Payable to parent | (16,668 | ) | 118,564 | 191,702 | (293,598 | ) | — | |||||||||
| Liabilities of discontinued operations | — | — | 71,835 | — | 71,835 | |||||||||||
| Commitments and contingencies | — | — | — | — | — | |||||||||||
| Stockholder's equity | 203,751 | 281,008 | 83,592 | (364,600 | ) | 203,751 | ||||||||||
| Total liabilities and stockholder's equity | $ | 773,323 | $ | 425,165 | $ | 381,733 | $ | (658,198 | ) | $ | 922,023 | |||||
83
EXCO RESOURCES, INC.
CONSOLIDATING BALANCE SHEET (Unaudited)
December 31, 2005
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiary | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Assets | ||||||||||||||||
| Current assets: | ||||||||||||||||
| Cash and cash equivalents | $ | 189,537 | $ | 35,454 | $ | — | $ | — | $ | 224,991 | ||||||
| Other current assets | 67,777 | 47,738 | — | — | 115,515 | |||||||||||
| Total current assets | 257,314 | 83,192 | — | — | 340,506 | |||||||||||
Oil and natural gas properties (full cost accounting method): | ||||||||||||||||
| Unproved oil and natural gas properties | 49 | 53,072 | — | — | 53,121 | |||||||||||
| Proved developed and undeveloped oil and natural gas properties | 94,872 | 778,723 | — | — | 873,595 | |||||||||||
| Allowance for depreciation, depletion and amortization | (1,650 | ) | (11,631 | ) | — | — | (13,281 | ) | ||||||||
| Oil and natural gas properties, net | 93,271 | 820,164 | — | — | 913,435 | |||||||||||
| Gas gathering, office and field equipment, net | 2,423 | 30,848 | — | — | 33,271 | |||||||||||
| Goodwill | 76,786 | 143,220 | — | — | 220,006 | |||||||||||
| Investments in and advances to affiliates | 891,817 | — | — | (891,817 | ) | — | ||||||||||
| Other assets, net | — | 419 | — | — | 419 | |||||||||||
| Total assets | $ | 1,321,611 | $ | 1,077,843 | $ | — | $ | (891,817 | ) | $ | 1,507,637 | |||||
Liabilities and Stockholder's Equity | ||||||||||||||||
| Current liabilities | $ | 418,833 | $ | 52,546 | $ | — | $ | — | $ | 471,379 | ||||||
| Long term debt | 461,802 | — | — | — | 461,802 | |||||||||||
| Deferred income taxes | 33,842 | 100,761 | — | — | 134,603 | |||||||||||
| Other liabilities | 56,975 | 40,197 | — | — | 97,172 | |||||||||||
| Payable to Parent | 7,478 | 371,199 | — | (378,677 | ) | — | ||||||||||
| Commitments and contingencies | — | — | — | — | — | |||||||||||
| Stockholder's equity | 342,681 | 513,140 | — | (513,140 | ) | 342,681 | ||||||||||
| Total liabilities and stockholder's equity | $ | 1,321,611 | $ | 1,077,843 | $ | — | $ | (891,817 | ) | $ | 1,507,637 | |||||
84
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
For the 209 day period ended July 28, 2003
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues and other income: | ||||||||||||||||
| Oil and natural gas sales | $ | 7,502 | $ | 14,901 | $ | — | $ | — | $ | 22,403 | ||||||
| Other income (loss) | (1,129 | ) | — | — | — | (1,129 | ) | |||||||||
| Equity in earnings of subsidiaries | 18,068 | — | — | (18,068 | ) | — | ||||||||||
| Total revenues and other income | 24,441 | 14,901 | — | (18,068 | ) | 21,274 | ||||||||||
Costs and expenses: | ||||||||||||||||
| Oil and natural gas production | 7,361 | 4,019 | — | — | 11,380 | |||||||||||
| Depreciation, depletion and amortization | 3,158 | 1,967 | — | — | 5,125 | |||||||||||
| Accretion of discount on asset retirement obligations | 240 | 80 | — | — | 320 | |||||||||||
| General and administrative | 11,347 | — | — | — | 11,347 | |||||||||||
| Interest | 1,058 | — | — | �� | — | 1,058 | ||||||||||
| Total costs and expenses | 23,164 | 6,066 | — | — | 29,230 | |||||||||||
Income (loss) before income taxes | 1,277 | 8,835 | — | (18,068 | ) | (7,956 | ) | |||||||||
| Income tax expense (benefit) | (181 | ) | — | — | — | (181 | ) | |||||||||
| Income (loss) before discontinued operations and cumulative effect of change in accounting principles | 1,458 | 8,835 | — | (18,068 | ) | (7,775 | ) | |||||||||
| Discontinued operations: | ||||||||||||||||
| Income from operations | — | — | 13,534 | — | 13,534 | |||||||||||
| Income tax expense | — | — | 4,982 | — | 4,982 | |||||||||||
| Income from discontinued operations, net of tax | — | — | 8,552 | — | 8,552 | |||||||||||
| Income before cumulative effect of change in accounting principle | 1,458 | 8,835 | 8,552 | (18,068 | ) | 777 | ||||||||||
| Cumulative effect of change in accounting principle, net of income tax | (426 | ) | (135 | ) | 816 | — | 255 | |||||||||
| Net income | $ | 1,032 | $ | 8,700 | $ | 9,368 | $ | (18,068 | ) | $ | 1,032 | |||||
85
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
For the 156 day period ended December 31, 2003
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues and other income: | ||||||||||||||||
| Oil and natural gas sales | $ | 13,939 | $ | 7,828 | $ | — | $ | — | $ | 21,767 | ||||||
| Commodity price risk management activities | (10,800 | ) | — | — | — | (10,800 | ) | |||||||||
| Other loss | (161 | ) | — | — | — | (161 | ) | |||||||||
| Equity in earnings of subsidiaries | 7,807 | — | — | (7,807 | ) | — | ||||||||||
| Total revenues and other income | 10,785 | 7,828 | — | (7,807 | ) | (7,807 | ) | |||||||||
Costs and expenses: | ||||||||||||||||
| Oil and natural gas production | 5,219 | 2,112 | — | — | 7,331 | |||||||||||
| Depreciation, depletion and amortization | 3,251 | 2,162 | — | — | 5,413 | |||||||||||
| Accretion of discount on asset retirement obligations | 158 | 47 | — | — | 205 | |||||||||||
| General and administrative | 3,823 | — | — | — | 3,823 | |||||||||||
| Interest | 1,921 | — | — | — | 1,921 | |||||||||||
| Total costs and expenses | 14,372 | 4,321 | — | — | 18,693 | |||||||||||
| Income (loss) before income taxes | (3,587 | ) | 3,507 | — | (7,807 | ) | (7,887 | ) | ||||||||
| Income tax benefit | (7,764 | ) | — | — | — | (7,764 | ) | |||||||||
| Income before discontinued operations: | 4,177 | 3,507 | — | (7,807 | ) | (123 | ) | |||||||||
| Discontinued operations: | ||||||||||||||||
| Income from operations | — | — | 6,217 | — | 6,217 | |||||||||||
| Income tax expense | — | — | 1,917 | — | 1,917 | |||||||||||
| Income from discontinued operations, net of tax | — | — | 4,300 | — | 4,300 | |||||||||||
| Net income | $ | 4,177 | $ | 3,507 | $ | 4,300 | $ | (7,807 | ) | $ | 4,177 | |||||
86
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
For the year ended December 31, 2004
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues and other income: | ||||||||||||||||
| Oil and natural gas sales | $ | 39,993 | $ | 102,000 | $ | — | $ | — | $ | 141,993 | ||||||
| Commodity price risk management activities | (18,055 | ) | (32,288 | ) | — | — | (50,343 | ) | ||||||||
| Other income (loss) | 4,262 | 877 | — | (3,998 | ) | 1,141 | ||||||||||
| Equity in earnings of subsidiaries | 41,164 | — | — | (41,164 | ) | — | ||||||||||
| Total revenues and other income | 67,364 | 70,589 | — | (45,162 | ) | 92,791 | ||||||||||
Costs and expenses: | ||||||||||||||||
| Oil and natural gas production | 11,563 | 16,693 | — | — | 28,256 | |||||||||||
| Depreciation, depletion and amortization | 7,148 | 21,371 | — | — | 28,519 | |||||||||||
| Accretion of discount on asset retirement obligations | 348 | 452 | — | — | 800 | |||||||||||
| General and administrative | 11,412 | 3,863 | — | — | 15,275 | |||||||||||
| Interest | 34,432 | 4,136 | — | (3,998 | ) | 34,570 | ||||||||||
| Total costs and expenses | 64,903 | 46,515 | — | (3,998 | ) | 107,420 | ||||||||||
| Income (loss) before income taxes | 2,461 | 24,074 | — | (41,164 | ) | (14,629 | ) | |||||||||
| Income tax expense | 504 | 4,622 | — | — | 5,126 | |||||||||||
| Income before discontinued operations | 1,957 | 19,452 | — | (41,164 | ) | (19,755 | ) | |||||||||
| Discontinued operations: | ||||||||||||||||
| Income from operations | 5,114 | — | 31,160 | — | 36,274 | |||||||||||
| Income tax expense | 910 | — | 9,448 | — | 10,358 | |||||||||||
| Income from discontinued operations, net of tax | 4,204 | — | 21,712 | — | 25,916 | |||||||||||
| Net income | $ | 6,161 | $ | 19,452 | $ | 21,712 | $ | (41,164 | ) | $ | 6,161 | |||||
87
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
For the 275 day period ended October 2, 2005
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiary | Eliminations | Consolidated | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues: | |||||||||||||||||
| Oil and natural gas sales | $ | 22,861 | $ | 109,960 | $ | — | $ | — | $ | 132,821 | �� | ||||||
| Commodity price risk management activities | (56,705 | ) | (120,548 | ) | — | — | (177,253 | ) | |||||||||
| Other income (loss) | 32,052 | 1,349 | — | (26,326 | ) | 7,075 | |||||||||||
| Equity in earnings of subsidiaries | (43,080 | ) | — | — | 43,080 | — | |||||||||||
| Total revenues | (44,872 | ) | (9,239 | ) | — | 16,754 | (37,357 | ) | |||||||||
Costs and expenses: | |||||||||||||||||
| Oil and natural gas production | 6,772 | 15,385 | — | — | 22,157 | ||||||||||||
| Depreciation, depletion and amortization | 3,978 | 20,709 | — | — | 24,687 | ||||||||||||
| Accretion of discount on asset retirement obligations | 235 | 382 | — | — | 617 | ||||||||||||
| General and administrative | 79,219 | 10,125 | — | — | 89,344 | ||||||||||||
| Interest | 26,673 | 26,328 | — | (26,326 | ) | 26,675 | |||||||||||
| Total costs and expenses | 116,877 | 72,929 | — | (26,326 | ) | 163,480 | |||||||||||
| Loss before income taxes | (161,749 | ) | (82,168 | ) | — | 43,080 | (200,837 | ) | |||||||||
| Income tax benefit | (21,538 | ) | (42,160 | ) | — | — | (63,698 | ) | |||||||||
| Loss before discontinued operations | (140,211 | ) | (40,008 | ) | — | 43,080 | (137,139 | ) | |||||||||
| Discontinued operations: | |||||||||||||||||
| Loss from operations | — | — | (4,403 | ) | — | (4,403 | ) | ||||||||||
| Gain on disposition of Addison Energy Inc | 175,717 | — | — | — | 175,717 | ||||||||||||
| Income tax (benefit) expense | 50,613 | — | (1,331 | ) | — | 49,282 | |||||||||||
| Income from discontinued operations, net of tax | 125,104 | — | (3,072 | ) | — | 122,032 | |||||||||||
| Net loss | $ | (15,107 | ) | $ | (40,008 | ) | $ | (3,072 | ) | $ | 43,080 | $ | (15,107 | ) | |||
88
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF OPERATIONS (Unaudited)
For the 90 day period ended December 31, 2005
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiary | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Revenues: | ||||||||||||||||
| Oil and natural gas sales | $ | 8,463 | $ | 61,598 | $ | — | $ | — | $ | 70,061 | ||||||
| Commodity price risk management activities | 2,856 | (3,112 | ) | — | — | (256 | ) | |||||||||
| Other income (loss) | 7,920 | 520 | — | (6,075 | ) | 2,365 | ||||||||||
| Equity in earnings of subsidiaries | 21,217 | — | — | (21,217 | ) | — | ||||||||||
| Total revenues | 40,456 | 59,006 | — | (27,292 | ) | 72,170 | ||||||||||
Costs and expenses: | ||||||||||||||||
| Oil and natural gas production | 1,784 | 7,165 | — | — | 8,949 | |||||||||||
| Depreciation, depletion and amortization | 1,869 | 12,202 | — | — | 14,071 | |||||||||||
| Accretion of discount on asset retirement obligations | 70 | 156 | — | — | 226 | |||||||||||
| General and administrative | 4,798 | 1,427 | — | — | 6,225 | |||||||||||
| Interest | 19,413 | 6,076 | — | (6,075 | ) | 19,414 | ||||||||||
| Total costs and expenses | 27,934 | 27,026 | — | (6,075 | ) | 48,885 | ||||||||||
| Income before income taxes | 12,522 | 31,980 | — | (21,217 | ) | 23,285 | ||||||||||
| Income tax expense (benefit) | (3,442 | ) | 10,763 | — | — | 7,321 | ||||||||||
| Net income (loss) | $ | 15,964 | $ | 21,217 | $ | — | $ | (21,217 | ) | $ | 15,964 | |||||
89
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
For the 209 day period ended July 28, 2003
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating Activities: | ||||||||||||||||
| Net cash provided by (used in) operating activities | $ | (9,910 | ) | $ | 10,882 | $ | 19,446 | $ | — | $ | 20,418 | |||||
| Investing Activities: | ||||||||||||||||
| Additions to oil and natural gas property and equipment | (3,517 | ) | (684 | ) | — | — | (4,201 | ) | ||||||||
| Proceeds from dispositions of property and equipment | 2,773 | 3,247 | — | — | 6,020 | |||||||||||
| Advances/investments with affiliates | 19,544 | (13,445 | ) | — | (6,099 | ) | — | |||||||||
| Proceeds from sales of marketable securities | 422 | — | — | — | 422 | |||||||||||
| Net cash used in investing activities of discontinued operations | — | — | (31,859 | ) | 6,099 | (25,760 | ) | |||||||||
| Other investing activities | (1 | ) | — | — | — | (1 | ) | |||||||||
| Net cash provided by (used in) investing activities | 19,221 | (10,882 | ) | (31,859 | ) | — | (23,520 | ) | ||||||||
Financing Activities: | ||||||||||||||||
| Proceeds from long-term debt | 20,638 | — | — | — | 20,638 | |||||||||||
| Payments on long-term debt | (11,750 | ) | — | — | — | (11,750 | ) | |||||||||
| Proceeds from exercise of stock options | 12,737 | — | — | — | 12,737 | |||||||||||
| Purchase of common stock from employees in connection with the merger | (17,874 | ) | — | — | — | (17,874 | ) | |||||||||
| Purchase of director and employee stock options in connection with the merger | (3,567 | ) | — | — | — | (3,567 | ) | |||||||||
| Payment of fees and expenses in connection with the merger | (563 | ) | — | — | — | (563 | ) | |||||||||
| Preferred stock dividends | (2,620 | ) | — | — | — | (2,620 | ) | |||||||||
| Deferred financing costs | (1,136 | ) | — | — | — | (1,136 | ) | |||||||||
| Net cash provided by financing activities of discontinued operations | (32 | ) | — | 13,977 | — | 13,945 | ||||||||||
| Other financing costs | 172 | — | — | — | 172 | |||||||||||
| Net cash provided by (used in) financing activities | (3,995 | ) | — | 13,977 | — | 9,982 | ||||||||||
| Net increase in cash | 5,316 | — | 1,564 | — | 6,880 | |||||||||||
| Effect of exchange rates on cash and cash equivalents | — | — | 58 | — | 58 | |||||||||||
| Cash at beginning of period | 1,867 | — | 75 | — | 1,942 | |||||||||||
| Cash at end of period | $ | 7,183 | $ | — | $ | 1,697 | $ | — | $ | 8,880 | ||||||
90
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
For the 156 day period ended December 31, 2003
| (in thousands) | Resources | Guarantor subsidiaries | Non-guarantor subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating Activities: | ||||||||||||||||
| Net cash provided by operating activities | $ | 4,633 | $ | 5,716 | $ | 11,371 | $ | — | $ | 21,720 | ||||||
| Investing Activities: | ||||||||||||||||
| Additions to oil and natural gas property and equipment | (6,282 | ) | (15,440 | ) | — | — | (21,722 | ) | ||||||||
| Proceeds from dispositions of property and equipment | 508 | 1,795 | — | — | 2,303 | |||||||||||
| Advances/investments with affiliates | (5,980 | ) | 7,929 | — | — | 1,949 | ||||||||||
| Proceeds from sales of marketable securities | 1,393 | — | — | — | 1,393 | |||||||||||
| Net cash used in investing activities of discontinued operations | 521 | — | (23,439 | ) | — | (22,918 | ) | |||||||||
| Other investing activities | 467 | — | — | — | 467 | |||||||||||
| Net cash used in investing activities | (9,373 | ) | (5,716 | ) | (23,439 | ) | — | (38,528 | ) | |||||||
Financing Activities: | ||||||||||||||||
| Proceeds from long-term debt | 58,520 | — | — | — | 58,520 | |||||||||||
| Payments on long-term debt | (56,000 | ) | — | — | — | (56,000 | ) | |||||||||
| Net cash provided by operating activities of discontinued operations | — | — | 14,035 | — | 14,035 | |||||||||||
| Deferred financing costs and other | (1,591 | ) | — | — | — | (1,591 | ) | |||||||||
| Net cash provided by financing activities | 929 | — | 14,035 | — | 14,964 | |||||||||||
| Net increase (decrease) in cash | (3,811 | ) | — | 1,967 | — | (1,844 | ) | |||||||||
| Effect of exchange rates on cash and cash equivalents | — | — | 297 | — | 297 | |||||||||||
| Cash at beginning of period | 7,183 | — | 1,697 | — | 8,880 | |||||||||||
| Cash at end of period | $ | 3,372 | $ | — | $ | 3,961 | $ | — | $ | 7,333 | ||||||
91
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
For the year ended December 31, 2004
| (in thousands) | Resources | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating Activities: | ||||||||||||||||
| Net cash provided by operating activities | $ | 219 | $ | 63,643 | $ | 54,771 | $ | — | $ | 118,633 | ||||||
| Investing Activities: | ||||||||||||||||
| Additions to oil and natural gas property and equipment | (15,547 | ) | (123,974 | ) | — | — | (139,521 | ) | ||||||||
| Proceeds from dispositions of property and equipment | 47,364 | 4,501 | — | — | 51,865 | |||||||||||
| Purchase of North Coast Energy, Inc | (225,562 | ) | 10,429 | — | — | (215,133 | ) | |||||||||
| Advances/investments with affiliates | (177,456 | ) | 52,873 | 124,734 | — | 151 | ||||||||||
| Proceeds from sales of marketable securities | 1,296 | — | — | — | 1,296 | |||||||||||
| Net cash used in investing activities of discontinued operations | — | — | (79,983 | ) | — | (79,983 | ) | |||||||||
| Other investing activities | — | — | — | — | — | |||||||||||
| Net cash provided by (used in) investing activities | (369,905 | ) | (56,171 | ) | 44,751 | — | (381,325 | ) | ||||||||
| Financing Activities: | ||||||||||||||||
| Proceeds from long-term debt | 546,350 | — | — | — | 546,350 | |||||||||||
| Payments on long-term debt | (158,070 | ) | — | — | — | (158,070 | ) | |||||||||
| Net cash used in financing activities of discontinued operations | — | — | (91,397 | ) | — | (91,397 | ) | |||||||||
| Deferred financing costs and other | (13,431 | ) | — | — | — | (13,431 | ) | |||||||||
| Net cash provided by (used in) financing activities | 374,849 | — | (91,397 | ) | — | 283,452 | ||||||||||
| Net increase in cash | 5,163 | 7,472 | 8,125 | — | 20,760 | |||||||||||
| Effect of exchange rates on cash and cash equivalents | — | — | (1,685 | ) | — | (1,685 | ) | |||||||||
| Cash at beginning of period | 3,372 | — | 3,961 | — | 7,333 | |||||||||||
| Cash at end of period | $ | 8,535 | $ | 7,472 | $ | 10,401 | $ | — | $ | 26,408 | ||||||
92
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
For the 275 day period ended October 2, 2005
| (in thousands) | Resources | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating Activities: | ||||||||||||||||
| Net cash provided by (used in) operating activities) | $ | (76,147 | ) | $ | 14,285 | $ | (19,158 | ) | $ | — | $ | (81,020 | ) | |||
| Investing Activities: | ||||||||||||||||
| Additions to oil and natural gas properties, gathering systems and equipment | 3,983 | (155,131 | ) | — | — | (151,144 | ) | |||||||||
| Proceeds from dispositions of non-oil and natural gas properties | — | — | — | — | — | |||||||||||
| Proceeds from dispositions of oil and natural gas properties | (160 | ) | 46,170 | — | — | 46,010 | ||||||||||
| Advances/investments with affiliates | (58,523 | ) | 107,719 | (48,987 | ) | — | 209 | |||||||||
| Proceeds from the sale of Addison | 444,812 | — | (1,415 | ) | — | 443,397 | ||||||||||
| Proceeds from sales of marketable securities | 59 | — | — | — | 59 | |||||||||||
| Net cash used in investing activities of discontinued operations | — | — | (442 | ) | — | (442 | ) | |||||||||
| Other investing activities | — | — | — | — | — | |||||||||||
| Net cash provided by (used in) investing activities | 390,175 | (1,242 | ) | (50,844 | ) | — | 338,089 | |||||||||
| Financing Activities: | ||||||||||||||||
| Proceeds from long-term debt | 41,300 | — | — | — | 41,300 | |||||||||||
| Payments on long-term debt | (148,247 | ) | — | — | — | (148,247 | ) | |||||||||
| Deferred financing costs and other | — | — | — | — | — | |||||||||||
| Net cash used in financing of discontinued operations | — | — | 59,601 | — | 59,601 | |||||||||||
| Net cash provided by (used in) financing activities | (106,947 | ) | — | 59,601 | — | (47,346 | ) | |||||||||
| Net increase (decrease) in cash | 207,081 | 13,043 | (10,401 | ) | — | 209,723 | ||||||||||
| Cash at the beginning of the period | 8,535 | 7,472 | 10,401 | — | 26,408 | |||||||||||
| Cash at end of period | $ | 215,616 | $ | 20,515 | $ | — | $ | — | $ | 236,131 | ||||||
93
EXCO RESOURCES, INC.
CONSOLIDATING STATEMENT OF CASH FLOWS (Unaudited)
For the 90 day period ended December 31, 2005
| (in thousands) | Resources | Guarantor Subsidiaries | Non-guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Operating Activities: | ||||||||||||||||
| Net cash provided by (used in) operating activities | $ | (19,500 | ) | $ | 27,240 | $ | — | $ | — | $ | 7,740 | |||||
| Investing Activities: | ||||||||||||||||
| Additions to oil and natural gas property, gathering systems and equipment | (1,153 | ) | (12,054 | ) | — | — | (13,207 | ) | ||||||||
| Proceeds from dispositions of property and equipment | (145 | ) | (248 | ) | — | — | (393 | ) | ||||||||
| Net cash used in investing activities | (1,298 | ) | (12,302 | ) | — | — | (13,600 | ) | ||||||||
| Financing Activities: | ||||||||||||||||
| Proceeds from long-term debt | 9,999 | — | — | — | 9,999 | |||||||||||
| Payments on long-term debt | (15,279 | ) | — | — | — | (15,279 | ) | |||||||||
| Net cash used in financing activities | (5,280 | ) | — | — | — | (5,280 | ) | |||||||||
| Net increase (decrease) in cash | (26,078 | ) | 14,938 | — | — | (11,140 | ) | |||||||||
| Effect of exchange rates on cash and cash equivalents | — | — | — | — | — | |||||||||||
| Cash at the beginning of the period | 215,616 | 20,515 | — | — | 236,131 | |||||||||||
| Cash at end of period | $ | 189,538 | $ | 35,453 | $ | — | $ | — | $ | 224,991 | ||||||
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20. 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):
| (in thousands, except per unit amounts) | | ||
|---|---|---|---|
| For the 209 day period from January 1, 2003 to July 28, 2003: | |||
| Proved property acquisition costs | $ | 1,474 | |
| Development costs | 2,622 | ||
| Capitalized asset retirement costs | 37 | ||
| Depreciation, depletion and amortization per Boe | $ | 4.16 | |
| Depreciation, depletion and amortization per Mcfe | $ | 0.69 | |
| For the 156 day period from July 29, 2003 to December 31, 2003: | |||
| Proved property acquisition costs | $ | 14,183 | |
| Development costs | 6,326 | ||
| Capitalized asset retirement costs | 49 | ||
| Depreciation, depletion and amortization per Boe | $ | 6.45 | |
| Depreciation, depletion and amortization per Mcfe | $ | 1.07 | |
| 2004: | |||
| Proved property acquisition costs | $ | 285,811 | |
| Unproved property acquisition costs | 17,669 | ||
| Total property acquisition costs(1) | 303,480 | ||
| Development and exploration costs(2) | 36,742 | ||
| Capitalized asset retirement costs | 8,462 | ||
| Depreciation, depletion and amortization per Boe | $ | 7.42 | |
| Depreciation, depletion and amortization per Mcfe | $ | 1.24 | |
| For the 275 day period from January 1, 2005 to October 2, 2005: | |||
| Proved property acquisition costs | $ | 103,222 | |
| Development and exploration costs(2) | 39,900 | ||
| Capitalized asset retirement costs | 1,686 | ||
| Depreciation, depletion and amortization per Boe | $ | 8.35 | |
| Depreciation, depletion and amortization per Mcfe | $ | 1.39 | |
| For the 90 day period from October 3, 2005 to December 31, 2005: | |||
| Development and exploration costs(2) | $ | 13,194 | |
| Capitalized asset retirement costs | 51 | ||
| Depreciation, depletion and amortization per Boe | $ | 14.54 | |
| Depreciation, depletion and amortization per Mcfe | $ | 2.42 | |
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Certain unaudited supplemental information related to oil and natural gas producing activities have been restated to reflect the impact of using spot prices for oil and natural gas as of December 31, 2003, 2004 and 2005 in determining volumes of proved oil and natural gas reserves and in the computations of discounted future cash flows and the standardized measure of future net cash flows. Prior to this restatement, such amounts were calculated using near month NYMEX futures prices. This restatement had no impact to our consolidated balance sheets, consolidated statements of operations, consolidated statements of changes in stockholders equity or consolidated statements of cash flows. The effects of the restatement to our estimated quantities and standardized measure of discounted future net cash flows are shown herein.
We retain independent engineering firms 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 probable 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.
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Estimated quantities of proved reserves
| (In thousands) | Oil (Bbls) | Natural Gas (Mcf) | NGLs (Bbls)(1) | Mcfe(2) | ||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | ||||||||||
| December 31, 2002 | 12,281 | 141,598 | 1,097 | 221,866 | ||||||
| Purchase of reserves in place | 153 | 22,133 | 45 | 23,321 | ||||||
| New discoveries and extensions | 396 | 5,196 | — | 7,572 | ||||||
| Revisions of previous estimates | 22 | (1,982 | ) | (210 | ) | (3,110 | ) | |||
| Production | (755 | ) | (7,551 | ) | (59 | ) | (12,435 | ) | ||
| Sales of reserves in place | (1,624 | ) | (3,764 | ) | (51 | ) | (13,814 | ) | ||
| December 31, 2003(3) | 10,473 | 155,630 | 822 | 223,400 | ||||||
| Purchase of reserves in place | 1,651 | 229,837 | — | 239,743 | ||||||
| New discoveries and extensions | 545 | 20,807 | 18 | 24,185 | ||||||
| Revisions of previous estimates | (369 | ) | 1,447 | 43 | (509 | ) | ||||
| Production | (638 | ) | (18,860 | ) | (60 | ) | (23,048 | ) | ||
| Sales of reserves in place | (4,426 | ) | (27,469 | ) | (613 | ) | (57,703 | ) | ||
| December 31, 2004(3) | 7,236 | 361,392 | 210 | 406,068 | ||||||
| Purchase of reserves in place | 60 | 59,780 | — | 60,140 | ||||||
| New discoveries and extensions | 349 | 30,834 | — | 32,928 | ||||||
| Revisions of previous estimates | 11 | (12,608 | ) | (190 | ) | (13,682 | ) | |||
| Production | (491 | ) | (20,482 | ) | (20 | ) | (23,548 | ) | ||
| Sales of reserves in place | (343 | ) | (17,886 | ) | — | (19,944 | ) | |||
| December 31, 2005(3) | 6,822 | 401,030 | — | 441,962 | ||||||
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Estimated quantities of proved developed reserves
| (In thousands) | Oil (Bbls) | Natural Gas (Mcf) | NGLs (Bbls)(1) | Mcfe(2) | ||||
|---|---|---|---|---|---|---|---|---|
| December 31, 2003(4) | 7,733 | 123,483 | 719 | 174,195 | ||||
| December 31, 2004(4) | 6,021 | 318,292 | 210 | 355,678 | ||||
| December 31, 2005(4) | 5,527 | 321,716 | — | 354,878 |
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
98
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.
| (in thousands) | | ||
|---|---|---|---|
| Year ended December 31, 2003: | |||
| Future cash inflows | $ | 1,177,506 | |
| Future production, development and abandonment costs | 408,093 | ||
| Future income taxes | 243,098 | ||
| Future net cash flows | 526,315 | ||
| Discount of future net cash flows at 10% per annum | 300,309 | ||
| Standardized measure of discounted future net cash flows(1) | $ | 226,006 | |
Year ended December 31, 2004: | |||
| Future cash inflows | $ | 2,589,656 | |
| Future production, development and abandonment costs | 795,140 | ||
| Future income taxes | 588,897 | ||
| Future net cash flows | 1,205,619 | ||
| Discount of future net cash flows at 10% per annum | 731,882 | ||
| Standardized measure of discounted future net cash flows(1) | $ | 473,737 | |
Year ended December 31, 2005: | |||
| Future cash inflows | $ | 4,334,629 | |
| Future production, development and abandonment costs | 1,148,283 | ||
| Future income taxes | 1,097,606 | ||
| Future net cash flows | 2,088,740 | ||
| Discount of future net cash flows at 10% per annum | 1,265,441 | ||
| Standardized measure of discounted future net cash flows(1) | $ | 823,299 | |
During recent years, prices paid for oil and natural gas have fluctuated significantly. The spot prices at December 31, 2003, 2004 and 2005 used in the above table, were $32.47, $43.33 and $61.03 per Bbl of oil, respectively, and $5.97, $6.18 and $10.08 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials. Prior to this restatement, we used near month NYMEX futures prices.
99
Changes in standardized measure
The following are the principal sources of change in the Standardized Measure:
| (in thousands) | | |||
|---|---|---|---|---|
| Year ended December 31, 2003: | ||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (39,032 | ) | |
| Net changes in prices and production costs | 64,514 | |||
| Extensions and discoveries, net of future development and production costs | 11,126 | |||
| Development costs during the period | 8,669 | |||
| Changes in estimated future development costs | (6,025 | ) | ||
| Revisions of previous quantity estimates | (8,673 | ) | ||
| Sales of reserves in place | (19,806 | ) | ||
| Purchase of reserves in place | 25,619 | |||
| Accretion of discount before income taxes | 28,384 | |||
| Changes in timing, foreign currency translation and other | (16,719 | ) | ||
| Net change in income taxes | 25,026 | |||
| Net change(1) | $ | 73,083 | ||
Year ended December 31, 2004: | ||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (114,116 | ) | |
| Net changes in prices and production costs | 84,388 | |||
| Extensions and discoveries, net of future development and production costs | 34,433 | |||
| Development costs during the period | 36,793 | |||
| Changes in estimated future development costs | 11,624 | |||
| Revisions of previous quantity estimates | (22,714 | ) | ||
| Sales of reserves in place | (81,485 | ) | ||
| Purchase of reserves in place | 320,788 | |||
| Accretion of discount before income taxes | 62,096 | |||
| Changes in timing, foreign currency translation and other | (48,243 | ) | ||
| Net change in income taxes | (35,833 | ) | ||
| Net change(1) | $ | 247,731 | ||
Year ended December 31, 2005: | ||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (171,775 | ) | |
| Net changes in prices and production costs | 511,666 | |||
| Extensions and discoveries, net of future development and production costs | 87,239 | |||
| Development costs during the period | 53,094 | |||
| Changes in estimated future development costs | (58,997 | ) | ||
| Revisions of previous quantity estimates | (21,895 | ) | ||
| Sales of reserves in place | (29,363 | ) | ||
| Purchase of reserves in place | 117,572 | |||
| Accretion of discount before income taxes | 69,849 | |||
| Changes in timing, foreign currency translation and other | (7,344 | ) | ||
| Net change in income taxes | (200,484 | ) | ||
| Net change(1) | $ | 349,562 | ||
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20. 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: The Company has determined that the impact of prices to the standardized measure, quantities and PV-10 for discontinued operations is not material and therefore are not being restated in this Amendment No. 2.
| (in thousands, except per unit amounts) | | ||
|---|---|---|---|
| For the 209 day period from January 1, 2003 to July 29, 2003: | |||
| Property acquisition costs | $ | 10,837 | |
| Development costs | 14,705 | ||
| Capitalized asset retirement costs | 203 | ||
| Depreciation, depletion and amortization per Boe | $ | 5.10 | |
| Depreciation, depletion and amortization per Mcfe | $ | 0.85 | |
| For the 156 day period from July 29, 2003 to December 31, 2003: | |||
| Property acquisition costs | $ | 4,954 | |
| Development costs | 17,486 | ||
| Capitalized asset retirement costs | 980 | ||
| Depreciation, depletion and amortization per Boe | $ | 6.99 | |
| Depreciation, depletion and amortization per Mcfe | $ | 1.17 | |
| 2004: | |||
| Property acquisition costs | $ | 43,178 | |
| Development costs | 33,258 | ||
| Capitalized asset retirement costs | 2,388 | ||
| Depreciation, depletion and amortization per Boe | $ | 6.86 | |
| Depreciation, depletion and amortization per Mcfe | $ | 1.14 | |
| For the 275 day period from January 1, 2005 to October 2, 2005: | |||
| Property acquisition costs | $ | 16 | |
| Development and exploration costs | 272 | ||
| Capitalized asset retirement costs | — | ||
| Depreciation, depletion and amortization per Boe | $ | 7.49 | |
| Depreciation, depletion and amortization per Mcfe | $ | 1.16 | |
We retained independent engineering firms for 2003 and 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 probable reserves, anticipated future oil and natural gas prices, interest rates, changes in
101
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—discontinued operations
| (in thousands) | Oil (Bbls) | Natural gas (Mcf) | NGLs (Bbls) | Mcfe(1) | ||||||
|---|---|---|---|---|---|---|---|---|---|---|
| December 31, 2002 | 5,754 | 107,695 | 3,994 | 166,183 | ||||||
| Purchase of reserves in place | 115 | 9,563 | 354 | 12,377 | ||||||
| New discoveries and extensions | 724 | 21,459 | 973 | 31,641 | ||||||
| Revisions of previous estimates | 641 | (3,965 | ) | 1,985 | 11,791 | |||||
| Production | (448 | ) | (8,360 | ) | (332 | ) | (13,040 | ) | ||
| Sales of reserves in place | — | — | — | — | ||||||
| December 31, 2003 | 6,786 | 126,392 | 6,974 | 208,952 | ||||||
| Purchase of reserves in place | 1,378 | 17,105 | 455 | 28,103 | ||||||
| New discoveries and extensions | 656 | 19,570 | 1,130 | 30,286 | ||||||
| Revisions of previous estimates | 1,068 | 14,450 | 1,586 | 30,374 | ||||||
| Production | (549 | ) | (10,345 | ) | (643 | ) | (17,497 | ) | ||
| Sales of reserves in place | — | — | — | — | ||||||
| December 31, 2004 | 9,339 | 167,172 | 9,502 | 280,218 | ||||||
| Purchase of reserves in place | — | — | — | — | ||||||
| New discoveries and extensions | — | — | — | — | ||||||
| Revisions of previous estimates | — | — | — | — | ||||||
| Production | (64 | ) | (1,142 | ) | (84 | ) | (2,030 | ) | ||
| Sales of reserves in place | (9,275 | ) | (166,030 | ) | (9,418 | ) | (278,188 | ) | ||
| December 31, 2005 | — | — | — | — | ||||||
Estimated quantities of proved developed reserves—discontinued operations
| (in thousands) | Oil (Bbls) | Natural gas (Mcf) | NGLs (Bbls) | Mcfe(1) | ||||
|---|---|---|---|---|---|---|---|---|
| December 31, 2003 | 6,529 | 117,030 | 6,377 | 194,466 | ||||
| December 31, 2004 | 8,825 | 155,012 | 9,250 | 263,462 |
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
102
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.
| | (in thousands) | ||
|---|---|---|---|
| Year ended December 31, 2003: | |||
| Future cash inflows | $ | 953,165 | |
| Future production and development costs | 364,305 | ||
| Future income taxes | 165,069 | ||
| Future net cash flows | 423,791 | ||
| Discount of future net cash flows at 10% per annum | 204,772 | ||
| Standardized measure of discounted future net cash flows | $ | 219,019 | |
| Year ended December 31, 2004: | |||
| Future cash inflows | $ | 1,525,346 | |
| Future production, development and abandonment costs | 502,980 | ||
| Future income taxes | 295,697 | ||
| Future net cash flows | 726,669 | ||
| Discount of future net cash flows at 10% per annum | 366,833 | ||
| Standardized measure of discounted future net cash flows | $ | 359,836 | |
| Year ended December 31, 2005: | |||
| Future cash inflows | $ | — | |
| Future production, development and abandonment costs | — | ||
| Future income taxes | — | ||
| Future net cash flows | — | ||
| Discount of future net cash flows at 10% per annum | — | ||
| Standardized measure of discounted future net cash flows | $ | — | |
Near month NYMEX futures prices at December 31, 2003 and 2004 used in the above table, were $32.52 and $43.45 per Bbl of oil, respectively, and $6.19 and $6.15 per Mmbtu of natural gas, respectively, in each case adjusted for historical differentials.
103
Changes in standardized measure—discontinued operations
The following are the principal sources of change in the Standardized Measure:
| (in thousands) | | |||
|---|---|---|---|---|
| Year ended December 31, 2003: | ||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (47,773 | ) | |
| Net changes in prices and production costs | (7,053 | ) | ||
| Extensions and discoveries, net of future development and production costs | 47,518 | |||
| Development costs during the period | 25,478 | |||
| Changes in estimated future development costs | (16,614 | ) | ||
| Revisions of previous quantity estimates | 18,054 | |||
| Sales of reserves in place | — | |||
| Purchase of reserves in place | 21,509 | |||
| Accretion of discount before income taxes | 24,595 | |||
| Changes in timing, foreign currency translation and other | (28,329 | ) | ||
| Net change in income taxes | 24,217 | |||
| Net change | $ | 61,602 | ||
| Year ended December 31, 2004: | ||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (74,160 | ) | |
| Net changes in prices and production costs | 79,167 | |||
| Extensions and discoveries, net of future development and production costs | 55,950 | |||
| Development costs during the period | 33,258 | |||
| Changes in estimated future development costs | (20,516 | ) | ||
| Revisions of previous quantity estimates | 56,311 | |||
| Sales of reserves in place | — | |||
| Purchase of reserves in place | 61,904 | |||
| Accretion of discount before income taxes | 30,119 | |||
| Changes in timing, foreign currency translation and other | (31,253 | ) | ||
| Net change in income taxes | (49,963 | ) | ||
| Net change | $ | 140,817 | ||
| Year ended December 31, 2005: | ||||
| Sales and transfers of oil and natural gas produced, net of production costs | $ | (8,756 | ) | |
| Development costs during the period | 272 | |||
| Accretion of discount before income taxes | 2,999 | |||
| Changes in timing, foreign currency translation and other | (11,002 | ) | ||
| Sales of reserves in place | (343,349 | ) | ||
| Net change | $ | (359,836 | ) | |
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21. Selected Quarterly Financial Information (Unaudited)
Selected Quarterly Financial Information (Unaudited)
| | 2005 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Private Predecessor | Successor | |||||||||||||
| | | As Restated(1) | 2 Day period from October 1 to October 2 | 90 day period from October 3 to December 31 | |||||||||||
| (in thousands, except per share amounts) | | ||||||||||||||
| March 31 | June 30 | September 30 | |||||||||||||
| Total revenues | $ | (18,079 | ) | $ | 31,653 | $ | (52,333 | ) | $ | 1,402 | $ | 72,170 | |||
| Income (loss) from continuing operations | (28,639 | ) | 4,452 | (49,715 | ) | (63,237 | ) | 15,964 | |||||||
| Income from discontinued operations | 120,884 | 1,148 | — | — | — | ||||||||||
| Basic earnings (loss) per share | N/A | N/A | N/A | N/A | N/A | ||||||||||
| Diluted earnings (loss) per share | N/A | N/A | N/A | N/A | N/A | ||||||||||
| Total assets | 847,329 | 870,152 | 910,464 | 911,072 | 1,507,637 | ||||||||||
| Long-term debt, less current maturities | 452,853 | 452,750 | 452,644 | 452,642 | 461,801 | ||||||||||
| Stockholder's equity | 274,613 | 280,230 | 230,515 | 209,692 | 342,681 | ||||||||||
| | 2004 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Private Predecessor | |||||||||||
| (in thousands, except per share amounts) | ||||||||||||
| March 31 | June 30 | September 30 | December 31 | |||||||||
| Total revenues | $ | 5,571 | $ | 20,970 | $ | 5,271 | $ | 60,979 | ||||
| Net income (loss) | (9,066 | ) | 2,756 | (11,090 | ) | 23,561 | ||||||
| Basic earnings (loss) per share | N/A | N/A | N/A | N/A | ||||||||
| Diluted earnings (loss) per share | N/A | N/A | N/A | N/A | ||||||||
| Total assets | 770,268 | 796,665 | 856,813 | 922,023 | ||||||||
| Long-term debt, less current maturities | 350,001 | 453,153 | 470,051 | 487,453 | ||||||||
| Stockholder's equity | 173,808 | 174,804 | 171,962 | 203,751 | ||||||||
| | 2003 | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Public Predecessor | Private Predecessor | |||||||||||||
| (in thousands, except per share amounts) | March 31 | June 30 | 28 Day Period From July 1 to July 28 | 64 Day Period From July 29 to September 30 | December 31 | ||||||||||
| Total revenues | $ | 7,344 | $ | 10,318 | $ | 3,612 | $ | 8,817 | $ | 1,969 | |||||
| Net income (loss) | 4,349 | 3,718 | (7,035 | ) | 3,726 | 451 | |||||||||
| Basic earnings (loss) per share | 0.43 | 0.34 | (0.58 | ) | N/A | N/A | |||||||||
| Diluted earnings (loss) per share | 0.35 | 0.29 | (0.58 | ) | N/A | N/A | |||||||||
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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
1. Financial Statements
See Index to Financial Statements on page 27 to this 10-K/A.
2. Financial Statement Schedules
All schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in our consolidated financial statements or related notes.
3. Exhibits
| EXHIBIT NUMBER | Description Of Exhibit | |
|---|---|---|
| 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 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 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. | |
4.5 | Form of 71/4% Global Note Due 2011.** | |
4.6 | Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.* | |
4.7 | Registration Rights Agreement by and among EXCO Resources, Inc., certain domestic subsidiaries of EXCO Resources, Inc., as guarantors, and Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc, dated April 1, 2004.** | |
4.8 | Pledge Agreement by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, dated January 20, 2004.* | |
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4.9 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
4.10 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
4.11 | 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. | |
10.1 | Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003, filed as an Exhibit to EXCO's Form 8-K filed March 12, 2003 and incorporated by reference herein. | |
10.2 | Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein.* | |
10.3 | First Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.** | |
10.4 | Second Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.** | |
10.5 | Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein.* | |
10.6 | First Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.** | |
10.7 | Second Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.** | |
10.8 | Amended and Restated Agreement and Plan of Merger among NCE Acquisition, Inc., EXCO Resources, Inc., North Coast Energy, Inc. and Nuon Energy & Water Investments, Inc., dated as of December 4, 2003, filed as exhibit (d)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein. | |
10.9 | Escrow Agreement among Nuon Energy & Water Investments, Inc., EXCO Resources, Inc. and Citibank, N.A., dated as of December 9, 2003.* | |
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10.10 | Unconditional Guaranty Agreement by and between EXCO Resources, Inc. and n.v. NUON, dated as of December 9, 2003.* | |
10.11 | Commitment Letter among Credit Suisse First Boston Bank One, NA, Banc One Capital Markets, Inc. and EXCO Resources, Inc., dated November 25, 2003, filed as exhibit (b)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein. | |
10.12 | Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, Canada Branch, as Agent.* | |
10.13 | Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC, Inc. in favor of Bank One, NA, Canada Branch, as Agent.* | |
10.14 | Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, Canada Branch, as agent.* | |
10.15 | Second Restated Unlimited Guaranty dated as of January 27, 2004, by EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Taurus Acquisition, Inc. in favor of Bank One, NA, Canada Branch, as Agent.* | |
10.16 | Amended and Restated Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.* | |
10.17 | Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, as Agent.* | |
10.18 | Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, as Agent.* | |
10.19 | Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Holdings Inc. in favor of Bank One, NA, as Agent.* | |
10.20 | Amended and Restated Subsidiary Guaranty dated as of January 27, 2004, by Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.* | |
10.21 | Third Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. | |
10.22 | Third Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. | |
10.23 | EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. *** | |
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10.24 | First Amendment to the EXCO Holdings Inc. 2004 Long-term Incentive Plan, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.*** | |
10.25 | Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.26 | Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.27 | EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.*** | |
10.28 | EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.29 | Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.30 | Unlimited Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, Canada Branch, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein. | |
10.31 | Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein. | |
10.32 | 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 Form 8-K filed January 21, 2005 and incorporated by reference herein. | |
10.33 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
10.34 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
10.35 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
10.36 | 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. | |
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10.37 | 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.* | |
10.38 | 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. | |
10.39 | 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. | |
10.40 | Form of 71/4% Global Note Due 2011.** | |
10.41 | Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.* | |
10.42 | EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.43 | Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.44 | Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.45 | Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.46 | Fourth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated September 30, 2005, as filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and incorporated by reference herein. | |
10.47 | 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 Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein. | |
10.48 | Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., as filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein. | |
110
10.49 | 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 the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein. | |
10.50 | Fifth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA (successor by merger to Bank One, N.A. (Illinois), as Administrative Agent for itself and the Lenders defined therein, dated December 15, 2005, 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. | |
10.51 | Agreement and Plan of Merger between EXCO Holdings Inc. and EXCO Resources, Inc., dated February9, 2006, filed as an Exhibit to EXCO's Current Report on Form 8-K filed February 14, 2006 and incorporated by reference herein. | |
10.52 | Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.53 | Guarantee, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., ROJO Pipeline, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Pinestone Resources, L.L.C., as Guarantors, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined herein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.54 | 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 Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.55 | 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 Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.56 | 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 Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
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10.57 | 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 filed on February 21, 2006 and incorporated by reference herein. | |
10.58 | 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 filed on March 23, 2006 and incorporated by reference herein. | |
10.59 | 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. | |
10.60 | Form of Incentive Stock Option 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. | |
10.61 | Form of Nonqualified Stock Option 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. | |
10.62 | 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. | |
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 the 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 the Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein. | |
21.1 | Subsidiaries of the registrant, filed herewith previously filed. | |
23.1 | Consent of PricewaterhouseCoopers LLP, filed herewith. | |
23.2 | Consent of Lee Keeling and Associates, Inc., 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 and Chief Financial Officer of EXCO Resources, Inc., filed herewith. | |
112
99.1 | Audit Committee Charter, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein. |
113
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.
| EXCO RESOURCES, INC. (Registrant) | |||
Date: December 7, 2006 | By: | /s/ DOUGLAS H. MILLER Douglas H. Miller Chairman and Chief Executive Officer | |
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| EXHIBIT NUMBER | Description Of Exhibit | |
|---|---|---|
| 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 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 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. | |
4.5 | Form of 71/4% Global Note Due 2011.** | |
4.6 | Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.* | |
4.7 | Registration Rights Agreement by and among EXCO Resources, Inc., certain domestic subsidiaries of EXCO Resources, Inc., as guarantors, and Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc, dated April 1, 2004.** | |
4.8 | Pledge Agreement by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, dated January 20, 2004.* | |
4.9 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
4.10 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
4.11 | 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. | |
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10.1 | Agreement and Plan of Merger among EXCO Resources, Inc., EXCO Holdings Inc. and ER Acquisition, Inc., dated March 11, 2003, filed as an Exhibit to EXCO's Form 8-K filed March 12, 2003 and incorporated by reference herein. | |
10.2 | Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein.* | |
10.3 | First Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.** | |
10.4 | Second Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated March 31, 2004.** | |
10.5 | Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein.* | |
10.6 | First Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.** | |
10.7 | Second Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated March 31, 2004.** | |
10.8 | Amended and Restated Agreement and Plan of Merger among NCE Acquisition, Inc., EXCO Resources, Inc., North Coast Energy, Inc. and Nuon Energy & Water Investments, Inc., dated as of December 4, 2003, filed as exhibit (d)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein. | |
10.9 | Escrow Agreement among Nuon Energy & Water Investments, Inc., EXCO Resources, Inc. and Citibank, N.A., dated as of December 9, 2003.* | |
10.10 | Unconditional Guaranty Agreement by and between EXCO Resources, Inc. and n.v. NUON, dated as of December 9, 2003.* | |
10.11 | Commitment Letter among Credit Suisse First Boston Bank One, NA, Banc One Capital Markets, Inc. and EXCO Resources, Inc., dated November 25, 2003, filed as exhibit (b)(1) to the Schedule TO filed by NCE Acquisition, Inc. and EXCO Resources, Inc. on December 5, 2003 and incorporated by reference herein. | |
10.12 | Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, Canada Branch, as Agent.* | |
10.13 | Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC, Inc. in favor of Bank One, NA, Canada Branch, as Agent.* | |
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10.14 | Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, Canada Branch, as agent.* | |
10.15 | Second Restated Unlimited Guaranty dated as of January 27, 2004, by EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Taurus Acquisition, Inc. in favor of Bank One, NA, Canada Branch, as Agent.* | |
10.16 | Amended and Restated Pledge Agreement for Partnership Interests dated as of January 27, 2004, by EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.* | |
10.17 | Pledge Agreement for Stock dated as of January 27, 2004, by North Coast Energy, Inc. in favor of Bank One, NA, as Agent.* | |
10.18 | Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Resources, Inc. in favor of Bank One, NA, as Agent.* | |
10.19 | Amended and Restated Pledge Agreement for Stock dated as of January 27, 2004, by EXCO Holdings Inc. in favor of Bank One, NA, as Agent.* | |
10.20 | Amended and Restated Subsidiary Guaranty dated as of January 27, 2004, by Taurus Acquisition, Inc., EXCO Investment I, LLC and EXCO Investment II, LLC in favor of Bank One, NA, as Agent.* | |
10.21 | Third Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. | |
10.22 | Third Amendment to the Third Amended and Restated Credit Agreement between Addison Energy Inc. and Bank One, NA, Canada Branch, as Administrative Agent for itself and the lenders named therein, dated June 28, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. | |
10.23 | EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein. *** | |
10.24 | First Amendment to the EXCO Holdings Inc. 2004 Long-term Incentive Plan, filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.*** | |
10.25 | Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.26 | Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2004 Long-term Incentive Plan, dated June 3, 2004 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.27 | EXCO Resources, Inc. Amended and Restated Severance Plan effective as of August 17, 2004 filed as an Exhibit to EXCO's Form 8-K filed November 24, 2004 and incorporated by reference herein.*** | |
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10.28 | EXCO Holdings Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.29 | Addison Energy Inc. Employee Bonus Retention Plan, dated July 29, 2003 filed as an Exhibit to EXCO's Form 10-Q filed August 13, 2004 and incorporated by reference herein.*** | |
10.30 | Unlimited Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, Canada Branch, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein. | |
10.31 | Subsidiary Guaranty dated as of December 21, 2004 made by Pinestone Resources, LLC in favor of Bank One, NA, as Agent, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2004 filed March 31, 2005 and incorporated by reference herein. | |
10.32 | 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 Form 8-K filed January 21, 2005 and incorporated by reference herein. | |
10.33 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
10.34 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
10.35 | 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 Form 8-K/A Amendment No. 1 filed February 16, 2005 and incorporated by reference herein. | |
10.36 | 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. | |
10.37 | 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.* | |
10.38 | 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. | |
10.39 | 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. | |
10.40 | Form of 71/4% Global Note Due 2011.** | |
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10.41 | Registration Rights Agreement by and among EXCO Resources, Inc., Credit Suisse First Boston LLC, Banc One Capital Markets, Inc., Banc of America Securities LLC, BNP Paribas Securities Corp., Comerica Securities, Inc., Fleet Securities, Inc., Scotia Capital (USA) Inc. and TD Securities (USA) Inc., dated January 20, 2004.* | |
10.42 | EXCO Holdings Inc. 2005 Long-term Incentive Plan, dated October 5, 2005 filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.43 | Form of Incentive Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.44 | Form of Nonqualified Stock Option Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.45 | Form of Restricted Stock Award Agreement of the EXCO Holdings Inc. 2005 Long-term Incentive Plan filed as an Exhibit to EXCO's Form 8-K dated October 7, 2005 and incorporated by reference herein.*** | |
10.46 | Fourth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc. and North Coast Energy Eastern, Inc., as Borrowers, and Bank One, NA, as Administrative Agent for itself and the Lenders defined therein, dated September 30, 2005, as filed as an Exhibit to EXCO's Form 8-K dated September 30, 2005 and incorporated by reference herein. | |
10.47 | 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 Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein. | |
10.48 | Promissory Note in the maximum amount of $10,000,000, dated October 7, 2005, made by EXCO Holdings Inc., payable to EXCO Resources, Inc., as filed as an Exhibit to EXCO's Form 10-Q for the Quarter ended September 30, 2005 filed November 14, 2005 and incorporated by reference herein. | |
10.49 | 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 the Form S-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein. | |
10.50 | Fifth Amendment to the Third Amended and Restated Credit Agreement among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA (successor by merger to Bank One, N.A. (Illinois), as Administrative Agent for itself and the Lenders defined therein, dated December 15, 2005, 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. | |
10.51 | Agreement and Plan of Merger between EXCO Holdings Inc. and EXCO Resources, Inc., dated February9, 2006, filed as an Exhibit to EXCO's Current Report on Form 8-K filed February 14, 2006 and incorporated by reference herein. | |
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10.52 | Sixth Amendment to Third Amended and Restated Credit Agreement, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., as Borrowers, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined therein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.53 | Guarantee, dated February 14, 2006, among EXCO Resources, Inc., EXCO Operating, LP, North Coast Energy, Inc., North Coast Energy Eastern, Inc., ROJO Pipeline, Inc., EXCO Investment I, LLC, EXCO Investment II, LLC and Pinestone Resources, L.L.C., as Guarantors, and JPMorgan Chase Bank, NA, as Administrative Agent for itself and the Lenders defined herein, filed as an Exhibit to EXCO's Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.54 | 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 Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.55 | 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 Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.56 | 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 Form 8-K filed on February 21, 2006 and incorporated by reference herein. | |
10.57 | 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 filed on February 21, 2006 and incorporated by reference herein. | |
10.58 | 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 filed on March 23, 2006 and incorporated by reference herein. | |
10.59 | 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. | |
10.60 | Form of Incentive Stock Option 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. | |
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10.61 | Form of Nonqualified Stock Option 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. | |
10.62 | 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. | |
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 the 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 the Form S-1 (File No. 333-129935) filed January 6, 2006 and incorporated by reference herein. | |
21.1 | Subsidiaries of the registrant previously filed. | |
23.1 | Consent of PricewaterhouseCoopers LLP, filed herewith. | |
23.2 | Consent of Lee Keeling and Associates, Inc., 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 and Chief Financial 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. |
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