10-Q/A 1 h96010e10-qa.txt TRI-UNION DEVELOPMENT CORPORATION - AMENDMENT #1 U.S. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q/A AMENDMENT 1 QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001 Commission file number: 333-66282 TRI-UNION DEVELOPMENT CORPORATION FORMERLY KNOWN AS TRIBO PETROLEUM CORPORATION (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) TEXAS 76-0381207 (STATE OR OTHER JURISDICTION OF (IRS EMPLOYER INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)

530 LOVETT BOULEVARD HOUSTON, TEXAS 77006 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (713) 533-4000 (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE) INDICATE BY CHECK MARK WHETHER THE REGISTRANT: (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. yes [ ] no [x] AS OF NOVEMBER 13, 2001 THERE WERE 368,333 SHARES OF CLASS A COMMON STOCK, PAR VALUE $0.01 PER SHARE AND 65,000 SHARES OF CLASS B COMMON STOCK, PAR VALUE $0.01 PER SHARE, OUTSTANDING -------------------------------------------------------------------------------- TRI-UNION DEVELOPMENT CORPORATION (formerly Tribo Petroleum Corporation) INDEX TO FINANCIAL INFORMATION Part I. Financial Information Item 1. Financial Statements Consolidated Statements of Income and Comprehensive Income for the Three and Nine Months Ended September 30, 2001 and 2000 (unaudited)...........................4 Consolidated Balance Sheets at September 30, 2001 (unaudited) and December 31, 2000 (audited)...................................................................5 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2001 and 2000 (unaudited)......................................................6 Notes to Consolidated Financial Statements (unaudited)........................................7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................................11 Item 3. Quantitative and Qualitative Disclosure about Market Risk....................................20 Part II. Other Information Item 1. Legal Proceedings............................................................................21 Signature ......................................................................................................23

-2- Explanatory Note: This amendment to Tri-Union Union Development Corporation's (formerly Tribo Petroleum Corporation) quarterly report on Form 10-Q/A for the three and nine month periods ended September 30, 2001 is being filed for the purpose of amending and restating Items 1 and 2 of Part I of our original Form 10-Q to reflect the restatement of our consolidated financial statements. This restatement relates to a change in our original estimate of the reorganization costs incurred as a result of the rejection of a fixed-price physical delivery contract. We have made no further changes to the previously filed Form 10-Q. All information in this Form 10-Q/A is as of September 30, 2001 and does not reflect any subsequent information or events other than the aforementioned restatement. -3- PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM CORPORATION) CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (UNAUDITED)

(1) Net income for the three and nine months ended September 30, 2001 has been reduced by $737,022 as a result of a change in our original estimate of the loss associated with the rejection of a fixed-price physical delivery contract during our bankruptcy proceeding classified as a component of reorganization costs. The change in estimate resulted from additional information, which became available to us subsequent to the filing of our report on Form 10-Q at September 30, 2001. Net income per common share for the three and nine months ended September 30, 2001 was reduced by $1.70 and $2.35 per share, respectively, as a result of this change in estimate. See note 2 of the Notes to Consolidated Financial Statements. The accompanying notes are an integral part of these consolidated financial statements. -4- TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM CORPORATION) CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements. -5- TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM CORPORATION) CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

The accompanying notes are an integral part of these consolidated financial statements. -6- TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM CORPORATION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1 -- BASIS OF PRESENTATION Tri-Union Development Corporation ("TDC") was incorporated in the State of Texas in 1996 and is the successor by merger to Tribo Petroleum Corporation ("Tribo"), which was incorporated in September 1992. TDC and its subsidiary (collectively, "the Company") is an independent oil and natural gas company engaged in the acquisition, operation and development of oil and natural gas properties primarily in areas of Texas and Louisiana, offshore in the shallow waters of the Gulf of Mexico, and in the Sacramento Basin of northern California. The consolidated financial statements include the accounts of TDC and its wholly owned subsidiary Tri-Union Operating Company ("TOC"). All significant intercompany accounts and transactions have been eliminated in consolidation. The information contained within these financial statements gives effect to our merger with the former parent corporation, Tribo, on July 27, 2001. NOTE 2 - RESTATEMENT OF FINANCIAL STATEMENTS During our bankruptcy, the court approved a motion to reject a fixed-price physical delivery contract. A claim was filed by the damaged party resulting in the recording of an estimated liability of $17,559,272 to reorganization costs. Subsequent to the filing of our original report on Form 10-Q for the quarter ended September 30, 2001, additional information became available to us which resulted in a $737,022 increase to the original estimate. The effects of the adjustment to the Company's Consolidated Statement of income and Comprehensive Income for the three and nine months ended September 30, 2001 are as follows: 1) An increase of reorganization costs of $737,022, 2) A reduction of net income of $737,022, and 3) A reduction of net income per common share, basic and diluted of $1.70 and $2.35 for the three and nine months ended September 30, 2001, respectively. The significant effects of the adjustment on the accompanying consolidated financial statements from the amounts previously reported are summarized as follows:

NOTE 3 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INTERIM PRESENTATION The accompanying unaudited consolidated interim financial statements and disclosures for the three and nine months ended September 30, 2001 and 2000, have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission and in accordance with accounting principles generally accepted in the United States of America. In the opinion of management, all adjustments (consisting solely of normal recurring adjustments) necessary for a fair presentation in all material respects of the results for the interim periods have been made. The December 31, 2000 balance sheet was derived from audited financial statements and notes included in a registration statement, but do not include all disclosures required by accounting principles generally accepted in the United States of -7- America. The interim unaudited financial statements for the three and nine months ended September 30, 2001 and 2000 should be read in conjunction with the Company's annual consolidated financial statements for the years ended December 31, 2000 and 1999. The results of operations for the three and nine months ended September 30, 2001 are not necessarily indicative of results to be expected for the full year. NOTE 4 -- 2001 EVENTS (a) During March 2001, the Company entered into a lease agreement with a related party for the lease of its current office facilities. The lease is on a month-to-month basis and obligates the Company to pay the related party $26,000 per month. (b) On May 23, 2001, TDC's plan of reorganization was confirmed by the bankruptcy court, pending the completion of a securities offering. On June 18, 2001, TDC completed its securities offering and exited from bankruptcy. Net cash proceeds from the offering provided sufficient available cash, allowing us to pay or segregate funds for the payment of all claims in full. In addition, the Company paid interest at 6% per annum for all unsecured pre-petition liabilities subject to compromise, and interest at prime plus 2%, or 11.50% on the liability relating to the cancellation of an executory contract. (c) On May 25, 2001, the Company agreed to transfer certain oil and natural gas properties with a net book value of approximately $1,138,000 to its affiliate, Atasca Resources, Inc. In connection with this transaction, all balances owing to and from the Company by its affiliates and its Chief Executive Officer and sole shareholder on May 25, 2001 of approximately $1,013,000 were forgiven. As a consequence of these transactions, the Company recorded a one-time reorganization expense of approximately $1,985,000. (d) On June 5, 2001, the Company sold certain oil and natural gas properties for $2.2 million. (e) On June 13, 2001, the Company increased its authorized share capital to 445,000 shares of class A common stock and 65,000 shares of class B common stock. The Company also affected a 238.333:1 stock split of its class A common stock. The consolidated financial statements give retroactive effect to the stock split for all periods presented. In connection with the stock split, the par value of the class A common stock decreased from $1.00 to $0.01 per share. The par value of the class B common stock is $0.01. The class B common stock is convertible into class A common stock on a one for one basis upon the occurrence of certain events. (f) On June 13, 2001, the Company issued a Prospectus for the sale of 130,000 Units, consisting of (1) $130 million of 12.5% senior secured notes due 2006 ("Notes") and (2) 130,000 shares of class A common stock of the Company. Each unit consisted of $1,000 principal amount of Notes and one share of class A common stock. Notes The Notes mature on June 1, 2006 and require amortization payments of the greater of $20 million or 15.3% of the aggregate amount then outstanding as of June 1, 2002 and 2003 and an amortization payment of the greater of $15 million or 11.5% of the aggregate amount then outstanding as of June 1, 2004. Interest is payable semi-annually on June 1 and December 1 of each year. The Notes were issued at a 5.5% discount from their face amount resulting in an aggregate discount of $7,150,000 that will be amortized as additional interest expense over the term of the Notes. Class A Common Stock The Company issued 130,000 shares of class A common stock with an estimated fair value of $17.6 million. The proceeds from the unit offering allocated to the common stock gave rise to further bond discount, which will be amortized as additional interest expense over the term of the Notes. Class B Common Stock In conjunction with the offering, the Company issued 65,000 shares of class B common stock to the initial purchaser of the Notes. These shares had a fair value of $11,000,000 and were considered as -8- unit offering costs. The portion of the offering costs associated with the issuance of the Notes will be amortized as additional interest expense over the term of the Notes. The class B common stock has special voting rights and the ability to control the Company's board of directors, subject to certain limitations. In addition, the Company incurred other offering costs of $9,625,000. The portion of the offering costs associated with the issuance of the Notes will be amortized as additional interest expense over the term of the Notes. (g) On June 18, 2001, the Company entered into a derivatives contract for approximately 80% of the Company's projected oil and gas production from proved developed producing reserves through June 30, 2003 and has agreed to maintain, on a monthly basis, a rolling two-year derivatives contract until the maturity of the notes. Currently, TDC has derivatives contracts in place through September 30, 2003. (h) On July 27, 2001, Tribo merged with one of its wholly owned subsidiaries, TDC. As a result of the merger, the surviving corporation was TDC, which assumed all of the rights and obligations of Tribo. (i) The exchange offer registration statement became effective on November 6, 2001; 22 days after contractual penalties of .5% of interest on the balance of the notes began accruing. The penalty totaled $37,916.67. NOTE 5 - RESTRICTED CASH Restricted cash recorded as current assets represents amounts deposited into escrow as required by our plan of reorganization to satisfy the payment in full of all remaining disputed pre-petition claims. Restricted cash recorded as other assets represent funds, which are pledged or are held in trust for the satisfaction of regulatory operating deposits and performance bonds. NOTE 6 - DERIVATIVES CONTRACT Upon the issuance of the senior secured notes, approximately 80% of the Company's projected oil and natural gas production from proved developed producing reserves, and the basis differential attributable to approximately 80% of its projected proved developed producing natural gas production from the Company's California properties, were contracted through September 30, 2003 at estimated net realized prices of $4.04 per Mcf and $24.97 per Bbl, or a weighted natural gas-equivalent price of approximately $4.10 per Mcfe. In connection with the issuance of the notes, the Company has agreed to maintain, on a monthly basis, a rolling two-year derivatives contract until the maturity of the notes, subject to certain conditions. These derivative transactions do not qualify for hedge accounting under FAS 133, therefore, the Company will be marking these transactions to fair value, which will be reflected in the balance sheet and statement of income. The estimated fair value of these derivative arrangements of September 30, 2001 resulted in a net current asset of $8,265,100 and a net non-current asset of $3,686,755, with an offsetting amount of $11,951,855, recorded as gain on derivatives contract. NOTE 7 - EARNINGS PER SHARE The basic net income per common share is computed by dividing the net income available to common shareholders by the weighted average number of common shares outstanding. Diluted net income per common share is computed by dividing the net income available to common shareholders, adjusted on an as if converted basis, by the weighted average number of common shares outstanding plus potential dilutive securities. There were no dilutive securities for the three and nine month periods ended September 30, 2001 and 2000. NOTE 8 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 ("FAS 133"), "Accounting for Derivative Instruments and Hedging -9- Activities." FAS 133, as amended by FAS 137, is effective for transactions entered into after June 15, 2000. FAS 133 requires that all derivative instruments be recorded on the balance sheet at fair value. Changes in the fair value of derivatives are recorded for each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. The ineffective portion of all hedges will be recognized in earnings. As of January 1, 2001, the Company adopted FAS 133 (see Note 5). In December 1999, the SEC issued Staff Accounting Bulletin No. 101 ("SAB 101"), "Revenue Recognition in Financial Statements." SAB 101 outlines the basic criteria that must be met to recognize revenue and provides guidance for disclosure related to revenue recognition policies. In June 2000, the SEC issued SAB 101B that delayed the implementation date of SAB 101 until the quarter ended December 31, 2000, with retroactive application to the beginning of our fiscal year. The adoption of SAB 101 did not have a material impact on our financial position or results of operations. In March 2000, the Financial Accounting Standards Board issued interpretation No. 44, "Accounting for Certain Transactions Involving Stock Compensation - An interpretation of APB No. 25" ("FIN 44"). FIN 44 clarified the application of Opinion No. 25 in certain respects, including; the definition of "employee" for purposes of applying Opinion No. 25; the criteria for determining whether a plan qualifies as a non-compensatory plan; the accounting consequences of various modifications to the terms of a previously fixed stock option or award; and the accounting for an exchange of stock compensation awards in a business combination. In general, FIN 44 became effective July 1, 2000. The adoption of FIN 44 did not have a material impact on our financial position or results of operation. In June 2001, the Financial Accounting Standards Board finalized FASB Statements No. 141, Business Combinations (SFAS 141), and No. 142, Goodwill and Other Intangible Assets (SFAS 142). SFAS 141 requires the use of the purchase method of accounting and prohibits the use of the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001. SFAS 141 also required that the Company recognize acquired intangible assets apart from goodwill if the acquired intangible assets meet certain criteria. SFAS 141 applies to all business combinations initiated after June 30, 2001 and for purchase business combinations completed on or after July 1, 2001. It also requires, upon adoption of SFAS 142 that the Company reclassify the carrying amounts of intangible assets and goodwill based on the criteria in SFAS 141. SFAS 142 requires, among other things, that companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS 142 requires that the Company identify reporting units for the purposes of assessing potential future impairments of goodwill and to reassess the amortization of intangible assets with an indefinite useful life. An intangible asset with an indefinite useful life should be tested for impairment in accordance with SFAS 142. SFAS 142 is required to be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized at that date, regardless of when those assets were initially recognized. SFAS 142 requires the Company to complete a transitional goodwill impairment test six months from the date of adoption. The Company is also required to reassess the useful lives of other intangible assets within the first interim quarter after adoption of SFAS 142. Currently, the Company is assessing but has not yet determined how the adoption of SFAS 141 and SFAS 142 will impact its financial position and results of operations. -10- ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Restatement of Financial Statements. During our bankruptcy, the court approved a motion to reject a fixed-price physical delivery contract. A claim was filed by the damaged party resulting in the recording of an estimated liability of $17,559,272 to reorganization costs. Subsequent to the filing of our original report on Form 10-Q for the quarter ended September 30, 2001, additional information became available to us which resulted in a $737,022 increase to the original estimate. The following discussion of our results of operations and financial condition includes the restated results of operations and financial condition of our former parent for periods presented prior to July 27, 2001, our subsidiary and us on a consolidated basis. Our consolidated financial statements and the related notes contain additional detailed information that should be referred to when reviewing this material. GENERAL We are an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties in three core areas. We commenced operations in 1992 and from our inception until mid-1996 we primarily acquired and developed properties onshore in south and southeast Texas. We expanded into the Sacramento Basin of northern California with our acquisition of Reunion in 1996. We established a core area of operation in the shallow waters of the Gulf of Mexico in 1997 with acquisitions from Apache and Statoil. In 1998 we expanded our onshore Gulf Coast properties by completing our largest acquisition to date, the $63.0 million acquisition of onshore Texas oil and natural gas properties from Apache. We have since focused our efforts and capital resources on developing our assets. We have one subsidiary, Tri-Union Operating Company, which is wholly owned by us. Tri-Union Operating's principal asset is a net profits interest in a field operated by us. This interest is the only oil and natural gas property of Tri-Union Operating and represents less than 5% of our consolidated proved reserves. In March 1998, we acquired certain onshore Texas oil and natural gas properties from Apache Corporation with the proceeds from a short-term, amortizing bank loan. In August 1998, before we were able to refinance our bank loan, commodity prices began falling, with oil prices ultimately reaching a 12-year low in December 1998. The resultant negative effect on our cash flow from the deterioration of commodity prices, coupled with the required amortization payments on our bank loan, severely restricted the amount of capital we were able to dedicate to development drilling. Consequently, our oil and natural gas production declined, further negatively affecting our cash flow. In October 1998, our short-term loan matured and we arranged a forbearance agreement providing for interest payments to be partially capitalized. In July 1999, this forbearance agreement terminated and we made negotiated interest payments while attempting to negotiate a restructuring of our obligations. On March 14, 2000, we chose to seek protection under Chapter 11 of the U.S. Bankruptcy Code. Tri-Union Operating continued to operate outside of bankruptcy. On July 18, 2001, we sold in a private unit offering $130,000,000 of old notes, each unit consisting of one old note in the principal amount of $1,000 and one share of class A common stock of Tribo Petroleum Corporation, our former parent corporation. The proceeds from the units offering and our available cash balances were sufficient to allow us to pay or segregate funds for the payment of all creditor claims in full, including interest, and to exit bankruptcy on June 18, 2001. At December 31, 2000, our net proved reserves were 180.1 Bcfe with a PV-10 Value of $630.0 million. At December 31, 1999, our net proved reserves were 205.2 Bcfe with a PV-10 Value of $292.5 million. While our total proved reserves quantities at December 31, 2000 decreased by 12% versus those at December 31, 1999, our proved developed producing reserves actually increased by 3% over the same period. The decrease in total proved reserves was primarily due to lease expirations that resulted in the loss of proved undeveloped reserves in our offshore Gulf Coast area. These leases expired as a consequence of our inability to obtain approval from the bankruptcy court to make the significant capital investments required to maintain these leases. Our capital budget has been primarily focused on converting proved developed non-producing and proved undeveloped reserves to production. -11- During 1998, 1999, 2000 and the first nine months of 2001, our capital expenditures on oil and gas activities totaled approximately $72.0 million, $13.6 million, $10.9 million and $10.7 million, respectively. These expenditures related to operations in our three core areas. In 1998, 87% of our capital expenditures were related to the acquisitions of reserves. In 1999 and 2000, a total of $10.6 million, or 44% of our capital expenditures were for development drilling and recompletions. The remaining 56% was incurred on items such as platform and pipeline improvements that were identified at the time of our acquisition of the properties, compressor installations and on 3-D seismic surveys. During 1999 and 2000 our development capital investments of $10.6 million were expended to complete 28 development wells, exploitation wells and recompletions. With our working capital from the offering and cash flow from operations, we plan to significantly increase our capital budget for the remainder of 2001 and 2002 to $34.2 million, to complete 93 development drilling, exploitation and recompletion projects. On July 27, 2001, we were the surviving corporation in a merger with our parent corporation, Tribo Petroleum Corporation. As a consequence of this merger, we assumed all of the rights and obligations of Tribo, including those under the indenture. The financial information contained herein is the consolidated financial information for Tribo, our subsidiary and us. We use the full cost method of accounting for oil and natural gas property acquisition, exploitation and development activities. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and development of oil and natural gas reserves are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals and the costs of drilling, completing and equipping oil and natural gas wells. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and natural gas reserves. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. RESULTS OF OPERATIONS Three Months Ended September 30, 2001 Compared to Three Months Ended September 30, 2000 For the three months ended September 30, 2001, consolidated net income was $2,453,750, a 48% decrease over consolidated net income of $4,734,473 for the three months ended September 30, 2000. Earnings before interest, taxes, depreciation, amortization, gains or losses on derivative contracts, and reorganization costs was $6,014,423 for the three months ended September 30, 2001 as compared to $12,584,870 for the three months ended September 30, 2000. OIL AND GAS REVENUES. Oil and natural gas revenues decreased $8,868,800, or 40%, to $13,398,527 for the three months ended September 30, 2001, from $22,267,327 for the three months ended September 30, 2000. The decrease in oil and natural gas revenues was primarily the result of a decrease in production volumes and a substantial decrease in the average price we received for natural gas during the period. The following table summarizes the consolidated results of oil and natural gas production and related pricing for the three months ended September 30, 2001 and 2000:

GAIN OR LOSS ON MARKETABLE SECURITIES. We recognized $139,556 in losses on marketable securities for the three months ended September 30, 2001, as compared to gains of $76,972 for the three months ended September 30, 2000. Marketable securities bought and held principally for the purpose of sale in the near term are classified as trading securities. Trading securities are recorded at fair value on the balance sheet as current assets, with the change in fair value recognized during the period included in earnings. -12- GAIN ON DERIVATIVES CONTRACT. In connection with the issuance of the senior secured notes, we agreed to maintain, subject to certain conditions, on a monthly basis, a rolling two-year derivatives contract until the maturity of the notes on approximately 80% of our projected oil and natural gas production from proved developed producing reserves and the basis differential attributable to approximately 80% of our projected proved developed producing natural gas production from our California properties. We currently have a derivatives contract in place through September 30, 2003 at estimated net realized prices that we expect will exceed $4.04 per Mcf and $24.97 per Bbl, or a weighted natural gas-equivalent price of approximately $4.10 per Mcfe. The estimated fair value of this derivatives contract at September 30, 2001 resulted in the recording of a gain on derivatives contract of $8,365,229 for the three months ended September 30, 2001. OTHER (LOSS) INCOME. Other income decreased $122,214 or 258%, to a loss of $74,846 for the three months ended September 30, 2001 from income of $47,367 for the three months ended September 30, 2000. The decrease was the result of a loss on the sale of zero coupon U.S. Treasury bonds which had a maturity of 2019, held in trust and pledged to the Minerals Management Service ("MMS") for the plugging and abandonment of certain wells and the decommissioning of offshore platforms. The sale of these bonds was necessary as a result of a change in MMS collateral requirements. LEASE OPERATING EXPENSE. Lease operating expense decreased $828,910, or 15%, to $4,607,123 for the three months ended September 30, 2001 from $5,436,034 for the three months ended September 30, 2000. Lease operating expense was $1.36 per Mcfe for the three months ended September 30, 2001, an increase of 11% from $1.22 per Mcfe for the three months ended September 30, 2000. The decrease in lease operating expense is primarily the result of a decrease in the costs of maintenance and repairs, saltwater disposal and dehydration. Additionally, lease operations on certain properties were no longer necessary upon the sale of our Ship Shoal 58 field in June 2001 and the plugging and decommissioning of the West Cameron 531, South Marsh Island 232 and Brazos 476 wells. WORKOVER EXPENSE. Workover expense decreased $1,778,329, or 67%, to $884,596 for the three months ended September 30, 2001 from $2,662,926 for the three months ended September 30, 2000. Workover expense was $0.26 per Mcfe for the three months ended September 30, 2001, a decrease of 56% from $0.60 per Mcfe for the three months ended September 30, 2000. During the three months ended September 30, 2000, a workover program was commenced that included normal and recurring workovers and a backlog of workovers from 1998 and 1999 resulting in a higher than usual occurrence of workover expense. PRODUCTION TAXES. Production taxes decreased by $265,403 or 45% to $327,232 for the three months ended September 30, 2001 from $592,635 for the three months ended September 30, 2000. Production taxes were $0.10 per Mcfe for the three months ended September 30, 2001, a decrease of 28% from $0.13 per Mcfe for the three months ended September 30, 2000. Decreases in oil and natural gas production and revenues during the three months ended September 30, 2001 resulted in a decrease in the amount of production taxes paid during the period. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"): DD&A expense decreased by $436,642, or 12%, to $3,147,998 for the three months ended September 30, 2001 from $3,584,641 for the three months ended September 30, 2000. DD&A was $0.93 per Mcfe for the three months ended September 30, 2001, an increase of 15% from $0.81 per Mcfe for the three months ended September 30, 2000. The decrease in DD&A is the result of a decrease in production volumes during the three months ended September 30, 2001. GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"): G&A increased $235,550, or 21%, to $1,350,191 for the three months ended September 30, 2001 from $1,115,201 for the three months ended September 30, 2000. G&A was $0.40 per Mcfe for the three months ended September 30, 2001, an increase of 59% from $0.25 per Mcfe for the three months ended September 30, 2000. The increase was primarily the result of an increase in legal fees incurred and an increase in salary and director fee expenses incurred during the three-month period ended September 30, 2001. INTEREST EXPENSE. Interest expense increased $4,173,683 or 124%, to $7,529,222 for the three months ended September 30, 2001 from $3,355,539 for the three months ended September 30, 2000. The increase is primarily the result of non-cash amortization of bond discount and deferred loan costs to -13- interest expense of $1,857,492 and $1,507,065 respectively, for the three months ended September 30, 2001 and 2000. REORGANIZATION COSTS: TDC filed a voluntary petition for relief under the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division on March 14, 2000. As a result, we incurred certain reorganization costs totaling $1,427,480 for the three months ended September 30, 2001, a 57% increase from $910,217 for the three months ended September 30, 2000. These reorganization costs consist of the following: Professional fees and other - We were required to hire certain legal and accounting professionals to assist us and certain of our creditors with the bankruptcy proceedings. Interest and amounts paid to creditors - Represents payments of amounts owed to creditors with pre-petition claims, including interest. Satisfaction of certain related party transactions - We entered into an agreement whereby we transferred to Atasca certain oil and gas properties and marketable securities owned by Tribo Petroleum Corporation and assigned to Atasca the net obligations owed to us by Richard Bowman, the Company's Chief Executive Officer. Additionally, we released Tribo Production Company, Ltd., BL Production Co., Ltd., and Atasca Properties, Ltd. from the net obligations they each owe to us. After giving effect to these transactions, all balances owing to and from us and these related parties have been satisfied. Interest - Interest income earned during bankruptcy has been recorded as an offset to reorganization costs as prescribed by SOP 90-7. The following table summarizes our reorganization costs incurred:

PROVISION FOR INCOME TAXES. The Company recognized a benefit for income taxes in the amount of $178,798 for the three months ended September 30, 2001, as the Company incurred a taxable loss for the three month period. No provision for federal income tax was required for the three months ended September 30, 2000. Nine Months Ended September 30, 2001 Compared to Nine Months Ended September 30, 2000 For the nine months ended September 30, 2001, consolidated net income was $21,634,397, a 187% improvement over consolidated net income of $7,541,003 for the nine months ended September 30, 2000. Earnings before interest, taxes, depreciation, amortization, gains or losses on derivatives contracts, and reorganization costs was $42,849,286 for the nine months ended September 30, 2001 as compared to $28,433,780 for the nine months ended September 30, 2000. OIL AND GAS REVENUES. Oil and natural gas revenues increased $19,610,424, or 40%, to $68,065,015 for the nine months ended September 30, 2001, from $48,454,590 for the nine months ended September 30, 2000. The increase in oil and natural gas revenues was primarily the result of an increase in production volumes and a substantial increase in the average price we received for natural gas during the period, which may not reflect the prices we receive in future periods. The following table summarizes the consolidated results of oil and natural gas production and related pricing for the nine months ended September 30, 2001 and 2000: -14-

GAIN OR LOSS ON MARKETABLE SECURITIES. We recognized $556,735 in losses on marketable securities for the nine months ended September 30, 2001, as compared to gains of $979,667 for the nine months ended September 30, 2000. Marketable securities bought and held principally for the purpose of sale in the near term are classified as trading securities. Trading securities are recorded at fair value on the balance sheet as current assets, with the change in fair value recognized during the period included in earnings. GAIN ON DERIVATIVES CONTRACT. In connection with the issuance of the senior secured notes, we agreed to maintain, subject to certain conditions, on a monthly basis, a rolling two-year derivatives contract, until the maturity of the notes on approximately 80% of our projected oil and natural gas production from proved developed producing reserves and the basis differential attributable to approximately 80% of our projected proved developed producing natural gas production from our California properties we currently have under a derivatives contract in place through September 30, 2003 at estimated net realized prices of $4.04 per Mcf and $24.97 per Bbl, or a weighted natural gas-equivalent price of approximately $4.10 per Mcfe. The estimated fair value of this derivatives contract at September 30, 2001 resulted in the recording of a gain on derivatives contract of $11,951,855 during the nine months ended September 30, 2001. OTHER INCOME. Other income increased $355,402 or 76%, to $822,076 for the nine months ended September 30, 2001 from $466,674 for the nine months ended September 30, 2000. The increase was primarily the result of the sale of emission reduction credits from our Hastings Field. This increase was partially offset by a loss on the sale of zero coupon U.S. Treasury bonds which had a maturity of 2019, held in trust and pledged to the Minerals Management Service ("MMS") for the plugging and abandonment of certain wells and the decommissioning of offshore platforms. The sale of these bonds was necessary as a result of a change in MMS collateral requirements. LEASE OPERATING EXPENSE. Lease operating expense increased $2,847,376, or 23%, to $15,087,552 for the nine months ended September 30, 2001 from $12,240,176 for the nine months ended September 30, 2000. Lease operating expense was $1.24 per Mcfe for the nine months ended September 30, 2001, an increase of 12% from $1.10 per Mcfe for the nine months ended September 30, 2000. The increase in lease operating expense is primarily the result of higher electricity and fuel costs, an increase in the number of producing wells and MMS compliance work at our Matagorda Island A-4 and Brazos 104 facility during the first half of 2001. This increase was partially offset by a decrease in the costs of maintenance and repairs, saltwater disposal and dehydration during the third quarter of 2001. Additionally, lease operations on certain properties were no longer necessary after the sale of our Ship Shoal 58 field in June 2001 and the plugging and decommissioning of the West Cameron 531, South Marsh Island 232 and Brazos 476 wells. WORKOVER EXPENSE. Workover expense decreased $135,098, or 3%, to $4,224,725 for the nine months ended September 30, 2001 from $4,359,824 for the nine months ended September 30, 2000. Workover expense was $0.35 per Mcfe for the nine months ended September 30, 2001, a decrease of 12% from $0.39 per Mcfe for the nine months ended September 30, 2000. During the first half of 2000, workover spending was minimized. During the remainder of 2000 and the first half of 2001, a workover program was completed that included normal and recurring workovers and a backlog of workovers from 1998 and 1999. PRODUCTION TAXES. Production taxes increased by $363,732 or 28% to $1,668,808 for the nine months ended September 30, 2001 from $1,305,076 for the nine months ended September 30, 2000. -15- Production taxes were $0.14 per Mcfe for the nine months ended September 30, 2001, an increase of 17% from $0.12 per Mcfe for the nine months ended September 30, 2000. Increases in oil and natural gas production and revenues during the nine months ended September 30, 2001 resulted in an increase in the amount of production taxes paid during the period. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"): DD&A expense increased by $1,431,078, or 16%, to $10,410,040 for the nine months ended September 30, 2001 from $8,978,962 for the nine months ended September 30, 2000. DD&A was $0.86 per Mcfe for the nine months ended September 30, 2001, an increase of 6% from $0.81 per Mcfe for the nine months ended September 30, 2000. Increased oil and natural gas production during the nine months ended September 30, 2001 resulted in an increase in the amount of depletion computed on those volumes. GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"): G&A increased $937,910, or 26%, to $4,499,985 for the nine months ended September 30, 2001 from $3,562,075 for the nine months ended September 30, 2000. G&A was $0.37 per Mcfe for the nine months ended September 30, 2001, an increase of 15% from $0.32 per Mcfe for the nine months ended September 30, 2000. The increase was primarily the result of an increase in legal fees incurred and an increase in salary and director fee expenses incurred during the first nine months of 2001. INTEREST EXPENSE. Interest expense increased $3,716,683, or 37%, to $13,805,472 for the nine months ended September 30, 2001 from $10,088,789 for the nine months ended September 30, 2000. The increase is primarily the result of non-cash amortization of bond discount and deferred loan costs to interest expense of $2,119,964 and $1,713,356 respectively, for the nine months ended September 30, 2001 and 2000. REORGANIZATION COSTS: TDC filed a voluntary petition for relief under the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division on March 14, 2000. As a result, we incurred certain reorganization costs totaling $8,738,588 for the nine months ended September 30, 2001, a 379% increase from $1,825,026 for the nine months ended September 30, 2000. These reorganization costs consist of the following: Professional fees and other - We were required to hire certain legal and accounting professionals to assist us, and certain of our creditors with the bankruptcy proceedings. Retention - In an effort to maintain our employees through the bankruptcy period, we paid a retention bonus to our employees during the months of June and July 2001. Additional bank and refinancing charges - We incurred additional fees and costs associated with the payoff of our previous bank debt. Interest and amounts paid to creditors - Represents payments of amounts owed to creditors with pre-petition claims, including interest. Satisfaction of certain related party transactions - We entered into an agreement whereby we transferred to Atasca certain oil and gas properties and marketable securities owned by Tribo Petroleum Corporation and assigned to Atasca the net obligations owed to us by Richard Bowman. Additionally, we released Tribo Production Company, Ltd., BL Production Co., Ltd., and Atasca Properties, Ltd. from the net obligations they each owe to us. After giving effect to these transactions, all balances owing to and from us and these related parties have been satisfied. Interest - Interest income earned during bankruptcy has been recorded as an offset to reorganization costs as prescribed by SOP 90-7. -16- The following table summarizes our reorganization costs incurred:

PROVISION FOR INCOME TAXES. A $212,644 provision for income tax was made for the nine months ended September 30, 2001, primarily as a result of alternative minimum tax requirements. No provision for federal income tax was required for the nine months ended September 30, 2000. LIQUIDITY AND CAPITAL RESOURCES In March 1998, TDC acquired certain onshore Texas oil and natural gas properties from Apache Corporation. Prior to the acquisition, we had approximately $35 million in debt outstanding. We incurred an additional $63 million in debt in connection with the acquisition. We utilized funds from a short-term, amortizing bank loan in connection with the acquisition of Reunion. In August 1998, before we were able to refinance our bank loan, commodity prices began falling, with oil prices ultimately reaching a 12-year low in December of that year. The resultant negative effect on our cash flow from the deterioration of commodity prices, coupled with the required amortization on our bank loan, severely restricted the amount of capital we were able to dedicate to development drilling. Consequently, our oil and natural gas production declined, further negatively affecting our cash flow. In October 1998, our short-term loan matured and we arranged a forbearance agreement providing for interest payments to be partially capitalized and providing us with additional time to refinance our obligation. In July 1999, this forbearance agreement terminated and we made negotiated interest payments while attempting to negotiate a restructuring of our obligations. By March 2000, the aggregate principal balance of our bank debt has increased as a result of capitalization of interest and expenses to approximately $105 million. In February 2000, the bank declared a default on the loan, demanded payment of all principal and interest and posted the shares of Tribo Petroleum Corporation, our parent corporation and a guarantor of the loan, for foreclosure. As a consequence of the bank's foreclosure action, on March 14, 2000, we filed for bankruptcy protection. After the filing, we operated as a "debtor-in-possession," continuing in possession of our estate, the operation of our business and the management of our properties. Under Chapter 11, certain claims against us in existence prior to the filing of the petition were stayed from enforcement or collection. These claims are reflected in full in the consolidated December 31, 2000 balance sheet as "pre-petition liabilities subject to compromise." We filed our amended plan of reorganization in the bankruptcy court on May 9, 2001. Our plan was confirmed by a court order entered as of May 23, 2001, subject to the completion of an offering of the notes and class A common stock. On June 18, 2001, the offering closed and we exited from bankruptcy. The proceeds of the offering and our available cash balances at closing were sufficient to allow us to pay or segregate funds for the payment of all claims. At September 30, 2001, we had $130.0 million of 12.5% senior secured notes. The notes mature on June 1, 2006 and require amortization payments of the greater of $20 million and 15.3% as of June 1, 2002 and 2003 and an amortization payment of the greater of $15 million and 11.5% as of June 1, 2004. Interest is payable semi-annually on June 1 and December 1 of each year. During the nine months ended September 30, 2001, our cash balances decreased by $21,448,847 to $11,541,092 from $32,989,939 at December 31, 2000. Net cash used by operating activities before reorganization items was $11,980,753 for the nine months ended September 30, 2001. The increase is the result of a decrease in accounts payable, accounts receivables and prepaid expenses for the nine months ended September 30, 2001. Additionally, we have $9,497,992 deposited into restricted cash as required by our plan of reorganization to satisfy the payment in full of all remaining disputed pre-petition claims. These uses of cash were partially offset by an increase in net income of $21,634,397 after reorganization costs of $8,738,588 and income from hedging contract of $11,951,855 for the nine months ended September 30, 2001, when -17- compared to net income of $7,541,003 after reorganization costs of $1,825,026 for the nine months ended September 30, 2000. Net cash used in investing activities was $10,060,058 for the nine months ended September 30, 2001 when compared to $8,368,867 for the nine months ended September 30, 2000. The increase is primarily the result of an increase in proceeds from the sales of oil and natural gas properties of $1,835,558, to $2,225,529 for the nine months ended September 30, 2001 from $389,971 for the nine months ended September 30, 2000. Additionally, additions to oil and natural gas properties and other equipment increased $2,097,294 to $11,677,425 for the nine months ended September 30, 2001 from $9,580,131 for the nine months ended September 30, 2000. This increase is partially offset by a decrease in proceeds from the sale of marketable securities of $1,316,851 to $555,964 for the nine months ended September 30, 2001 from $1,872,815 for the nine months ended June 30, 2000. Net cash provided by financing activities was $5,851,936 for the nine months ended September 30, 2001 when compared to net cash used of $739,929 for the nine months ended September 30, 2000. The increase is the result of the completion of the senior notes offering on June 18, 2001 resulting in our exit from bankruptcy. The net cash proceeds from the offering provided sufficient available cash, allowing us to pay or segregate funds for the payment of all claims. The following table sets forth information concerning our oil and natural gas property acquisition, exploration and development activities and the related costs during the year's ended December 31, 1998, 1999 and 2000 and the nine months ended September 30, 2001:

CAPITAL REQUIREMENTS Historically, our principal sources of capital have been cash flows from operations, short-term reserve-based bank loans, private placement units, and proceeds from asset sales. Our principal uses for capital have been the acquisition and development of oil and natural gas properties. On June 18, 2001, TDC emerged from bankruptcy by way of the issuance of $130 million in face value notes and 130,000 shares of Class A common stock. The notes bear interest at 12.5% per annum and mature June 2006. The net proceeds of $113,444,294 and cash on hand at closing were used to satisfy certain pre-petition obligations, retire an existing bank loan, and provide sufficient working capital for the company's oil and natural gas operations, capital expenditure and recompletion program. At September 30, 2001, our cash balance was $11.5 million. Our budget for 2001 includes capital expenditures of $17.1 million, representing an increase of 57% over our total capital expenditures for 2000. We expect to use approximately $14.6 million of this amount for development drilling and recompletions, approximately $1.7 million to conduct two 3-D seismic surveys over certain leases in California and $0.8 million for other geological and geophysical expenditures. At September 30, 2001, we had expended $10.7 of our development and drilling budget for 2001. At September 30, 2001, we had $130.0 million of 12.5% senior secured debt. The notes mature on June 1, 2006 and have a required amortization payment of the greater of $20 million and 15.3% on June 1, 2002. Interest is payable semi-annually on June 1 and December 1 of each year, with the first such payment payable on December 1, 2001. Net cash flows from operations and proceeds from asset sales are expected to provide sufficient cash flows to allow us to meet our obligations. -18- RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 ("FAS 133"), "Accounting for Derivative Instruments and Hedging Activities." FAS 133, as amended by FAS 137, is effective for transactions entered into after June 15, 2000. FAS 133 requires that all derivative instruments be recorded on the balance sheet at fair value. Changes in the fair value of derivatives are recorded for each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. The ineffective portion of all hedges will be recognized in earnings. As of January 1, 2001, the Company adopted FAS 133. In December 1999, the SEC issued Staff Accounting Bulletin No. 101 ("SAB 101"), "Revenue Recognition in Financial Statements." SAB 101 outlines the basic criteria that must be met to recognize revenue and provides guidance for disclosure related to revenue recognition policies. In June 2000, the SEC issued SAB 101B that delayed the implementation date of SAB 101 until the quarter ended December 31, 2000, with retroactive application to the beginning of our fiscal year. The adoption of SAB 101 did not have a material impact on our financial position or results of operations. In March 2000, the Financial Accounting Standards Board issued interpretation No. 44, "Accounting for Certain Transactions Involving Stock Compensation - An interpretation of APB No. 25" ("FIN 44"). FIN 44 clarified the application of Opinion No. 25 in certain respects, including; the definition of "employee" for purposes of applying Opinion No. 25; the criteria for determining whether a plan qualifies as a non-compensatory plan; the accounting consequences of various modifications to the terms of a previously fixed stock option or award; and the accounting for an exchange of stock compensation awards in a business combination. In general, FIN 44 became effective July 1, 2000. The adoption of FIN 44 did not have a material impact on our financial position or results of operation. In June 2001, the Financial Accounting Standards Board finalized FASB Statements No. 141, Business Combinations (SFAS 141), and No. 142, Goodwill and Other Intangible Assets (SFAS 142). SFAS 141 requires the use of the purchase method of accounting and prohibits the use of the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001. SFAS 141 also required that the Company recognize acquired intangible assets apart from goodwill if the acquired intangible assets meet certain criteria. SFAS 141 applies to all business combinations initiated after June 30, 2001 and for purchase business combinations completed on or after July 1, 2001. It also requires, upon adoption of SFAS 142 that the Company reclassify the carrying amounts of intangible assets and goodwill based on the criteria in SFAS 141. SFAS 142 requires, among other things, that companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS 142 requires that the Company identify reporting units for the purposes of assessing potential future impairments of goodwill, reassess the amortization of intangible assets with an indefinite useful life. An intangible asset with an indefinite useful life should be tested for impairment in accordance with SFAS 142. SFAS 142 is required to be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized at that date, regardless of when those assets were initially recognized. SFAS 142 requires the Company to complete a transitional goodwill impairment test six months from the date of adoption. The Company is also required to reassess the useful lives of other intangible assets within the first interim quarter after adoption of SFAS 142. Currently, the Company is assessing but has not yet determined how the adoption of SFAS 141 and SFAS 142 will impact its financial position and results of operations. -19- ITEM 3. Quantitative and Qualitative Disclosures about Market Risk Commodities Price Swaps Derivative Instruments Used In Our Production We have entered into a natural gas and crude oil derivatives agreement with counter parties to manage commodities price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these derivative agreements, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market index, such as the NYMEX natural gas and crude oil futures and the PG&E Citygate Index. We entered into no commodities price swaps covering production in the first six months of 2001. The following table reflects the production volumes and the weighted average prices under our commodities price swaps (including settled swaps) at September 30, 2001.

The prices presented above are averages for each of the quarters indicated. At September 30, 2001, the commodities price swaps above represented approximately $12.0 million in income. -20- PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS From time to time, we are party to litigation or other legal proceedings that we consider to be a part of the ordinary course of our business. Other than as set forth below, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could reasonably be expected to have a materially adverse effect on our financial condition, cash flow or results of operations. Bankruptcy filing On March 14, 2000, we filed a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. We filed our amended plan of reorganization in the bankruptcy proceeding on May 9, 2001. Our plan provided for payment in cash, or segregation of funds for the payment, to each creditor of its full, allowed claim, including interest, on the closing date of the original offering. Our plan was confirmed by a court order on May 23, 2001, subject to the completion of the offering of the old notes. Upon the closing of the offering, we paid or segregated funds for the payment of all allowed claims in accordance with our plan and the court order and, except as specifically discussed below, lawsuits, administrative actions and other proceedings that arose prior to the confirmation were dismissed as to us. Claims that we dispute will be heard by the bankruptcy court. If claims are resolved for less than the amount segregated by us, we will receive the balance of the funds. Credit Lyonnais and Credit Lyonnais Securities In March 2000, Richard Bowman and we filed suit against Credit Lyonnais, New York Branch and Credit Lyonnais Securities (USA), Inc. in the 16th Judicial District Court of Harris County, Texas asserting claims for violations of the Federal Bank Tying Act, fraud and tortious interference. Credit Lyonnais filed a counterclaim against us seeking repayment of monies loaned to us by Credit Lyonnais, interest and attorney's fees. At the time these claims arose, Credit Lyonnais was our senior secured lender. Specifically, we alleged that we were wrongfully induced into incurring additional secured indebtedness associated with the acquisition of certain oil and natural gas properties from Apache Corporation. This additional indebtedness was to be refinanced on a short-term basis by a debt or equity offering underwritten or privately placed by Credit Lyonnais and/or its securities affiliate, Credit Lyonnais Securities, Inc. We alleged that Credit Lyonnais advised us that it would not increase our credit facility to an amount necessary to consummate the acquisition from Apache unless we entered into an agreement with Credit Lyonnais Securities to act as our exclusive financial advisor for such an offering. We agreed to enter into such an arrangement based upon representations made to us regarding the ability, experience and expertise of Credit Lyonnais Securities to assist us in such an offering. We further alleged that no meaningful effort was made on the part of Credit Lyonnais or Credit Lyonnais Securities to assist us in raising the funds necessary to refinance the credit facility. As part of the confirmation of our plan, Richard Bowman and we reached a settlement of this litigation in May 2001. The terms of the settlement included a reduction in the amount of the secured claim of Credit Lyonnais in the approximate amount of $3.3 million and our agreement not to dispute, other than for arithmetic error, the remainder of Credit Lyonnais' secured claim, in the approximate amount of $127.3 million, including principal, interest, fees and expenses as of May 31, 2001. Richard Bowman assigned his interest in the settlement to us. Aviara Energy Corporation On November 10, 1999, Aviara Energy Corporation filed suit against us in the 129th Judicial District Court of Harris County, Texas, alleging that we owe approximately $1.8 million in joint interest expenses under a participation and operating agreement. Aviara subsequently filed an amended proof of claim to add post-petition administrative expenses and interest of approximately $1.0 million to its claim. No action on this suit was taken during our bankruptcy. An agreed ordered was entered into and approved by the court on August 28, 2001 whereby Aviara would be paid $2,694,235 plus interest from March 14, 2000 to June 18, 2001 at 6% per annum. On September 5, 2001, funds were distributed from our restricted escrowed account in satisfaction of this claim. -21- Chieftain International On March 31, 1999, Chieftain International (U.S.) Inc. filed suit against us in the United States District Court for the Eastern District of Louisiana alleging that we owe joint interest expenses in the amount of approximately $3.0 million, together with accrued interest, attorneys' fees and costs, in connection with Chieftain's operation of two mineral leases. No action on this suit was taken during our bankruptcy. The plaintiff has filed a motion with the United States Bankruptcy Court for the Southern District of Texas, Houston Division, requesting that the state district court in Louisiana be allowed to liquidate the claim. The motion was granted and the case was remanded to state court in Louisiana. We intend to continue to vigorously defend this suit. Funds in the amount of approximately $5.5 million were segregated in accordance with our plan, pending the trial or resolution of this dispute in Louisiana. Seitel Data, Ltd. and DDD Energy, Inc. On December 13, 2000, Seitel Data, Ltd., and DDD Energy, Inc., filed suit against Tribo Petroleum Corporation in the 334th Judicial District of Harris County, Texas, alleging that Tribo owed approximately $0.8 million in damages, together with interest and attorney's fees for goods and services delivered for our benefit. Currently, an agreed order has been entered in the bankruptcy court to pay the full amount of this claim, together with interest, in accordance with our plan. Minerals Management Service We have reached a settlement with the MMS that resolves a civil enforcement action first brought against us in August 2000, with respect to certain alleged violations of MMS rules relating to the operation of our offshore facilities prior to the commencement of our bankruptcy proceedings. As part of the settlement, we have agreed to pay civil penalties in the amount of $506,500, with $25,325 paid out initially, and the remaining $481,175 paid out in quarterly installments over a two-year period. We have also agreed to provide the MMS with approximately $9.8 million in operators bonds. The settlement between the MMS and us is not an admission of liability with respect to the violations alleged by the MMS. Arch W. Helton, Helton Properties, Inc., and Linda Barnhill On May 28, 1997, Arch W. Helton and Helton Properties, Inc., filed suit against us in the 80th Judicial District Court of Harris County, Texas. Subsequently, Linda Barnhill joined as a plaintiff. The suit alleges that we owe additional royalties on oil and natural gas produced from February 1987 to date as to certain completions in oil and natural gas properties located in Alvin, Texas, that oil and natural gas was drained from approximately 18 acres in which they claim interests and seeks the recovery of attorneys' fees. As to certain of the plaintiffs' claims, we have obtained a favorable decision from the Texas Railroad Commission. An appeal of the decision by the plaintiffs is currently pending. We believe the decision will be affirmed and that, if affirmed, it could result in the full avoidance of all of the plaintiffs' claims. Even if the decision is not affirmed, we believe we have other defenses that could result in the full avoidance of the claims. We have filed a partial summary judgment on limitations and other defenses that is currently pending. We intend to continue to vigorously defend this suit. Funds in the amount of approximately $1.0 million have been segregated in accordance with our plan pending the resolution of this dispute by the bankruptcy court. We believe these funds are sufficient to cover our net interest in the full proof of claim filed in the amount of $3.0 million. -22- SIGNATURE Pursuant to the requirements 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. TRI-UNION DEVELOPMENT CORPORATION April 11, 2002 By: /s/ SUZANNE R. AMBROSE --------------------------------------------- Suzanne R. Ambrose, Vice President and Chief Financial Officer -23-

TRI UNION DEVELOPMENT CORP 10-Q/A