10-Q 1 h01204e10vq.txt TRI-UNION DEVELOPMENT CORPORATION - 9/30/2002 U.S. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002 Commission file number: 333-66282 TRI-UNION DEVELOPMENT 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 77006 HOUSTON, TEXAS (ZIP CODE) (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 [X] no [ ] AS OF NOVEMBER 19, 2002 THERE WERE 445,000 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 (SUCCESSOR TO TRIBO PETROLEUM CORPORATION) INDEX TO FINANCIAL INFORMATION Part I. Financial Information Item 1. Financial Statements Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2002 and 2001 (unaudited)................................................... 3 Consolidated Balance Sheets at September 30, 2002 (unaudited) and December 31, 2001 (audited)............................................................... 4 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2002 and 2001 (unaudited)................................................... 5 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................................. 23 Item 4. Controls and Procedures................................................................... 24 Part II. Other Information Item 1. Legal Proceedings......................................................................... 25 Item 2. Changes in Securities..................................................................... 26 Item 3. Defaults Upon Senior Securities........................................................... 26 Item 4. Submission of Matters to a Vote of Security Holders....................................... 27 Item 5. Forward Looking Statements................................................................ 28 Item 6. Exhibits and Reports on Form 8-K.......................................................... 29 Signatures ................................................................................................... 30 Section 302 Officers' Certification........................................................................... 31

2 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS TRI-UNION DEVELOPMENT CORPORATION (SUCCESSOR TO TRIBO PETROLEUM CORPORATION) CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

The accompanying notes are an integral part of these consolidated financial statements. 3 TRI-UNION DEVELOPMENT CORPORATION (SUCCESSOR TO TRIBO PETROLEUM CORPORATION) CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements. 4 TRI-UNION DEVELOPMENT CORPORATION (SUCCESSOR TO TRIBO PETROLEUM CORPORATION) CONSOLIDATED STATEMENTS OF CASH FLOWS INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (UNAUDITED)

5 TRI-UNION DEVELOPMENT CORPORATION (SUCCESSOR TO TRIBO PETROLEUM CORPORATION) CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (UNAUDITED) Supplemental Disclosures of Cash Flow Information: Interest paid $ 33,295 $ 19,525,512 Non-cash transactions: Discount on units offering - (24,750,000) Transfer of oil and natural gas properties to affiliate - 1,097,611 Purchase of derivative contracts with long-term liability 1,797,943 - Sale of oil and natural gas properties in exchange for receivable 998,192 - Issuance of class A common stock in consideration for modifying senior secured debt terms 850,000 - Conversion of accrued interest payable to senior secured debt 8,125,000 -

The accompanying notes are an integral part of these consolidated financial statements. 6 TRI-UNION DEVELOPMENT CORPORATION (SUCCESSOR TO TRIBO PETROLEUM CORPORATION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) NOTE 1 -- BASIS OF PRESENTATION Tri-Union Development Corporation ("the Company") successor to Tribo Petroleum Corporation ("Tribo") was incorporated in the State of Texas in September 1992. The Company with its subsidiary 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 the Company and its wholly owned subsidiary Tri-Union Operating Company ("TOC"), which was incorporated in the State of Delaware in November 1974. All significant intercompany accounts and transactions have been eliminated in consolidation. Prior to July 2001, the Company was a wholly owned subsidiary of Tribo. On July 27, 2001, the Company and Tribo merged and the surviving corporation was the Company. Accordingly, the assets, liabilities and operations of Tribo are included with those of the Company for all periods presented in the financial statements. NOTE 2 - LIQUIDITY, GOING CONCERN UNCERTAINTY AND MANAGEMENT'S PLANS On June 1, 2002, the Company was required to make a $28,125,000 payment of principle and interest on its senior secured notes, with an additional scheduled interest payment of approximately $7,400,000 due on December 1, 2002. In addition, the Company has a scheduled principal and interest payment of approximately $28,700,000 due June 1, 2003. The Company made its scheduled principal payment of $20,000,000 due on June 1, 2002, but refinanced its scheduled interest payment of $8,125,000 into additional promissory notes under the terms of a Waiver, Agreement and Supplemental Indenture (the "Waiver") (see Note 7). In connection with securing the Waiver, the Company issued 76,667 shares of class A common stock. The value of these shares was determined to be $850,000 and was recorded on the accompanying balance sheet as additional deferred loan costs and will be amortized over the remaining term of the senior secured notes. The Waiver contained additional covenants, one of which required the Company to obtain clear title to an oil and gas property subject to lien by no later than August 2, 2002. Additionally, the Waiver contained covenants requiring the Company to maintain average daily production of 28.5 Mmcfe and to generate $4.0 million of EBITDA, as adjusted for the non-cash effects of our oil and gas hedging contract as of the end of the third quarter of 2002. As the Company was unable to obtain clear title by that date, maintain the required average daily production levels, and did not report EBITDA of $4.0 million, an event of default occurred to the Waiver and the original Indenture whereby the senior secured notes became due on demand. Accordingly, the senior secured notes and related deferred loan costs have been classified as current in the accompanying consolidated balance sheet at September 30, 2002. While the Company continues to delay certain of its workover and capital improvement projects in order to maximize available cash to meet its debt obligations, the foregoing event of default could have a material impact on the Company's ability to meet its scheduled debt obligation and working capital requirements. Should the noteholders demand payment on the notes, the Company will not have the ability to generate sufficient resources to satisfy this obligation. These conditions raise substantial doubt about the Company's ability to continue as a going concern. The Company is currently marketing certain of its oil and gas properties in order to meet these scheduled debt obligations and working capital requirements. Several offers to purchase certain of the Company's oil and gas properties have been received to date which, if accepted, and combined with the Company's unrestricted cash balances at November 12, 2002 of approximately $4.6 million, would provide the Company with sufficient capital to meet its upcoming December 1, 2002 scheduled debt obligation. To the extent the cash generated from oil and gas property sales and continuing operations are insufficient to meet the Company's scheduled debt obligations and its projected working capital needs, the Company will have to raise additional capital. No assurance can be given that additional funding will be available, or if available, will be on terms acceptable to the Company. Uncertainty regarding the 7 amount and timing of any proceeds from the Company's plans to raise additional capital raises substantial doubt about the Company's ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might be necessary should the Company be unable to continue as a going concern. 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, 2002 and 2001, 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 ("GAAP"). 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, 2001 balance sheet was derived from audited financial statements and notes included in our annual report on Form 10-K. The interim unaudited financial statements for the three and nine months ended September 30, 2002 and 2001 should be read in conjunction with the Company's annual consolidated financial statements for the years ended December 31, 2001 and 2000. The results of operations for the three and nine months ended September 30, 2002, are not necessarily indicative of results to be expected for the full year. NOTE 4 - DERIVATIVE CONTRACTS On March 28, 2002, the Company terminated certain of its commodity price swap derivative contracts for net proceeds of approximately $2.3 million and replaced them with contracts providing for price floors at prices specified under the terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50 per barrel of crude oil. The gain of $2.3 million from the sale of the commodity price swap derivative contracts is included in gain (loss) on derivative contracts in the Company's consolidated statements of operations for the three and nine months ended September 30, 2002. The purchase price of the floor contracts of $1,797,943 is due and payable in full on July 1, 2003 and, accordingly, has been presented as a current liability in the accompanying consolidated balance sheet at September 30, 2002. The purchase price of the floor contracts is recognized as an offset to revenues in the accompanying consolidated statements of operations based upon the cost of the individual contracts purchased. During the three and nine months ended September 30, 2002, the Company recognized $277,285 and $461,137, respectively, of such costs as an offset to revenues. The Company maintains a rolling two-year combination of commodity price swaps and price floor agreements in order to manage the price risk associated with a portion of its production. These derivative transactions do not qualify for hedge accounting under Financial Accounting Standards Board ("FASB") Statement No. 133 and, accordingly, changes in the estimated value of derivative contracts held at the balance sheet date are recognized in the statement of operations as non-cash gains or losses on derivative contracts. Conversely, net cash settlements realized from the Company's derivative contracts are included in oil and natural gas revenues in the accompanying consolidated statements of operations. At September 30, 2002, the estimated fair value of the Company's derivative contracts held represents a net current liability of $1,248,279 and a net non-current liability of $1,772,008. During the three and nine months ended September 30, 2002, net cash settlements realized from the Company's derivative contracts amounted to approximately ($890,675) and $1,555,424, respectively. NOTE 5 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 2001, FASB issued Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations (SFAS No. 141), and No. 142, Goodwill and Other Intangible Assets (SFAS No. 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 No. 141 required the Company to recognize acquired intangible assets apart from goodwill if the acquired intangible assets meet certain criteria. SFAS No. 141 applies to all business combinations initiated after June 30, 2001, and for purchase business combinations completed on or after July 1, 2001. SFAS No. 141 also requires upon adoption of SFAS No. 142 that the Company reclassify the carrying amounts of intangible assets and goodwill based on the criteria in SFAS No. 141. SFAS No. 142 requires that 8 companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS No. 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 No. 142. SFAS No. 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 No. 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. The adoption of SFAS No. 141 and SFAS No. 142 did not materially impact the Company's financial position and results of operations. In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). SFAS No. 143 amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is applicable to all companies. SFAS No. 143, which is effective for fiscal years beginning after June 15, 2002, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. As used in SFAS No. 143, a legal obligation is an obligation that a party is required to settle as a result of an existing or enacted law, statue, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. While the Company is not yet required to adopt SFAS No. 143, it is not believed the adoption will have a material effect on its financial condition or results of operations. In August 2001, FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets ("SFAS No. 144"). SFAS No. 144, which supercedes SFAS No. 121, Accounting for the Impairment of Long-lived Assets and Long-lived Assets to be Disposed Of and amends Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001, and interim financials within those fiscal years, with early adoption encouraged. The provisions of SFAS No. 144 are generally to be applied prospectively. The Company does not believe the adoption of SFAS No. 144 will have a material effect on its financial condition or results of operations. In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. The statement also contains other nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. Adoption of this standard will not have any immediate effect on our consolidated financial statements. The Company will apply this guidance prospectively. On June 20, 2002, FASB's Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, and No. 00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10. The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be retroactively presented on a net basis in earnings. In addition, companies must disclose volumes of physically-settled energy trading contracts. The Company is evaluating the impact of this new consensus on the presentation of its consolidated income statement but believes it will not have a material impact on total revenues and expenses. The consensus will have no impact on net income. 9 In June 2002, FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3. The Company will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost is recognized at the date of a company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amount recognized. Adoption of this standard will not have any immediate effect on our consolidated financial statements. The Company will apply this guidance prospectively. NOTE 6 - OIL AND NATURAL GAS PROPERTIES During May 2002, the Company sold certain of its oil and natural gas properties for approximately $7,700,000. Consistent with the Company's policy of accounting for its oil and natural gas properties using the full cost method, the sales price was credited to oil and natural gas properties with no corresponding gain or loss recorded as a result of the sale transactions. Among those properties sold was the Company's interest in the Scott, Clear Branch and Rayne Fields in Louisiana for $6,450,000. Subject to the terms of the sale, the Company entered into a Holdback Agreement whereby $998,192 of the total sales price was held back pending completion of a post-closing review. The hold back amount has been included in accounts receivable in the accompanying Consolidated Balance Sheet at September 30, 2002. During the second quarter of 2002, the Company participated in the successful drilling and completion of the Champion #1-H well in Grimes County, Texas. The well was brought into production during the second quarter of 2002 for a net cost to the Company of $2,328,494. Currently, the title to this well is in dispute. As a result, the net cost to drill and complete the well, offset by $559,098 of production revenue and $13,498 of lease operating expense is shown on the accompanying balance sheet as other assets at September 30, 2002, pending resolution of the title dispute. Note 7 - Contingencies The Company is currently involved in various legal disputes with its former Chief Executive Officer in which he alleges certain members of the Company's board of directors violated fiduciary duties to the Company's shareholders by entering into the Waiver. The suit further alleges the Company entered into the Waiver transaction with the intended effect of diluting the former executive to a minority interest in the Company. Additionally, the Company has filed claims against the former executive, and related entities, alleging breach of fiduciary responsibility with respect to improper use and diversion of corporate funds used to improve a property, owned by an entity related to the former executive, for which title has not been properly conveyed to the Company. Although the outcome of these matters is uncertain, the Company does not anticipate that their resolution will have a material adverse impact on the Company's consolidated financial position or results of operations. 10 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion of our financial condition and results of operations and financial condition includes the results of operations and financial condition of our former parent for periods presented prior to July 27, 2001, and 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, onshore Gulf Coast, Gulf of Mexico and the Sacramento Basin of northern California. 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 representing 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 senior secured notes, each unit consisting of one 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 unit 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, 2001, our net proved reserves were 191.7 Bcfe with a PV-10 Value of $143.8 million and $160.8 million including our hedge position value at such date. Our total proved reserve quantities at December 31, 2001 increased by 6% versus those at December 31, 2000. The increase in total proved reserves was primarily due to two factors: first, based on recent drilling and recompletion successes, we have been able to add a number of additional proved undeveloped ("PUD's") and behind-pipe locations on our California assets; secondly, a recent 3-D seismic survey conducted over our Barber's Hill property has enabled us to delineate and add a PUD location in that field. Our capital budget has been primarily focused on converting proved developed non-producing and proved undeveloped reserves to production. During 1999, 2000, 2001 and the first nine months of 2002, our capital expenditures on oil and gas activities totaled approximately $13.6 million, $10.9 million, $13.6 million and $5.2 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, 44%, or $10.6 million, 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 11 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. During 2001 and the first nine months of 2002, our development capital investments of $13.6 million and $5.2 million were expended on a large offshore recompletion, the plugging and abandonment of four offshore facilities and the recompletion or drilling of approximately 58 other 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 governing the senior secured notes. The financial information contained herein is the consolidated financial information for Tribo, our subsidiary and us. On June 13, 2002, our Chief Executive Officer and President, Richard Bowman, resigned his positions and was replaced by James M. Trimble, effective July 19, 2002. Mr. Bowman retains ownership of approximately 47% of the Company's outstanding common stock. 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, 2002 Compared to Three Months Ended September 30, 2001 For the three months ended September 30, 2002, consolidated net loss was $7,205,271 as compared to consolidated net income of $2,453,750 for the three months ended September 30, 2001. OIL AND GAS REVENUES. Oil and natural gas revenues decreased $5,464,287, or 41%, to $7,934,240 for the three months ended September 30, 2002, from $13,398,527 for the three months ended September 30, 2001. The decrease in oil and natural gas revenues was primarily the result of a decrease in production volumes and a decrease in the average price we received for natural gas during the period. During the second quarter of 2002, the Company sold certain of its Texas Gulf Coast and all of its Louisiana properties. The decline in production volumes is further attributable to a reduction in production from our Westbury Farm #1 well in the Constitution field due to 2 wells drilled on adjoining acreage, not owned or operated by us, directly offsetting our production. Further contributing to the production decline are two wells that watered-out in our Ord Bend field in California. After watering out, these 2 wells were recompleted to two zones at reduced production rates. Additionally, production from our North Alvin, Spindletop, Sour Lake, South Liberty and Hastings fields experienced abnormal production declines partially due to a curtailed workover program during the second and third quarters of 2002. The following table summarizes the consolidated results of oil and natural gas production and related pricing for the three months ended September 30, 2002 and 2001:

LOSS ON MARKETABLE SECURITIES. We recognized $139,556 in losses on marketable securities for the three months ended September 30, 2001. 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 12 fair value on the balance sheet as current assets, with the change in fair value recognized during the period included in earnings. For the three months ended September 30, 2002, we held no marketable securities for trading purposes. LOSS ON DERIVATIVE CONTRACTS. 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. Additionally, in June 2001, we entered into two-years of derivative contracts on the basis differential attributable to approximately 80% of our projected proved developed producing natural gas production from our California properties. These derivative contracts do not qualify for hedge accounting under FAS 133, therefore, the Company marks these transactions to fair value. On March 31, 2002, we terminated certain of our derivative contracts and replaced them with contracts providing for price floors at the prices specified under the terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50 per barrel of crude oil. Proceeds from the sale of these contracts were approximately $2.3 million. The purchase price of the floor contracts of approximately $1.8 million has been financed by the Company's derivative contracts counterparty. The change in estimated fair value of these contracts during the three months ended September 30, 2002 resulted in a net non-cash loss on derivative contracts of $369,475 when compared to net non-cash income on derivative contracts of $8,365,229 during the three months ended September 30, 2001. OTHER. Other income increased $179,413 or 240% to $104,567 for the three months ended September 30, 2002 when compared to a loss $74,846 for the three months ended September 30, 2001. The increase was primarily the result of income in the amount of $100,000 for compensatory damages received during the quarter ended September 30, 2002 offset by a reduction of emission credit income in the amount of $50,000 recorded during the period. During the three months ended September 30, 2001, a loss in the amount of $224,235 was recorded 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. The loss we recorded as a result of the sale of the U.S. Treasury bonds was partially offset by interest income of $70,196 received during the three months ended September 30, 2001. LEASE OPERATING EXPENSE. Lease operating expense decreased $770,305, or 17%, to $3,836,818 for the three months ended September 30, 2002 from $4,607,123 for the three months ended September 30, 2001. Lease operating expense was $1.68 per Mcfe for the three months ended September 30, 2002, an increase of 23% from $1.36 per Mcfe for the three months ended September 30, 2001. The decrease in lease operating expense is the result of the sale of certain of our Texas Gulf Coast and all of our Louisiana properties during the second quarter of 2002. Additionally, certain of our offshore properties including our High Island leases and Galveston Island 211 were shut-in during the first and second quarters of 2002 and continued to be shut-in during the three months ended September 30, 2002. During the three months ended September 30, 2002, lease operating expense, calculated on a unit of production basis increased by $0.32 per Mcfe. This increase is attributable to the 32% decline in oil and natural gas production volumes when compared to the three months ended September 30, 2001. WORKOVER EXPENSE. Workover expense decreased $181,823, or 21%, to $702,773 for the three months ended September 30, 2002 from $884,596 for the three months ended September 30, 2001. Workover expense was $0.31 per Mcfe for the three months ended September 30, 2002, an increase of 19% from $0.26 per Mcfe for the three months ended September 30, 2001. The decrease is primarily the result of the Company's decision to restrict the use of cash during the third quarter of 2002 in anticipation of the required interest payment due on its 12.5% senior secured debt on December 1, 2002. The reduction in the amount of workover expense incurred during the third quarter contributed to the general decline in production volumes. During the three months ended September 30, 2002, workover expense, calculated on a unit of production basis increased by $0.05 per Mcfe. This increase is attributable to the 32% decline in oil and natural gas production volumes when compared to the three months ended September 30, 2001. PRODUCTION TAXES. Production taxes decreased by $140,668 or 43% to $186,564 for the three months ended September 30, 2002 from $327,232 for the three months ended September 30, 2001. Production taxes were $0.08 per Mcfe for the three months ended September 30, 2002, a decrease of 20% from $0.10 per Mcfe for the three months ended September 30, 2001. Decreases in oil and natural 13 gas production and revenues during the three months ended September 30, 2002, resulted in a decrease in the amount of production taxes incurred during the period. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"). DD&A expense decreased by $1,373,179, or 44%, to $1,774,819 for the three months ended September 30, 2002 from $3,147,998 for the three months ended September 30, 2001. DD&A was $0.78 per Mcfe for the three months ended September 30, 2002, a decrease of 16% from $0.93 per Mcfe for the three months ended September 30, 2001. The decrease in DD&A is the result of the decrease in production volumes during the three months ended September 30, 2002 and the sale of certain oil and natural gas properties during May 2002. GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A increased $641,182, or 47%, to $1,991,933 for the three months ended September 30, 2002 from $1,350,751 for the three months ended September 30, 2001. G&A was $0.85 per Mcfe for the three months ended September 30, 2002, an increase of 113% from $0.40 per Mcfe for the three months ended September 30, 2001. The increase was primarily the result of an increase of bad debt expense in the amount of $205,580 and an increase in legal and consulting and professional fees of $818,904 during the three months ended September 30, 2002 when compared to the three months ended September 30, 2001. The increase in legal and consulting and professional fees was primarily the result of services provided in connection with the Waiver agreement and various legal matters discussed in legal proceedings (Item 1 of Part II). This increase was partially offset by a decrease in contract labor services of $141,569 and a decrease in insurance of $107,606 during the three months ended September 30, 2002 when compared to the three months ended September 30, 2001. INTEREST EXPENSE. Interest expense decreased $1,130,987 or 15%, to $6,398,235 for the three months ended September 30, 2002 from $7,529,222 for the three months ended September 30, 2001. The decrease in interest expense is the result of a decrease in the amount of outstanding debt on which interest is calculated. Our outstanding interest bearing debt balance was $118.0 million at September 30, 2002, a $12.0 million decrease from $130.0 million at September 30, 2001. Additionally, the decrease is attributable to a decrease of amortization of deferred loan costs during the three months ended September 30, 2002. REORGANIZATION COSTS. We 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. During the three months ended September 30, 2002, a reduction in the amount of $16,539 was recorded to previously expensed reorganization costs. This compares to reorganization costs in the amount of $1,427,480 during the three months ended September 30, 2001. These reorganization costs consist of the following: Professional fees and other - We retained certain legal and accounting professionals to assist with the bankruptcy proceedings and have incurred legal and accounting fees associated with these proceedings totaling $190 and $245,147 for the three months ended September 30, 2002 and 2001, respectively. Interest and amounts paid to creditors - Represents payments of amounts owed to creditors with pre-petition claims, including interest. During the three months ended September 30, 2002, we recorded a reduction of amounts owed to creditors in the amount of $16,729. This compares to $1,079,880 of pre-petition liabilities and interest paid to creditors during the three months ended September 30, 2001. Atasca transaction - As a condition of TDC's plan of reorganization, the Company agreed to transfer all of the oil and natural gas properties owned by Tribo Petroleum Corporation as of May 1, 2001 at their net book value of $1,097,547 and certain marketable securities with a value of $102,453, to an affiliate, Atasca Resources, Inc. In connection with this transaction, all balances owing to and from the Company by affiliates on May 1, 2001 were forgiven. These balances aggregated to a net receivable from the affiliates of $785,442. As a consequence of these transactions, the Company recorded a one-time reorganization expense of $1,985,442. The value of the marketable securities in the amount of $102,453 was transferred to the affiliate during the three months ended September 30, 2001. No amounts were recorded as a result of this transaction during the three months ended September 30, 2002. 14 PROVISION FOR INCOME TAXES. A $178,798 provision for income tax was made for the three months ended September 30, 2001, primarily as a result of alternative minimum tax requirements. No provision for federal income tax was required for the three months ended September 30, 2002. Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001 For the nine months ended September 30, 2002, consolidated net loss was $31,439,879 as compared to consolidated net income of $21,634,397 for the nine months ended September 30, 2001. OIL AND GAS REVENUES. Oil and natural gas revenues decreased $38,448,020, or 56%, to $29,616,995 for the nine months ended September 30, 2002, from $68,065,015 for the nine months ended September 30, 2001. 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 oil and natural gas during the period. During the second quarter of 2002, we sold certain of our Texas Gulf Coast and all of our Louisiana properties. The decline in production volumes is further attributable to a reduction in production from our Westbury Farm #1 well in the Constitution field due to 2 wells drilled on adjoining acreage, not owned or operated by us, directly offsetting our production. Further contributing to the production decline are two wells, which watered-out in our Ord Bend field in California. After watering out, these 2 wells were recompleted to two zones at reduced production rates. Additionally, production from our North Alvin, Spindletop, Sour Lake, South Liberty and Hastings fields experienced abnormal production declines partially due to a curtailed workover program during the second and third quarters of 2002. The following table summarizes the consolidated results of oil and natural gas production and related pricing for the nine months ended September 30, 2002 and 2001:

LOSS ON MARKETABLE SECURITIES. We recognized $556,735 in losses on marketable securities for the nine months ended September 30, 2001. 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. At September 30, 2002, we held no marketable securities for trading purposes. LOSS ON DERIVATIVE CONTRACTS. 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. Additionally, in June 2001, we entered into two years of derivative contracts on the basis differential attributable to approximately 80% of our projected proved developed producing natural gas production from our California properties. These derivative contracts do not qualify for hedge accounting under FAS 133, therefore, the Company marks these transactions to fair value. On March 31, 2002, we terminated certain of our derivative contracts and replaced them with contracts providing for price floors at the prices specified under the terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50 per barrel of crude oil. Proceeds from the sale of these contracts were approximately $2.3 million. The purchase price of the floor contracts of approximately $1.8 million has been financed by the Company's derivative contracts counterparty. The change in estimated fair value of these contracts during the nine months ended September 30, 2002 and 2001 resulted in a net non-cash loss on derivative contracts of $14,603,065 and net non-cash income on derivative contracts of $11,951,855, respectively. OTHER. Other income increased $1,738,820 or 212% to $2,560,896 for the nine months ended September 30, 2002 when compared to $822,076 for the nine months ended September 30, 2001. The increase was primarily the result of the sale of emission reduction credits from our Hastings Field in the 15 amount of $2,226,450 during the nine months ended September 30, 2002 when compared to income from the sale of emission credits in the amount of $681,690 during the nine months ended September 30, 2001. Additionally income in the amount of $100,000 for compensatory damages was received during the nine months ended September 30, 2002 LEASE OPERATING EXPENSE. Lease operating expense decreased $1,294,125, or 9%, to $13,793,427 for the nine months ended September 30, 2002 from $15,087,552 for the nine months ended September 30, 2001. Lease operating expense was $1.68 per Mcfe for the nine months ended September 30, 2002, an increase of 35% from $1.24 per Mcfe for the nine months ended September 30, 2001. The decrease in lease operating expense is primarily the result of the sale of our Ship Shoal 58 field in June 2001 and the plugging and abandonment of the West Cameron 531, South Marsh Island 232 and Brazos 476 wells and platforms, where lease operations have ceased, in the fourth quarter of 2001. Additionally, certain of our offshore properties including our High Island leases and Galveston Island 211 were shut-in during the first and second quarter of 2002. The decrease is also the result of the sale of certain of our Texas Gulf Coast and all of our Louisiana properties during the second quarter of 2002. During the nine months ended September 30, 2002, lease operating expense, calculated on a unit of production basis increased by $0.44 per mcfe. This increase is attributable to the 32% decline in oil and natural gas production volumes when compared to the nine months ended June 30, 2001. WORKOVER EXPENSE. Workover expense decreased $1,065,350, or 25%, to $3,159,375 for the nine months ended September 30, 2002 from $4,224,725 for the nine months ended September 30, 2001. Workover expense was $0.38 per Mcfe for the nine months ended September 30, 2002, an increase of 9% from $0.35 per Mcfe for the nine months ended September 30, 2001. The decrease is primarily the result of the Company's decision to restrict the use of cash during the second and third quarters of 2002 in anticipation of the required interest payment due on its 12.5% Senior Secured Debt on December 1, 2002. The reduction in the amount of workover expense incurred during the second and third quarters of 2002 contributed to the general decline in production volumes. During the nine months ended September 30, 2002, workover expense, calculated on a unit of production basis increased by $0.03 per mcfe. This increase is attributable to the 32% decline in oil and natural gas production volumes when compared to the nine months ended September 30, 2001. PRODUCTION TAXES. Production taxes decreased by $1,004,389 or 60% to $664,419 for the nine months ended September 30, 2002 from $1,668,808 for the nine months ended September 30, 2001. Production taxes were $0.08 per Mcfe for the nine months ended September 30, 2002, a decrease of 43% from $0.14 per Mcfe for the nine months ended September 30, 2001. Decreases in oil and natural gas production and revenues during the nine months ended September 30, 2002 resulted in a decrease in the amount of production taxes incurred during the period. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"). DD&A expense decreased by $4,070,539, or 39%, to $6,339,501 for the nine months ended September 30, 2002 from $10,410,040 for the nine months ended September 30, 2001. DD&A was $0.77 per Mcfe for the nine months ended September 30, 2002, a decrease of 10% from $0.86 per Mcfe for the nine months ended September 30, 2001. The decrease in DD&A is the result of the decrease in production volumes during the nine months ended September 30, 2002 and the sale of certain oil and natural gas properties during May 2002. GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A increased $92,635, or 2%, to $4,592,620 for the nine months ended September 30, 2002 from $4,499,985 for the nine months ended September 30, 2001. G&A was $0.55 per Mcfe for the nine months ended September 30, 2001, an increase of 50% from $0.37 per Mcfe for the nine months ended September 30, 2001. The increase was primarily the result of an increase in professional and consulting service fees of $993,595 and an increase in director fees and related expenses in the amount of $225,000. This increase was partially offset by decreases in salary, bonus and related overhead expense of $636,893, contract labor of $242,983 and rent and relocation expense of $111,223 during the nine months ended September 30, 2002. INTEREST EXPENSE. Interest expense increased $6,537,269 or 47%, to $20,342,741 for the nine months ended September 30, 2002 from $13,805,472 for the nine months ended September 30, 2001. The increase is primarily the result of non-cash amortization of bond discount and deferred loan costs to interest expense of $4,671,318 and $3,895,886 respectively during the nine months ended September 30, 2002 compared to $2,119,964 and $1,735,908 respectively during the nine months ended September 30, 2001. 16 REORGANIZATION COSTS. We 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 $122,622 for the nine months ended September 30, 2002, a 99% decrease from $8,738,588 for the nine months ended September 30, 2001. These reorganization costs consist of the following: Professional fees and other - We retained certain legal and accounting professionals to assist with the bankruptcy proceedings and have incurred legal and accounting fees associated with these proceedings totaling $93,901 and $5,524,049 for the nine months ended September 30, 2002 and 2001, respectively. Interest and amounts paid to creditors - Represents payments of amounts owed to creditors with pre-petition claims, including interest. During the nine months ended September 30, 2002 and 2001, $28,721 and $1,873,078, respectively of pre-petition liabilities and interest were paid to creditors. Retention costs - In an effort to maintain certain key employees through the bankruptcy period, the Company incurred retention bonuses of $301,740 during the nine months ended September 30, 2001. No retention bonuses were incurred during the nine months ended September 30, 2002. Interest - Interest income earned during bankruptcy has been recorded as an offset to reorganization costs as prescribed by SOP 90-7. During the nine months ended September 30, 2002 and 2001, none and $945,721 were offset to reorganization costs, respectively. Atasca transaction - As a condition of TDC's plan of reorganization, the Company agreed to transfer all of the oil and natural gas properties owned by Tribo Petroleum Corporation, as of May 1, 2001 at their net book values of $1,097,547 and marketable securities with a value of $102,453, to an affiliate, Atasca Resources, Inc. In connection with this transaction, all balances owing to and from the Company by affiliates on May 1, 2001 were forgiven. These balances aggregated to a net receivable from the affiliates of $785,442. As a consequence of these transactions, the Company recorded a one-time reorganization expense of $1,985,442 during the nine months ended September 30, 2001. No amounts were recorded as a result of this transaction during the nine months ended September 30, 2002. 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, 2002. LIQUIDITY AND CAPITAL RESOURCES In March 1998, we acquired certain onshore Texas oil and natural gas properties from Apache Corporation. Prior to the acquisition, we had approximately $35.0 million in debt outstanding. We incurred approximately $63.0 million of additional debt in connection with the Apache acquisition. In August 1998, before we were able to refinance our debt, 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 payment 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 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 obligations. In July 1999, the 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 had increased as a result of capitalized interest and expenses to approximately $105.0 million. In February 2000, the bank declared the loan in default, demanded payment of all principle and interest and posted the shares of Tribo Petroleum Corporation, at that time our parent corporation and a guarantor of the loan, for foreclosure. As a consequence of the bank's actions, 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 September 30, 2002 and December 31, 2001 balance sheets as "Accounts payable subject to renegotiation." After we entered into bankruptcy in March 2000, commodity prices began to recover, with natural gas prices eventually reaching historically high levels, particularly in California. During the nine month 17 period ended September 30, 2002, the average prices we received for natural gas and oil were $3.16 per Mcf and $24.05 per Bbl. We filed our amended plan of reorganization in the bankruptcy court on May 9, 2001, which provided for our exit from bankruptcy upon the completion of a $130.0 million unit offering of senior secured notes and class A common stock. Our plan was confirmed by a court order entered as of May 23, 2001, subject to the completion of the offering. On June 18, 2001, the offering closed and we exited 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 in full, including interest. During the last two quarters of 2001 and continuing into 2002, commodity prices again declined. These price declines, coupled with production declines beginning in the third quarter of 2001, predominately attributable to unanticipated production declines in two wells, adversely impacted our cash flows during the latter part of 2001 and continuing into 2002. Commodity price hedges that we had entered into in connection with the closing of the offering only partially offset the adverse impact on our cash flows from the decline in commodity prices. At September 30, 2002, we had approximately $118.1 million of 12.5% senior secured notes outstanding. The notes mature on June 1, 2006 and require amortization payments of the greater of $20.0 million and 15.3% as of June 1, 2002 and 2003 and an amortization payment of the greater of $15.0 million and 11.5% as of June 1, 2004. A final amortization payment of $75.0 million is due June 1, 2006. Interest is payable semi-annually on June 1 and December 1 of each year. On June 1, 2002, a principal payment in the amount of $20.0 million was made on the notes reducing the outstanding balance on the notes to $110.0 million. Interest in the amount of $8.1 million was deferred until July 1, 2002. On July 3, 2002, the Company entered into a Waiver, Agreement and Supplement (the "Waiver") to the Indenture whereby the interest was added to the outstanding balance of the notes, bringing the total amount of outstanding debt to $118.1 million. In addition, the Company issued to the Noteholders 76,667 shares of Class A common stock, par value $0.01 per share. The Waiver contained additional covenants, one of which required the Company to obtain clear title to an oil and gas property subject to lien by no later than August 2, 2002. Additionally, the Waiver contained additional covenants, which required the Company to maintain minimum daily production levels of 28.5 Mmcfe of average daily production and report $4.0 million of EBITDA, as adjusted for the non-cash effects of oil and gas hedging contracts, as of the end of the third quarter of 2002. The Company has been unable to achieve the required daily production and did not generate $4.0 million of EBITDA during the third quarter of 2002. As the Company was unable to obtain clear title to an oil and gas property and to maintain the required production levels, or to report EBITDA of $4.0 million, an event of default occurred to the Waiver and the original Indenture whereby the senior secured notes became due on demand. Accordingly, the senior secured notes and related deferred loan costs have been classified as current in the accompanying consolidated balance sheet at September 30, 2002. At September 30, 2002, our cash balance was $2.9 million, a $1.8 million decrease from our cash balance at December 31, 2001. Net cash provided by operating activities after reorganization items increased $31.9 million to $14.7 million for the nine months ended September 30, 2002 compared to net cash used by operating activities after reorganization items of $17.2 million for the nine months ended September 30, 2001. The increase is the result of a $48.8 million decrease in net cash used in operating activities for accounts payable subject to renegotiation and accounts payable and accrued liabilities. Accounts payable subject to renegotiation and accounts payable and accrued liabilities were $42.6 million at September 30, 2001 compared to $6.3 million at September 30, 2002. The Company reported a net loss of $31.4 million for the nine months ended September 30, 2002 when compared to net income of $21.6 million for the nine months ended September 30, 2001. During the nine months ended September 30, 2002, we recorded a loss on the mark-to-market value of our derivative contracts of $14.6 million. Additionally, on June 18, 2001, we deposited $13.5 million into a restricted cash account as required by our plan of reorganization to satisfy the payment in full of all remaining disputed pre-petition claims. As of September 30, 2002, $11.9 million of cash deposited into this restricted account was disbursed to us or to claimants of pre-petition claims. At September 30, 2002, the balance in the restricted account was $1.6 million. Net cash provided by investing activities was $4.5 million during the nine months ended September 30, 2002 compared to net cash used in investing activities of $10.1 million during the nine months ended September 30, 2001. The increase in net cash provided by investing activities is primarily 18 the result of the sale of certain oil and natural gas properties and net realized proceeds in the amount of $6.0 million. Additionally, the company recognized $2.3 million of proceeds from the sale of derivative contracts and $1.6 million of cash settlements on derivative contracts during the nine months ended September 30, 2002. Net cash used in financing activities was $21.0 million for the nine months ended September 30, 2002 when compared to net cash provided by financing activities of $5.9 million during the nine months ended September 30, 2001. The increase in net cash used in financing activities is the result of our payment of $20.0 million of principal due on June 1, 2002. CAPITAL REQUIREMENTS Historically, our principal sources of capital have been cash flow from operations, short-term reserve-based bank loans, proceeds from asset sales and the offering of our 12.5% senior secured notes. Our principal uses for capital have been the acquisition and development of oil and natural gas properties. On June 1, 2002, the Company was required to make a $28,125,000 payment of principle and interest on its senior secured notes, and an additional scheduled interest payment of approximately $7,400,000 is due on December 1, 2002. In addition, the Company has a scheduled principal and interest payment of approximately $28,700,000 due June 1, 2003. The Company made its scheduled principal payment of $20,000,000 due on June 1, 2002, but refinanced its scheduled interest payment of $8,125,000 into additional promissory notes under the terms of a Waiver, Agreement and Supplemental Indenture (the "Waiver"). The Waiver contained additional covenants, one of which required the Company to obtain clear title to an oil and gas property subject to lien by no later than August 2, 2002. Additionally, the Waiver contained covenants requiring the Company to maintain average daily production levels of 28.5 Mmcfe per day and to generate $4.0 million of EBITDA, as adjusted for the non-cash effects of oil and gas hedging contracts as of the end of the third quarter of 2002. As the Company was unable to obtain clear title by that date, did not maintain the required production levels, and did not report $4.0 million of EBITDA, an event of default occurred to the Waiver and the original Indenture whereby the senior secured notes became due on demand. Accordingly, the senior secured notes and related deferred loan costs have been classified as current in the accompanying consolidated balance sheet at September 30, 2002. While the Company continues to delay certain of its workover and capital improvement projects in order to maximize available cash to meet its debt obligations, the foregoing event of default could have a material adverse impact on the Company's ability to meet its debt and working capital requirements. Should the noteholders demand payment on the notes, the Company will not have the ability to generate sufficient resources to satisfy this obligation. These conditions raise substantial doubt about the Company's ability to continue as a going concern. The Company is currently marketing certain of its oil and gas properties in order to meet these scheduled debt obligations and working capital requirements. Several offers to purchase certain of the Company's oil and gas properties have been received to date which, if accepted, and combined with the Company's cash balances at November 12, 2002 of approximately $4.6 million, would provide the Company with sufficient capital to meet its upcoming December 1, 2002 scheduled debt obligation. To the extent the cash generated from oil and gas property sales and cash flows from continuing operations are insufficient to meet our scheduled debt obligations and our projected working capital needs, we will have to raise additional capital. No assurance can be given that additional funding will be available, or if available, will be on terms acceptable to us. Uncertainty regarding the amount and timing of any proceeds from our plans to raise additional capital raises substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might be necessary should we be unable to continue as a going concern. 19 QUALITATIVE DISCLOSURES ABOUT MARKET RISK Revenues from our operations are highly dependent on the price of oil and natural gas. The markets for oil and natural gas are volatile and prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond our control, including the level of consumer demand, weather conditions, domestic and foreign governmental regulations, market uncertainty, the price and availability of alternative fuels, political conditions in the Middle East, foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas prices with any certainty. To reduce our exposure to oil and natural gas price risks, from time to time we may enter into commodity price derivative contracts to hedge commodity price risks. In connection with the issuance of the senior secured notes, we agreed to maintain, on a monthly basis, a rolling two-year hedge program until the maturity of the notes, subject to certain conditions. In March 2002, we terminated certain of our price swap derivatives contracts and replaced them with contracts providing for price floors at the prices specified under the terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50 per barrel of crude oil. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 2001, FASB issued Statement of Financial Accounting Standards ("SFAS") No. 141, Business Combinations (SFAS No. 141), and No. 142, Goodwill and Other Intangible Assets (SFAS No. 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 No. 141 required the Company to recognize acquired intangible assets apart from goodwill if the acquired intangible assets meet certain criteria. SFAS No. 141 applies to all business combinations initiated after June 30, 2001, and for purchase business combinations completed on or after July 1, 2001. SFAS No. 141 also requires upon adoption of SFAS No. 142 that the Company reclassify the carrying amounts of intangible assets and goodwill based on the criteria in SFAS No. 141. SFAS No. 142 requires that companies no longer amortize goodwill, but instead test goodwill for impairment at least annually. In addition, SFAS No. 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 No. 142. SFAS No. 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 No. 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. The adoption of SFAS No. 141 and SFAS No. 142 did not materially impact the Company's financial position and results of operations. In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). SFAS No. 143 amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is applicable to all companies. SFAS No. 143, which is effective for fiscal years beginning after June 15, 2002, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset, except for certain obligations of lessees. As used in SFAS No. 143, a legal obligation is an obligation that a party is required to settle as a result of an existing or enacted law, statue, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. While the Company is not yet required to adopt SFAS No. 143, it is not believed the adoption will have a material effect on its financial condition or results of operations. In August 2001, FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets ("SFAS No. 144"). SFAS No. 144, which supercedes SFAS No. 121, Accounting for the Impairment of Long-lived Assets and Long-lived Assets to be Disposed Of and amends Accounting Research Bulletin No. 51, Consolidated Financial Statements, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001, and interim financials within those fiscal years, with early adoption 20 encouraged. The provisions of SFAS No. 144 are generally to be applied prospectively. The Company does not believe the adoption of SFAS No. 144 will have a material effect on its financial condition or results of operations. In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. The statement also contains other nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. Adoption of this standard will not have any immediate effect on our consolidated financial statements. The Company will apply this guidance prospectively. On June 20, 2002, FASB's Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, and No. 00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10. The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (including those to be physically settled) must be retroactively presented on a net basis in earnings. In addition, companies must disclose volumes of physically-settled energy trading contracts. The Company is evaluating the impact of this new consensus on the presentation of its consolidated income statement but believes it will not have a material impact on total revenues and expenses. The consensus will have no impact on net income. In June 2002, FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3. The Company will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost is recognized at the date of a company's commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amount recognized. Adoption of this standard will not have any immediate effect on our consolidated financial statements. The Company will apply this guidance prospectively. CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES The Securities and Exchange Commission recently issued disclosure guidance for "critical accounting policies." The SEC defines critical accounting policies as those that require application of management's most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain and may change in subsequent periods. Our significant accounting policies are described in Note 3 in the Notes to Consolidated Financial Statements. Not all of these significant accounting policies require management to make difficult, subjective or complex judgments or estimates. However, the following policies could be deemed to be critical within the SEC definition. Oil and Natural Gas Interests Full Cost Method - The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar 21 activities. The sum of net capitalized costs and estimated future development and abandonment costs of oil and gas properties and mineral investments are amortized using the unit-of-production method. Proved Reserves - Proved oil and gas reserves are the estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered "proved" if they can be produced economically as demonstrated by either actual production or conclusive formation tests. Reserves which can be produced economically through application of improved recovery techniques 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. "Proved developed" oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company emphasizes that the volumes of reserves are estimates, which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. These estimates, made by the Company's engineers, are reviewed and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in assumptions based on, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to uneconomic conditions. Ceiling Test - Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves. This ceiling is compared to the net book value of the oil and gas properties reduced by any related deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write down is required. A ceiling test impairment can give us a significant loss for a particular period; however, future DD&A expense would also be reduced. Estimates of future net cash flows from proved reserves of gas, oil and condensate are made in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Derivative Financial Instruments As a condition of the bond indenture agreement, the Company entered into commodity price swap derivative contracts and price floor contracts to manage price risk with regard to 80% of its natural gas and crude oil production. Statement of Accounting Financial Standards No. 133 (SFAS No. 133), "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB No. 133", and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" was effective for the Company as of January 1, 2001. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is designated as a hedge and qualifies for hedge accounting, changes in the fair value of derivatives will either be offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be immediately recognized in earnings. Use of Estimates The financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, appropriate in the circumstances. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. 22 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Derivative Instruments Used In Our Production We have entered into a combination of natural gas and crude oil price swap and price floor derivative agreements with counterparties to manage commodities price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under the price swap 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. Under the price floor agreements, we have purchased the right to obtain a minimum fixed price on a notional quantity of natural gas and crude oil. We entered into no commodities price swaps or price floor agreements covering production in the first six months of 2001. On March 31, 2002, we terminated certain of our price swap derivative contracts and replaced them with price floors at prices specified under the terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50 per barrel of crude oil. Proceeds from the sale of the price swap contracts were approximately $ 2.3 million. The purchase price of the price floor contracts of approximately $1.8 million has been financed by the Company's derivative contracts counterparty. The following table reflects the production volumes and the weighted average prices under our commodities price swaps, which remain in place at September 30, 2002:

The prices presented above are averages for each of the quarters indicated. The following table sets forth the production volumes, which are protected with price floors of $2.75 per MMBtu of natural gas and $18.50 per barrel of crude oil as of September 30, 2002:

------------------------------------------------------------------- 23 ITEM 4. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures The term "disclosure controls and procedures" is defined in Rule 13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. Our Chief Executive Officer and our Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures as of a date within 90 days before the filing of this quarterly report, and have concluded that as of that date, our disclosure controls and procedures were effective at ensuring that required information will be disclosed on a timely basis in our reports filed under the Exchange Act. Changes in Internal Controls We maintain a system of internal controls that is designed to provide reasonable assurance that our books and records accurately reflect our transactions and that our established policies and procedures are followed. There were no significant changes to our internal controls or in other factors that could significantly affect our internal controls subsequent to the date of their evaluation by our Chief Executive Officer and Chief Financial Officer, including any corrective actions with regard to significant deficiencies and material weaknesses. 24 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 material adverse effect on our financial condition, cash flow or results of operations. Disputes with Richard Bowman and Affiliates On August 9, 2002, shareholder and former Chief Executive Officer Richard Bowman ("Bowman") filed suit against the Company, certain members of its board of directors, and Jefferies & Company, Inc. ("Jefferies") in the District Court of Harris County, Texas 55th Judicial District (the "Court"). The suit alleges that the Company, certain members of the Company's board of directors and Jefferies violated fiduciary duties to the Company's shareholders by entering into the Waiver (see Note 2 to the consolidated financial statements) to the Indenture. The suit further alleges that the Company's board members in concert with Jefferies entered into the Waiver with the intended effect of diluting Bowman below a 50% ownership in the Company and effectively transferred significant properties to the bondholders as a security interest. Bowman's original petition sought to temporarily restrain the Company's ability to hold an Annual Meeting of its Shareholders, scheduled for August 9, 2002 whereby its Shareholders were solicited to vote on Director Nominees and the issuance of additional common shares (see Item 4 - Submission of Matters to a Vote of Security Shareholders) and seeks to rescind the Waiver declaring it void and excusing all parties from all obligations under the agreement. The Company intends to vigorously defend against Bowman's claims of breach of fudiciary responsibility and the rescinsion of the Waiver. The Company has also filed claims in the lawsuit, including counterclaims against Bowman and third-party claims against Atasca Resources, Inc. ("Atasca"), Tribo Production Company ("Tribo Production"), and Lovett Properties, Ltd. ("Lovett"), three entities owned and controlled by Bowman. The claims against Bowman allege primarily breaches by Bowman of fiduciary duties owed to the Company. The claims against Atasca relate to disputes concerning Bowman's actions with respect to a certain gas well known as the Champion 1-H well in Grimes County. The claims against Tribo Production and Lovett relate to the lease of the Company's corporate office, which is leased from these Bowman affiliates. The Company alleges that Bowman's actions with respect to the lease and the Champion well were violations of his fiduciary duties, and alleges that Bowman has improperly used and diverted corporate funds for his own benefit and for the benefit of his affiliates. The Company seeks relief from Bowman's request to rescind the Waiver, actual and punitive damages, equitable reformation of the lease with Bowman's affiliates along with all costs and attorney fees. In late August, the Company was served in another lawsuit filed by Bowman affiliate Atasca in the District Court of Grimes County, Texas 278th Judicial District (the "Court") for declaratory judgment. That suit seeks judicial intervention in determining the ownership of interests in the Champion 1-H well. The Company has requested transfer of this lawsuit so that it can be combined into the pending action in Harris County. 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. Chieftain International On March 31, 1999, Chieftain International (U.S.), Inc. ("Chieftain") filed suit against us in the United States District Court for the Eastern District of Louisiana (the "District Court") alleging that we 25 owed certain joint interest expenses in the approximate amount of $3.0 million, together with accrued interest, attorney's fees, and costs, in connection with Chieftain's operation of two offshore mineral leases. Chieftain took no action with regard to its lawsuit during our bankruptcy, as the litigation in the District Court was stayed pursuant to 11 U.S.C. Section 362. Since emerging from bankruptcy, Chieftain successfully re-opened the litigation in the District Court and has claimed that we now owe approximately $5.1 million, together with accrued interest, attorneys' fees, and costs. However, pursuant to our confirmed plan of reorganization, approximately $5.5 million was segregated in an interest bearing account pending the trial and/or non-judicial resolution of our dispute with Chieftain. On April 17, 2002, we entered into an agreement with Chieftain to stay the litigation for a six-month period in which we will conduct an audit of Chieftain's books and records relating to the litigation. However, $5 million of the funds segregated pending the trial and/or non-judicial resolution of our dispute with Chieftain was transferred to Chieftain prior to the commencement of our audit. We have and will continue to maintain $500,000 in the segregated account pending a resolution of the audit, but all additional funds in the segregated account due to interest accumulation will be distributed to us. If Chieftain's lawsuit is not successfully resolved in the audit process, the lawsuit will be reopened in the District Court and any of Chieftain's remaining claims will be litigated, along with our counterclaims against Chieftain for conducting operations in an imprudent manner. 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. ITEM 2. CHANGES IN SECURITIES On July 3, 2002, the Company issued 76,667 shares of its class A common stock, par value $0.01 per share to the holders of its 12.5% senior secured notes. The issuance of the additional shares of class A common stock resulted in a change of control with respect to beneficial ownership of our common stock. An aggregate of 510,000 shares of our common stock were issued and outstanding at July 3, 2002 consisting of 445,000 shares of class A common stock and 65,000 shares of class B common stock. Of these shares, Richard Bowman, our former President and Chief Executive Officer, owns 238,333 shares of class A common stock and no shares of class B common stock, or 47% of our common stock. The holders of the senior secured notes hold an aggregate of 206,667 shares of class A common stock and Jefferies & Company, Inc. holds an aggregate of 65,000 shares of class B common stock, or 53% of our common stock. Prior to the July 3, 2002 issuance of an additional 76,667 shares of class A common stock, Richard Bowman owned 55% of the issued and outstanding shares of common stock. As a result of the aforementioned changes in securities and the resulting change in control, federal tax laws may restrict the Company's ability to utilize its net operating loss carryforward's. ITEM 3. DEFAULTS UPON SENIOR SECURITIES The Company issued 130,000 units including $130,000,000 in aggregate principal amount of its 12.5% Series A Senior Secured Notes due 2006 on June 18, 2001, and it subsequently exchanged the units for an equal principal amount of notes in an exchange registered with the Securities and Exchange Commission, as defined in the Indenture. On June 3, 2002, the Company timely made a $20,000,000 aggregate principal payment due under the terms of the notes but did not make a $8,125,000 aggregate accrued cash interest payment due on the notes, which was also due on June 3, 2002. The Company had advised the noteholders that it had insufficient funds to make the June 3, 2002 interest payment, which would result in an event of default under the Indenture on July 3, 2002. As a result, the Company 26 requested that the noteholders agree to permit the Company to make the June 1, 2003 interest payment due on the notes, plus the interest due on such interest, through the issuance of additional promissory notes (the "New Notes") with terms identical to the terms of the Series A Notes. The New Notes will not immediately be registered under the Securities Act of 1933 and will not be freely tradable until such time as a registration statement with respect to the exchange of the New Notes has been declared effective by the Securities and Exchange Commission. In August, 2002, the Company notified the holders of its senior secured notes that it did not obtain clear title to the Champion #1-H well in the 30 day period required pursuant to the Waiver. The failure to obtain clear title to the Champion #1-H well constitutes an event of default pursuant to the terms of the Waiver and the Indenture. Additionally, in September 2002, the Company notified the holders of its senior secured notes that EBITDA, as adjusted to exclude the non-cash effects of oil and gas hedging contract, as of the end of the third quarter of 2002 was less than $4.0 million and average daily production had fallen below 28.5 Mmcfe per day. If any event of default occurs and not cured, the noteholders may by notice to the Company, declare all the notes then outstanding to be due and payable upon demand. Although no such declaration or demand has been made upon the Company, the senior secured notes have been classified as current in the accompanying consolidated balance sheet at September 30, 2002. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The Company held an annual meeting of its shareholders on September 10, 2002. At the meeting, the shareholders voted on the election of five directors and a proposal to approve an amendment of the Company's Articles of Incorporation to increase the number of authorized shares of common stock from 510,000 to 2,510,000. An amendment to the Articles of Incorporation requires the affirmative vote of two-thirds of the outstanding class A common stock and class B common stock voting together as a single class and the affirmative vote of two-thirds of the outstanding class B common stock voting as a separate class. The Company received proxies covering 510,000 shares of its outstanding common stock, representing 100% of such shares. There were no abstentions or non-votes on any proposals voted on at the meeting. Directors are elected by a plurality vote of the class A common stock and the class B common stock present at the meeting, voting together as a single class. Five directors, constituting the entire board of directors, were elected at the meeting to serve until the next annual meeting of shareholders. The voting was as follows:

Messrs. Dutt, Riegle and Richard have served as directors since June 2001. Mr. Ducote joined the board in July 2002 following the resignation of Michel T. Halbouty. On June 13, 2002, our Chief Executive Officer and President, Richard Bowman, resigned his positions and was replaced by James M. Trimble, effective July 19, 2002. Mr. Bowman, who is no longer a board member, retains approximately 47% of the Company's outstanding common stock. The vote on the amendment of the Company's Articles of Incorporation to increase the number of authorized share of common stock was not approved. Of the 510,000 shares voting on this matter, 271,667 shares, or approximately 53% voted for approval and 238,333 shares, or approximately 47% for against. No votes were withheld. 27 ITEM 5. FORWARD LOOKING STATEMENTS Certain information included in this report, other materials filed or to be filed by the Company with the Securities and Exchange Commission, as well as information included in oral statements or written statements made or to be made by the Company contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements that are not historical facts contained in this report are forward-looking statements that involve risks and uncertainties that could cause actual results to differ from projected results. Such statements may include activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration opportunities, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and natural gas, business strategies, property acquisition and sales, and anticipated liquidity. Factors that could cause actual results to differ materially ("Cautionary Disclosures") are described, among other places, in the Company's Form 10-K. Without limiting the Cautionary Disclosures so described, Cautionary Disclosures include, among others: general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and gas business, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, environmental risks, the results of financing efforts and regulatory developments. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Disclosures. The Company disclaims any obligation to update or revise any forward-looking statement to reflect events or circumstances occurring hereafter or to reflect the occurrence of anticipated or unanticipated events. 28 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(1) Incorporation by reference to the comparably numbered Exhibit to the Registration Statement on Form S-4 filed by the Issuer November 2, 2001. 29 SIGNATURES 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 November 19, 2002 By: /s/ James M. Trimble ----------------- ----------------------------------------- James M. Trimble, Chief Executive Officer and President By: /s/ Suzanne R. Ambrose ----------------------------------------- Suzanne R. Ambrose, Vice President and Chief Financial Officer 30 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350) I, James M. Trimble, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Tri-Union Development Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions and about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls, which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 19, 2002 --------------------------------------- /s/ James M. Trimble ------------------------------------------------ James M. Trimble President and Chief Executive Officer 31 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350) I, Suzanne R. Ambrose, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Tri-Union Development Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions and about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls, which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 19, 2002 ----------------------------------------------- /s/ Suzanne R. Ambrose ------------------------------------------------ Suzanne R. Ambrose Vice President and Chief Financial Officer 32 EXHIBIT INDEX

(1) Incorporation by reference to the comparably numbered Exhibit to the Registration Statement on Form S-4 filed by the Issuer November 2, 2001.

TRI UNION DEVELOPMENT CORP 10-Q