TRI UNION DEVELOPMENT CORP - 10-Q Quarterly Report

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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 MARCH 31, 2003

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)

801 Travis, Suite 2102 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
----- -----

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act): yes no x
----- -----

As of May 15, 2003 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
INDEX TO FINANCIAL INFORMATION

Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets at December 31, 2002 (audited) and
March 31, 2003 (unaudited)...................................................... 3

Consolidated Statements of Loss for the Three Months Ended
March 31, 2002 and 2003 (unaudited)............................................. 4

Consolidated Statements of Cash Flows for the Three Months Ended
March 31, 2002 and 2003 (unaudited)............................................. 5

Notes to Consolidated Financial Statements (unaudited).......................... 6

Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................................... 11

Item 3. Quantitative and Qualitative Disclosure about Market Risk....................... 20

Item 4. Controls and Procedures......................................................... 21

Part II. Other Information

Item 1. Legal Proceedings............................................................... 22

Item 2. Changes in Securities........................................................... 23

Item 3. Defaults Upon Senior Securities................................................. 23

Item 4. Submission of Matters to a Vote of Security Holders............................. 24

Item 5. Forward Looking Statements...................................................... 25

Item 6. Exhibits and Reports on Form 8-K................................................ 26

Signatures ......................................................................................... 27

Section 302 Officers' Certification................................................................. 28

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TRI-UNION DEVELOPMENT CORPORATION
CONSOLIDATED BALANCE SHEETS

December 31, March 31,
2002 2003
(audited) (unaudited)
-------------- -------------

ASSETS
Current assets:
Cash and cash equivalents ....................................... $ 1,541,680 $ 2,884,599
Restricted cash ................................................. 1,583,200 1,586,413
Accounts receivable, net of allowance for doubtful accounts
of $1,707,465 ................................................. 6,927,014 6,538,481
Prepaid expenses and other ...................................... 1,936,861 2,249,290
Deferred loan costs, net ........................................ 12,785,411 11,584,541
------------- -------------
Total current assets .......................................... 24,774,166 24,843,324
------------- -------------
Oil and natural gas properties - full cost method, net ............. 73,829,045 85,137,541

Other assets:
Restricted cash and bonds ....................................... 5,340,087 5,360,347
Furniture, fixtures and equipment, net .......................... 990,514 739,357
Other assets .................................................... 2,578,895 1,539,573
------------- -------------
Total other assets ............................................ 8,909,496 7,639,277
------------- -------------
$ 107,512,707 $ 117,620,142
============= =============

LIABILITIES AND CAPITAL DEFICIT
Current liabilities:
Accounts payable and accrued liabilities ........................ $ 20,676,260 $ 17,528,813
Accounts payable subject to renegotiation ....................... 1,408,185 1,371,145
Accrued interest ................................................ 1,254,067 4,894,906
Payable to affiliate ............................................ -- 208,142
Notes payable ................................................... 790,766 318,576
Derivative contracts ............................................ 3,379,875 8,224,705
Asset retirement obligation (Note 6) ............................ -- 11,927,799
Other liabilities ............................................... 1,797,942 1,797,942
Senior secured notes - in default (Note 2) ...................... 103,397,107 104,799,491
------------- -------------
Total current liabilities ..................................... 132,704,202 151,071,519
------------- -------------
Derivative contracts ............................................... 1,912,722 3,350,410
Asset retirement obligation (Note 6) ............................... -- 13,097,180
------------- -------------
Total liabilities ............................................... 134,616,924 167,519,109
------------- -------------

Capital deficit:
Class A common stock, $0.01 par value, 445,000 shares authorized,
issued and outstanding ........................................ 4,450 4,450
Class B common stock, $0.01 par value, 65,000 shares authorized,
issued and outstanding ........................................ 650 650
Additional paid in capital ...................................... 26,065,635 26,065,635
Deficit ......................................................... (53,174,952) (75,969,702)
------------- -------------
Total capital deficit ......................................... (27,104,217) (49,898,967)
------------- -------------
$ 107,512,707 $ 117,620,142
============= =============

The accompanying notes are an integral part of these consolidated
financial statements.

3

TRI-UNION DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF LOSS
(UNAUDITED)

Three Months Ended
March 31,
--------------------------------
2002 2003
------------- --------------

Revenues and other:
Oil and natural gas revenues ........... $ 11,310,653 $ 9,993,436
Loss on derivative contracts ........... (11,947,692) (5,892,062)
Other .................................. 969,385 41,898
------------ ------------
Total revenues and other ............. 332,346 4,143,272

Expenses:
Lease operating expense ................ 4,752,574 3,732,613
Workover expense ....................... 1,951,896 1,061,355
Production taxes ....................... 229,522 166,360
Depreciation, depletion and amortization 2,495,264 2,523,749
General and administrative expense ..... 1,199,533 1,782,347
Interest expense ....................... 7,153,929 6,272,664
------------ ------------
Total expenses ....................... 17,782,718 15,539,088
------------ ------------
Loss before reorganization costs .......... (17,450,372) (11,395,816)
Reorganization costs (benefit) ............ 90,863 (61,175)
------------ ------------
Loss before cumulative effect of
change in accounting principle ....... (17,541,235) (11,334,641)
Cumulative effect of change in accounting
principle (Note 6) ..................... -- 11,460,109
------------ ------------
Net loss ............................. $(17,541,235) $(22,794,750)
============ ============

Net loss per share before cumulative
effect of change in accounting
principle - basic and diluted ........ $ (40.48) $ (22.22)
============ ============

Net loss per share after cumulative
effect of change in accounting
principle - basic and diluted ........ $ (40.48) $ (44.70)
============ ============

Weighted average share outstanding - basic
and diluted ............................ 433,333 510,000
============ ============

The accompanying notes are an integral part of these consolidated
financial statements.

4

TRI-UNION DEVELOPMENT CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(UNAUDITED)

Three Months Ended March 31,
---------------------------------
2002 2003
-------------- --------------

Cash flows from operating activities:
Net loss .................................................... $ (17,541,235) $ (22,794,750)
Adjustments to reconcile net loss to net cash provided
by (used in) operating activities:
Cumulative effect of change in accounting principle ..... -- 11,460,109
Depreciation, depletion and amortization ................ 2,495,264 2,523,749
Amortization of bond discount ........................... 1,657,367 1,402,384
Amortization of debt issuance costs ..................... 1,356,805 1,200,870
Accretion of bond interest .............................. (14,853) (20,260)
Loss on sale of equipment ............................... -- 1,007
Write-off of leasehold improvements ..................... -- 306,469
Reorganization costs .................................... 90,863 (61,175)
Cash settlements on derivative contracts ................ (2,573,694) 1,829,480
Loss on derivative floor contracts recognized in revenues -- 390,456
Loss on derivative contracts ............................ 11,947,692 5,892,062
Changes in assets and liabilities:
Restricted cash ........................................... 1,830,370 (3,213)
Accounts receivable ....................................... 2,479,014 388,533
Prepaid expenses and other ................................ (145,604) (312,429)
Payable to affiliates, net ................................ 133,468 208,142
Other assets .............................................. -- 1,039,322
Accounts payable and accrued liabilities .................. 2,454,683 554,567
Accounts payable subject to renegotiation ................. (199,544) (37,040)
------------- -------------
Net cash provided by operating activities ............... 3,970,596 3,968,283
------------- -------------
Cash flows from investing activities:
Additions to oil and natural gas properties ................. (3,489,863) (493,220)
Purchase of furniture, fixtures and equipment ............... (78,649) (131,186)
Proceeds from sale of oil and natural gas properties ........ 359,962 300,712
Cash settlements on derivative contracts .................... 2,573,694 (1,829,480)
Proceeds from sale of derivative contracts .................. 2,252,971 --
------------- -------------
Net cash used in investing activities ..................... 1,618,115 (2,153,174)
------------- -------------
Cash flows from financing activities:
Payment of loan fees ........................................ (21,753) --
Payments on notes payable ................................... (409,923) (472,190)
------------- -------------
Net cash provided by (used in) financing activities ....... (431,676) (472,190)
------------- -------------
Net increase in cash and cash equivalents ...................... 5,157,035 1,342,919
Cash and cash equivalents - beginning of period ................ 4,764,545 1,541,680
------------- -------------
Cash and cash equivalents - end of period ...................... $ 9,921,580 $ 2,884,599
============= =============
Supplemental Disclosures of Cash Flow Information:
Interest paid ............................................... $ -- $ 14,324
Non-cash transactions:
Purchase of derivative contracts with long-term liability ... 1,797,943 --

The accompanying notes are an integral part of these consolidated
financial statements.

5

TRI-UNION DEVELOPMENT CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - BASIS OF PRESENTATION

Tri-Union Development Corporation ("the Company"), formerly 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. Our operating areas are located onshore Texas Gulf Coast, 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 July 3, 2002, the Company defaulted under the Indenture of its senior
secured notes. As a result of the default, the holders of the notes have the
right as provided in the Indenture, to accelerate the payment of principal and
interest of the notes. Accordingly, the senior secured notes and related
deferred loan costs have been classified as current in the accompanying
consolidated balance sheets at December 31, 2002 and March 31, 2003. 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 working capital requirements and repay its indebtedness. Should
the noteholders accelerate the notes, the Company will not have the ability to
generate sufficient resources to satisfy this obligation. During 2002 and the
first quarter of 2003, the Company incurred a net loss of $39.5 and $22.8
million, respectively. Additionally, at December 31, 2002 and at March 31, 2003,
the Company has a capital deficit of $27.1 and $49.9 million, respectively and a
working capital deficit of $108.0 and $126.2 million, respectively. These
conditions raise substantial doubt about the Company's ability to continue as a
going concern.

The Company does not expect that cash flows from operations will be
sufficient to finance the payment of principal and interest on its senior
secured notes, abandonment liabilities and capital budget. The Company is
evaluating its alternatives to finance these obligations. The alternatives being
evaluated include:

o sale of oil and gas properties or production payments,
o restructuring of the senior secured notes, and
o the issuance of additional equity.

The Company has retained an investment bank to solicit bids for its oil and
gas properties. In addition, the Company has had preliminary discussions with
holders or representatives of its senior notes regarding a restructuring of the
notes. The Company has also had discussions with possible investors regarding an
investment in the Company. None of these discussions has resulted in an offer or
formal proposal. There can be no assurance that the Company will be able to
restructure its senior secured notes or locate investors willing to invest in
the Company or that terms of a restructuring or investment, if available, would
be acceptable to the Company.

A restructuring that involves a sale of all or substantially all of the
Company's assets or requires the issuance of certain amounts of equity may
require the approval of Mr. Bowman as a stockholder. The Company is currently
involved in litigation with Mr. Bowman, our former President and Chief Executive
Officer (see Note 7 - "Contingencies").

To the extent the cash generated from oil and gas property sales and cash
flows from continuing operations are insufficient to meet its debt obligations
and projected working capital needs, the Company

6

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 amount and timing of any proceeds from the
Company's plans to raise additional capital raises substantial doubt about its
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 as of March 31, 2003 and for the three months ended March 31, 2003
and 2002 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, 2002 balance
sheet was derived from audited financial statements and notes included in our
annual report on Form 10-K. The interim unaudited financial statements as of
March 31, 2003 and for the three months ended March 31, 2003 and 2002 should be
read in conjunction with the Company's annual consolidated financial statements
for the years ended December 31, 2002 and 2001. The results of operations for
the three months ended March 31, 2003, are not necessarily indicative of results
to be expected for the full year.

NOTE 4 - DERIVATIVE CONTRACTS

The Company uses derivative instruments to manage exposures to commodity
prices. The Company's objectives for holding derivatives are to minimize the
risks of reductions in market prices for its oil and natural gas production
using the most effective methods to eliminate or reduce the impacts of this
exposure. Certain derivative instruments used by the Company can reduce or
eliminate the benefit to the Company from increases in commodity prices.

In June 2001 the Company entered into three commodity SWAP derivative
contracts as a condition of the issuance of the Notes. The contracts are not
designated for hedge accounting under FAS No. 133; therefore, the Company
records these contracts at their estimated fair values, and includes the changes
in their fair value in the statement of operations.

On March 28, 2002, the Company terminated certain of its commodity price
SWAP derivative contracts for net proceeds of $2,252,971 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 $2,252,971 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 months ended March
31, 2002 and 2003. The purchase price of the floor contracts of $1,797,942 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 December
31, 2002 and March 31, 2003. 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 year ended December 31, 2002 and the three months ended March 31, 2003, the
Company recognized $906,502 and $390,455, respectively of such costs as an
offset to revenues.

The Company's SWAP contracts stipulate that the Company will receive or
make payments based upon the differential between the fixed prices specified in
the contract and the market prices in effect from time to time, as defined in
the SWAP contracts, for the notional quantities. As of April 1, 2003, the
Company has oil and natural gas SWAP contracts in place through February 2005.
Additionally, at April 1, 2003, the Company held 9 months of commodity SWAP
contracts whereby the basis differential attributable to 70 Mmcf of monthly
natural gas production from our California properties is hedged through December
31, 2003. These California contracts will settle on the basis differential
between NYMEX and PG&E Citygate. In consideration of management's plans to
market all or part of the Company's oil and natural gas properties, additional
SWAP contracts will not be put in place.

7

The estimated fair value of these contracts at December 31, 2002 and March
31, 2003 of $5,292,597 and $11,575,115, respectively and is included in the
accompanying balance sheets at December 31, 2002 and March 31, 2003 as a current
liability of $3,379,875 and $8,224,705, respectively and as a non-current
liability of $1,912,722 and $3,350,410, respectively. At March 31, 2002 and
March 31, 2003, the unrealized loss of $11,947,692 and $5,892,062, respectively
is included in the accompanying statement of operations as "Loss on Derivative
Contracts".

The Company is exposed to credit risk in the event of nonperformance by the
counterparty in the commodity price SWAP contracts; however, the Company does
not anticipate nonperformance by the counterparty.

NOTE 5 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standard's Board ("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. The Company adopted SFAS No. 143 effective
January 1, 2003 (See Note 6 - "Oil and Natural Gas Properties").

In August 2001, the 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
adoption of SFAS No. 144 in 2002 did not have a material effect on the Company's
financial condition or results of operations.

In April 2002, the 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
is 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 did not have an immediate effect on our
consolidated financial statements.

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 adoption of this consensus did not have an impact
on our results of operations.

In June 2002, the 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

8

Company has adopted the provisions of SFAS No. 146 for exit or disposal
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 exit or disposal costs as well as the amount recognized.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," which disclosures are effective for
financial statements issued after December 15, 2002. While the Company has
various guarantees included in contracts in the normal course of business,
primarily in the form of indemnities, these guarantees would only result in
immaterial increases in future costs, and do not represent significant
commitments or contingent liabilities of the indebtedness of others.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure,' which amended SFAS No. 123
"Accounting for Stock-Based Compensation." The new standard provides alternative
methods of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. Additionally, the statement
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in the annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the change
used on reported results. This statement is effective for financial statements
for fiscal years ending after December 15, 2002. The Company does not offer
employee stock-based compensation; therefore SFAS No. 148 did not have an effect
on its consolidated financial statements.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" ("FIN 46") which requires the consolidation of
variable interest entities, as defined. FIN 46 is applicable to financial
statements to be issued by the Company after 2002, however, disclosures are
required currently if the Company expects to consolidate any variable interest
entities. The Company did not consolidate any additional entities as a result of
the adoption of FIN 46.

In May 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The Company does not expect the
adoption of this statement to have a material effect on its consolidated
financial statements.

NOTE 6 - OIL AND NATURAL GAS PROPERTIES

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.
Currently, the title to this well is in dispute. At December 31, 2002 and March
31, 2003, the net cost to drill and complete the well, offset by production
revenue and lease operating expense, in the amount of $2,578,895 and $1,539,573,
respectively is shown on the accompanying balance sheet as other assets, pending
resolution of the title dispute.

Adoption of SFAS 143, "Accounting for Asset Retirement Obligations"

Effective January 1, 2003, the Company adopted SFAS 143, "Accounting for
Asset Retirement Obligations." SFAS 143 requires that the fair value of a
liability for an asset's retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. The
associated asset retirement cost is capitalized as part of the carrying value of
the long-lived asset. Subsequently, the asset retirement cost is amortized to
expense over the useful life of the asset. The majority of the asset retirement
obligation recorded relates to the expected plugging and abandonment costs of
oil and natural gas wells and the removal of pipeline, compressor and related
production facilities. The adoption of SFAS 143 resulted in our recording a
net-of-tax cumulative effect of change in accounting principle loss of $11.5
million, a current asset retirement obligation of $11.5 million, a long-term
retirement obligation of $12.6 million and an increase to oil and natural gas
properties of $12.6 million. The remainder of the retirement obligation will be
accreted over the remaining useful life our oil and natural gas properties and
production facilities.

9

During the quarter ended March 31, 2003, the Company recognized accretion
expense as a result of the asset retirement obligation of approximately $0.9
million, which has been included in depreciation, depletion and amortization
expense in the accompanying consolidated statement of operations. As of December
31, 2002 and March 31, 2003, the Company had $5.3 million and $5.4 million,
respectively of restricted cash and bonds pledged for the future plugging and
abandonment of our oil and natural gas wells and related production facilities.

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 a Waiver, Agreement and Supplement ("Waiver") to the Indenture for
its senior secured notes. The Waiver, among other things, allowed the Company to
add a scheduled interest payment, in the amount of $8,125,000, to the balance of
the notes. 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. The Company has filed claims against the
former executive, and related entities, alleging, among other things, 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.
Additionally, the Company vacated its office space, which was leased from Lovett
Properties, Ltd. ("Lovett"), an entity owed by the Company's former Chief
Executive Officer ("Bowman") as of the end of March 2003. Lovett has
counterclaimed against the Company alleging a breach of the lease agreement,
which Bowman and Lovett contend binds the Company to continue leasing from
Lovett for approximately another three years. Under the terms of the lease
agreement with Lovett, the monthly base rental was $26,000 per month and the
Company was responsible for certain expenses associated with the building,
including property taxes, insurance, maintenance and utilities. The Company has
alleged that the lease is void and unenforceable because it was unfair to the
Company, and was entered into in violation of Bowman's fiduciary obligation to
the Company. As a result of the Company's decision to vacate the Lovett offices,
net capitalized leasehold improvements in the amount of $306,469 were charged to
expense during the first quarter of 2003. Accordingly, as required by FASB No.
146, Accounting for Costs Associated with Exit or Disposal Activities, the
Company recorded a lease termination liability of $208,142, which represents the
fair value of the exit costs associated with the rejection of the Lovett lease
agreement, net of estimated sublease rental income. The liability will be
amortized to expense over the remaining life of the lease agreement. Although
the outcome of these matters is uncertain, the Company does not anticipate that
their resolution will have any additional material adverse impact on the
Company's consolidated financial position or results of operations.

NOTE 8 - SUBSEQUENT EVENTS

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 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. On April 17, 2002, we entered into an agreement
with Chieftain to stay the litigation for a six-month period in which we
conducted an audit of Chieftain's books and records relating to the litigation.
We completed our joint audit of Chieftain's books and records and entered into a
final settlement and release agreement (the "Agreement") effective April 24,
2003. As a result of the joint interest audit and pursuant to the agreement,
Chieftain credited back to Tri-Union approximately $0.9 million plus interest.
Chieftain further agreed to release to us the remaining amount of restricted
cash held in escrow since our emergence from bankruptcy totaling approximately
$0.5 million. We agreed to pay Chieftain approximately $0.8 million, which
represents the total of outstanding billings owed Chieftain from the end of the
audit period through March 31, 2003.

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 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 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.

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, 2002, our net proved reserves were 187.3 Bcfe with a PV-10
Value of $241.7 million. Our total proved reserve quantities at December 31,
2002 decreased by 2.3% versus those at December 31, 2001. The decrease in total
proved reserves was primarily due to the sale in 2002 of 21 producing fields. At
December 31, 2001, these 21 fields had 1,222 Mbbl and 14,930 Mmcf, or 22,264
Mmcfe of net proved reserves. This decrease was offset by extension and
discovery reserve additions of 587 Mbbl and 11,368 Mmcf, or 14,892 Mmcfe,
primarily in our AWP and Giddings fields in the Gulf Coast area and Willows
Beehive field in California. The increase in reserves was primarily the result
of lower operating costs, extended producing lives and adjustments for well
performance history. Our capital budget has been primarily focused on converting
proved developed non-producing and proved undeveloped reserves to production.

During 2002 and the first quarter of 2003 our capital expenditures on oil
and gas activities totaled approximately $6.5 and $.5 million, respectively.
These expenditures related to operations in our three core areas. During 2002,
51%, or $3.3 million of our capital expenditures were for the drilling and
recompletion of 58 projects primarily on California and Gulf Coast properties.
The remaining 49%, or $3.2 million of our capital expenditures were primarily
for the development of PUD acreage in Grimes County, Texas and plugging and
abandonment work on 4 properties. During the first quarter of 2003, 72%, or $0.4
million of our capital expenditures were for a fracture stimulation and running
tubing on our Westbury Farms #1 well in Constitution field. The remaining 28%,
or $0.1 million of our capital expenditures were for recompletion activity on 5
wells in Hastings, Sour Lake and SE Winnie fields.

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 March 31, 2003 Compared to Three Months Ended March 31, 2002

For the three months ended March 31, 2003, consolidated net loss was
$22,794,750 as compared to consolidated net loss of $17,541,235 for the three
months ended March 31, 2002.

11

OIL AND GAS REVENUES. Oil and natural gas revenues decreased $1,317,217, or
12%, to $9,993,436 for the three months ended March 31, 2003, from $11,310,653
for the three months ended March 31, 2002. The decrease in oil and natural gas
revenues was primarily the result of a decrease in production during the period.
Additionally, we sold our Louisiana properties during the second quarter of
2002, certain of our Gulf Coast properties during the second and fourth quarter
of 2002, and shut-in one Texas offshore property in the first quarter of 2002.
Additionally, during the first quarter of 2003, one of our Louisiana offshore
properties was shut-in due to storm damage. These sold and shut-in properties
produced 504 Mcfe of production during the first quarter 2002. The decrease in
oil and natural gas revenues is also attributable to our experiencing general
production declines primarily in our West Hastings, Sour Lake, Spindletop,
Constitution, Grimes and Sycamore fields. These properties experienced a total
of 427 Mcfe of production declines in the first quarter of 2003 when compared to
the first quarter of 2002. The decrease in oil and natural gas revenue was
partially offset by a $0.99 per Mcfe, or 27% increase in the average price
received for the sale of production during the quarter ended March 31, 2003 when
compared to the average price received during the quarter ended March 31, 2002.
The following table summarizes the consolidated results of oil and natural gas
production and related pricing for the three months ended March 31, 2002 and
2003:

For the Three Months Ended March 31,
--------------------------------------------
2002 2003 % Change
------------- ------------- -------------

Oil production volumes (Mbbls) ................... 253 185 -27%
Gas production volumes (Mmcf) .................... 1,549 1,024 -34
Total (Mmcfe) ............................... 3,065 2,134 -30

Average oil price (per Bbl) ...................... $23.20 $29.53 27%
Average gas price (per Mcf) ...................... 3.52 4.43 26
Average price (per Mcfe) ......................... 3.69 4.68 27

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 have not
been designated for hedge accounting under FAS 133; therefore, the Company marks
these transactions to fair value. Changes in the fair value during the period
are recorded as gains or losses on derivative contracts. 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 $2,252,971. The purchase
price of the floor contracts of $1,797,942 has been financed by the Company's
derivative contracts counterparty. The change in estimated fair value of these
contracts during the three months ended March 31, 2002 and 2003 resulted in a
net non-cash loss on derivative contracts of $11,947,692 and $5,892,062,
respectively.

OTHER. Other income decreased $927,487 or 96% to $41,898 for the three
months ended March 31, 2003 when compared to $969,385 for the three months ended
March 31, 2002. The decrease was primarily the result of the sale of emission
reduction credits in the amount of $818,850 from our Hastings field during the
first quarter of 2002. There were no sales of emission reduction credits during
the first quarter of 2003. Additionally, the decrease is the result of a
decrease in the amount of interest, management fee and transportation income of
$106,853 during the three months ended March 31, 2003 when compared to the three
months ended March 31, 2002.

LEASE OPERATING EXPENSE. Lease operating expense decreased $1,019,961, or
21%, to $3,732,613 for the three months ended March 31, 2003 from $4,752,574 for
the three months ended March 31, 2002. Lease operating expense was $1.75 per
Mcfe for the three months ended March 31, 2003, an increase of $0.20 per Mcfe or
13% from $1.55 per Mcfe for the three months ended March 31, 2002. The decrease
in lease operating expense is partially the result of the sale of our Louisiana
properties during the second quarter of 2002 and certain of our Gulf Coast
properties during the second and fourth quarter of 2002. Additionally, the
decrease in lease operating expense is the result of the shut-in of five Texas
offshore properties in the first quarter of 2002, the shut-in of an additional
Texas offshore property in the second quarter of 2002 and the shut-in of a
Louisiana offshore property during the first quarter of 2003 due to

12

storm damage. The decrease in lease operating expense calculated on a unit of
production basis is primarily the result of a 931 Mcfe, or 30%, decrease in
production volumes and a 21% decrease in lease operating expense during the
quarter ended March 31, 2003 when compared to the quarter ended March 31, 2002.

WORKOVER EXPENSE. Workover expense decreased $890,541, or 46%, to
$1,061,355 for the three months ended March 31, 2003 from $1,951,896 for the
three months ended March 31, 2002. Workover expense was $0.50 per Mcfe for the
three months ended March 31, 2003, a decrease of 22% from $0.64 per Mcfe for the
three months ended March 31, 2002. The decrease is primarily the result of the
Company's decision to restrict the use of cash during the first quarter of 2003.
During the three months ended March 31, 2003, workover expense, calculated on a
unit of production basis decreased by $0.14, or 22% per Mcfe.

PRODUCTION TAXES. Production taxes decreased by $63,162 or 28% to $166,360
for the three months ended March 31, 2003 from $229,522 for the three months
ended March 31, 2002. Production taxes were $0.08 per Mcfe for the three months
ended March 31, 2003, an increase of 4% from $0.07 per Mcfe for the three months
ended March 31, 2002. Decreases in oil and natural gas production and revenues
during the three months ended March 31, 2003, resulted in a proportionate
decrease in the amount of production taxes incurred during the period.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"). DD&A expense
increased by $28,485 or 1%, to $2,523,749 for the three months ended March 31,
2003 from $2,495,264 for the three months ended March 31, 2002. DD&A was $1.18
per Mcfe for the three months ended March 31, 2003, an increase of 45% from
$0.81 per Mcfe for the three months ended March 31, 2002. The increase in DD&A
is primarily the result the Company's adoption of SFAS 143, "Accounting for
Asset Retirement Obligations" effective January 1, 2003 more fully described
below in "Cumulative Effect of Change in Accounting Principle". SFAS 143
requires that the fair value of a liability for an asset's retirement obligation
be recognized in the period in which it is incurred if a reasonable estimate of
fair value can be made. The associated asset retirement cost is capitalized as
part of the carrying value of the long-lived asset. Subsequently, the asset
retirement obligation is amortized to expense over the useful life of the asset.
Accordingly, $0.9 million of this capitalized retirement obligation was expensed
during the first quarter of 2003. This increase was offset by a 931 Mcfe, or
30%, decrease in the amount of depletion recorded from production activities
during the first quarter of 2003.

GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A increased $582,814, or 49%,
to $1,782,347 for the three months ended March 31, 2003 from $1,199,533 for the
three months ended March 31, 2002. G&A was $0.84 per Mcfe for the three months
ended March 31, 2003, an increase of 113% from $0.39 per Mcfe for the three
months ended March 31, 2002. The increase was primarily the result of a $671,629
increase in legal expenses. This increase was partially offset by a decrease in
payroll and payroll related burdens in the amount of $473,942 and a decrease in
travel and entertainment expenses of $114,947. Additionally, the Company vacated
its office space, which was being leased from Lovett Properties, Ltd.
("Lovett"), a Bowman affiliate as of the end of March 2003. As a result of this
relocation, net capitalized leasehold improvements in the amount of $306,469
were expensed during the first quarter of 2003 (see Item 1 - "Legal
Proceedings"). Lovett has counterclaimed against the Company alleging a breach
of the lease agreement, which Bowman and Lovett contend binds the Company to
continue leasing from Lovett for approximately another three years. Under the
terms of the lease agreement with Lovett, the monthly base rental was $26,000
per month and we were responsible for certain expenses associated with the
building, including property taxes, insurance, maintenance and utilities.
Although the outcome of this matter is uncertain, as required by FASB No. 146,
Accounting for Costs Associated with Exit or Disposal Activities, the Company
recorded a liability of $208,142 which represents the fair value of the exit
costs associated with the rejection of the Lovett lease agreement, net of
estimated sublease rental income. The liability will be amortized to expense
over the remaining life of the lease agreement. The 52% increase in G&A
calculated on an Mcfe basis is primarily attributable to a 30% decrease in
production volumes during the three months ended March 31, 2003 when compared to
the three months ended March 31, 2002.

INTEREST EXPENSE. Interest expense decreased $881,265 or 12%, to $6,272,664
for the three months ended March 31, 2003 from $7,153,929 for the three months
ended March 31, 2002. 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 March 31, 2003,
a $12.0 million decrease from $130.0 million at March 31, 2002. Additionally,
the decrease is attributable to a

13

decrease of amortization of deferred loan costs to interest expense of
$1,657,367 for the three months ended March 31, 2002 when compared to $1,402,384
for the three months ended March 31, 2003.

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 March 31, 2003, a reduction
in the amount of $61,175 was recorded to previously expensed reorganization
costs. This compares to reorganization costs in the amount of $90,863 during the
three months ended March 31, 2002.

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE. The Company adopted
SFAS 143, "Accounting for Asset Retirement Obligations" effective January 1,
2003. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recognized in the period in which it is incurred if a
reasonable estimate of fair value can be made. The associated asset retirement
cost is capitalized as part of the carrying value of the long-lived asset.
Subsequently, the asset retirement cost is amortized to expense over the useful
life of the asset. The majority of the asset retirement obligation we recorded
relates to the plugging and abandonment of oil and natural gas wells and the
removal of pipeline, compressor and related production facilities. The adoption
of SFAS 143 resulted in our expensing a net-of-tax cumulative effect of change
in accounting principle loss of $11.5 million at January 1, 2003.

LIQUIDITY AND CAPITAL RESOURCES

Historically our primary source of capital consists of cash flows generated
from the production of our oil and natural gas properties and the issuance of
the senior secured notes. During 2003, we may generate additional working
capital from the sale of oil and natural gas properties.

During 2002 and continuing into 2003, our primary uses of capital are for
the payment of principal and interest on our senior secured notes and for the
development of our oil and natural gas properties.

In connection with the issuance of the 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. As of March 31, 2003, the Company has oil and
natural gas SWAP contracts in place through February 2005. In consideration of
management's plans to market all or part of the Company's oil and natural gas
properties, the Company does not plan to enter into additional SWAP contracts.

At March 31, 2003, our unrestricted cash balance was $2.9 million, a $1.4
million increase from our cash balance at December 31, 2002.

Net cash provided by operating activities decreased $8.8 million to $0.3
million for the three months ended March 31, 2003 compared to net cash provided
by operating activities of $9.1 million for the three months ended March 31,
2002. The decrease is partially the result of a the Company's reported net loss
of $22.8 million for the three months ended March 31, 2003 when compared to a
net loss of $17.5 million for the three months ended March 31, 2002. During the
three months ended March 31, 2003, we recorded a loss on the mark-to-market
value of our derivative contracts of $5.9 million when compared to a loss on the
mark-to-market value of derivative contracts of $12.0 million for the three
months ended March 31, 2002, a decrease of $6.1 million. Cash settlements paid
on our derivative contracts during the three months ended March 31, 2003 were
$1.8 million when compared to cash settlements received of $2.6 million during
the three months ended March 31, 2002, resulting in a $4.4 million decrease. 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 March 31, 2003, $11.9 million of
the cash deposited into this restricted account had been disbursed to us or to
claimants of pre-petition claims. At March 31, 2003, the balance in the
restricted account was $1.6 million. Additionally, during the three months ended
March 31, 2003 accounts receivable and accounts payable and accrued liabilities
decreased $4.0 million when compared to the three months ended March 31, 2002.
These decreases were offset by an $11.5 million loss as a result of our adoption
of SFAS 143, "Accounting for Asset Retirement Obligations" effective January 1,
2003.

Net cash provided by investing activities was $1.5 million during the three
months ended March 31, 2003 compared to net cash used in investing activities of
$3.5 million during the three months ended March 31, 2002. The increase in net
cash provided by investing activities is primarily the result of a decrease in
additions to oil and natural gas properties of $3.0 million during the three
months ended March 31, 2003

14

when compared to the three months ended March 31, 2002. Additionally, the
Company recorded net cash settlements under derivative contracts of $1.8 million
during the quarter ended March 31, 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 development of oil and natural gas properties.

At March 31, 2003, we had $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, 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 $83.1 million is due June 1, 2006. Interest is payable
semi-annually on June 1 and December 1 of each year. On June 1, 2002, the
Company was required to make a $28.1 million payment of principal and interest
on its senior secured notes, and an additional scheduled interest payment of
approximately $7.4 million was due on December 1, 2002. In addition, the Company
has a scheduled principal and interest payment of approximately $27.4 million
due June 1, 2003. The Company made its scheduled principal payment of $20.0
million due on June 1, 2002, but refinanced its scheduled interest payment of
$8.1 million into additional promissory notes under the terms of a Waiver,
Agreement and Supplemental Indenture (the "Waiver"). The Company is currently in
default under the terms of the Indenture as amended by the Waiver. Holders of
the senior secured notes, subject to the requirements set forth in the
Indenture, can declare the balance of the outstanding principal and interest due
on demand (see Item 3 - "Defaults Upon Senior Securities"). Accordingly, the
senior secured notes and related deferred loan costs have been classified as
current in the accompanying consolidated balance sheet at March 31, 2003. 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 evaluating its alternatives regarding the June 1,
2003 scheduled payment of principal and interest due on the senior secured
notes. These alternatives include the marketing of its oil and natural gas
properties, the restructuring of the senior secured notes and arranging for
additional capital.

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 or restructure the senior secured notes. No assurance can be
given that the Company can restructure the senior secured notes or 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.

15

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, the Financial Accounting Standard's Board ("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. The Company adopted SFAS No. 143 effective
January 1, 2003 (See Note 6 - "Oil and Natural Gas Properties").

In August 2001, the 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
adoption of SFAS No. 144 in 2002 did not have a material effect on the Company's
financial condition or results of operations.

In April 2002, the 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
is 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 did not have an immediate effect on our
consolidated financial statements.

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

16

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 adoption of this consensus did not have an impact
on our results of operations.

In June 2002, the 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 has adopted the
provisions of SFAS No. 146 for exit or disposal 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 exit or disposal costs
as well as the amount recognized.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," which disclosures are effective for
financial statements issued after December 15, 2002. While the Company has
various guarantees included in contracts in the normal course of business,
primarily in the form of indemnities, these guarantees would only result in
immaterial increases in future costs, and do not represent significant
commitments or contingent liabilities of the indebtedness of others.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure,' which amended SFAS No. 123
"Accounting for Stock-Based Compensation." The new standard provides alternative
methods of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. Additionally, the statement
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in the annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the change
used on reported results. This statement is effective for financial statements
for fiscal years ending after December 15, 2002. The Company does not offer
employee stock-based compensation; therefore SFAS No. 148 did not have an effect
on its consolidated financial statements.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" ("FIN 46") which requires the consolidation of
variable interest entities, as defined. FIN 46 is applicable to financial
statements to be issued by the Company after 2002, however, disclosures are
required currently if the Company expects to consolidate any variable interest
entities. The Company did not consolidate any additional entities as a result of
the adoption of FIN 46.

In May 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003. The Company does not expect the
adoption of this statement to have a material effect on its consolidated
financial statements.

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 on our December 31, 2002 report filed on form
10K. 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.

17

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 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."

Accounting for Asset Retirement Obligations - Effective January 1, 2003,
the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations."
SFAS 143 requires that the fair value of a liability for an asset's retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. The associated asset retirement cost is
capitalized as part of the carrying value of the long-lived asset. Subsequently,
the asset retirement cost is amortized to expense over the useful life of the
asset. The majority of the asset retirement obligation recorded relates to the
plugging and abandonment of oil and natural gas wells, the removal of pipeline,
compressor and related production facilities.

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

18

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.

19

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. 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 $2,252,971. The purchase price of the floor contracts
of $1,797,943 has been financed by the Company's derivative contracts
counterparty. As of April 1, 2003, the Company has oil and natural gas SWAP
contracts in place through February 2005. In consideration of management's plans
to market all or part of the Company's oil and natural gas properties,
additional SWAP contracts will not be put in place. The following table reflects
the production volumes and the weighted average prices under our commodities
price swaps, which remain in place at March 31, 2003:

NYMEX SWAPS
---------------------------------------
VOLUME NYMEX PRICE
--------------- ------------------
QUARTER ENDING MMCF MBBL $/MMBTU $/BBL
-------------- ------ ------ ------- -------

June 30, 2003 ............ 404 -- 4.04 --
September 30, 2003........ 708 177 3.27 22.33
December 31, 2003 ........ 708 177 3.44 20.69
March 31, 2004 ........... 462 115 3.36 20.97
June 30, 2004 ............ 711 152 3.67 23.01
September 30, 2004 ....... 718 153 3.58 22.99
December 31, 2004 ........ 718 153 3.69 22.68
March 31, 2005 ........... 461 98 4.11 23.08

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 March 31, 2003:

NYMEX FLOORS
-------------------
VOLUME
-------------------
QUARTER ENDING MMCF MBBL
-------------- ----- ----

June 30, 2003 ............... 909 173
March 31, 2004 .............. 242 52

Additionally, at April 1, 2003, the Company held 9 months of commodity SWAP
contracts whereby the basis differential attributable to 70 Mmcf of monthly
natural gas production from our California properties is hedged through December
31, 2003. These California contracts will settle on the basis differential
between NYMEX and PG&E Citygate.

20

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.

21

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"). Bowman primarily
asserts claims, individually and derivatively, complaining of and contesting the
Company's entry into the Waiver to the Indenture and related transactions. Among
other challenges, Bowman complains that the issuance of stock in connection with
the Waiver inappropriately and intentionally diluted Bowman's ownership in the
Company below 50% of the outstanding stock. Among other relief, Bowman seeks to
rescind or void the Waiver and related stock issuance. The Company intends to
vigorously defend against Bowman's attempt to rescind 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, among other things, multiple 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 on Lovett Boulevard
in Houston, which was leased from these Bowman affiliates. The Company's claims
are that Bowman has improperly used and diverted corporate funds for his own
benefit and for the benefit of his affiliates.

The Company vacated its Lovett offices as of the end of March 2003. Lovett
has counterclaimed against the Company alleging breach of the lease agreement,
which Bowman and Lovett contend binds the Company to continue leasing from
Lovett for approximately another three years. The Company has alleged that the
lease is void and unenforceable because it was unfair to the Company, and was
entered into in violation of Bowman's fiduciary obligation to the Company.

Also in August 2002, 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.

In March 2003, Bowman and his affiliates, the Company, and Jefferies
reached an agreement to temporarily defer most of the proceedings in both the
Harris County and Grimes County actions. The parties have asked the Court for a
trial setting in the Harris County action in January 2004.

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 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. ss.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 conducted an audit of
Chieftain's books and records relating to the litigation and transferred to
Chieftain $5.0 million of the funds

22

segregated pending the trial and/or non-judicial resolution of our dispute with
Chieftain. We completed our joint audit of Chieftain's books and records and
entered into a final settlement and release agreement (the "Agreement")
effective April 24, 2003. As a result of the joint interest audit and pursuant
to the agreement, Chieftain credited back to Tri-Union approximately $0.9
million plus interest. Chieftain further agreed to release to us the restricted
cash held in escrow totaling approximately $0.5 million. We agreed to pay
Chieftain approximately $0.8 million, which represents the total of outstanding
billings owed Chieftain from the end of the audit period through March 31, 2003.

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

None.

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. 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 refinanced its scheduled interest payment through the issuance
of additional promissory notes (the "New Notes") under the terms of a Waiver,
Agreement and Supplemental Indenture (the "Waiver") with terms identical to the
terms of the Series A Notes.

The Waiver contained additional covenants some of which required the
Company to obtain clear title to an oil and gas property and subject this
property to a lien by no later than August 2, 2002 and required the Company to
maintain minimum daily production levels of 28.5 Mmcfe of average daily
production. Additionally, the Waiver required the Company to report EBITDA, as
adjusted to exclude the non-cash effect of any oil and natural gas hedging
contracts, as of the end of the third quarter of 2002, at a level of $4.0
million ("Base EBITDA") and, as of the end of each fiscal quarter thereafter, to
report Base EBITDA compounded by an additional 5% for each succeeding fiscal
quarter. Additionally, pursuant to the Waiver, the Company was required to file
a registration statement with the Securities and Exchange Commission ("SEC")
relative to the new notes and to cause that registration statement to become
effective on or before March 3, 2003. 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 the required amounts of EBITDA, and has not filed or caused a
registration statement to become effective with the SEC, several events of
default have occurred under the terms of the Waiver.

In connection with the original issuance of the notes on June 18, 2001, we
agreed to maintain, on a monthly basis, a rolling two-year hedge program until
the maturity of the notes, subject to certain conditions. As of March 31, 2003,
the Company has oil and natural gas SWAP contracts in place through February
2005. In consideration of management's plans to market all or part of the
Company's oil and natural gas properties, additional SWAP contracts will not be
put in place. As a result, a default exists pursuant to the Indenture, which
requires the Company to maintain a two-year hedge program.

23

These defaults accelerate the principal and interest payments due on the
notes and if not cured, allow the noteholders, subject to the provisions of the
Indenture, by notice to the Company, to 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 and related deferred loan
costs have been classified as current in the accompanying consolidated balance
sheet at March 31, 2003.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

24

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.

25

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

EXHIBIT
NUMBER DESCRIPTION
- ------- ----------------------------------------------------------------------

2.1 Debtor's First Amended Plan of Reorganization approved on May 23, 2001
by the United States Bankruptcy Court for the Southern District of
Texas, Houston Division (1)

2.2 Agreement and Plan of Merger between Tribo Petroleum Corporation and
Tri-Union Development Corporation, dated July 27, 2001 (1)

3.1 Restated Articles of Incorporation for Tri-Union Development
Corporation, as amended through July 2001. (1)

3.2 By-laws of Tri-Union Development Corporation as amended and restated
through June 18, 2001. (1)

3.3 Certificate of Incorporation for Tri-Union Operating Company dated as
of November 1, 1974, as amended through May 30, 1996. (1)

3.4 By-laws of Tri-Union Operating Company as amended and restated through
June 18, 2001. (1)

4.1 Indenture Agreement by and between Tri-Union Development Corporation,
as Issuer, Tribo Petroleum Corporation, as Parent Guarantor, and
Firstar Bank, National Association, as Trustee, dated June 18, 2001.
(1)

4.2 Purchase Agreement between Tribo Petroleum Corporation, Tri-Union
Development Corporation, Tri-Union Operating Company and Jefferies &
Company, Inc., dated June 18, 2001. (1)

4.3 Registration Rights Agreement by and among Tri-Union Development
Corporation, Tri-Union Operating Company, Tribo Petroleum Corporation
and Jefferies & Company, Inc., dated June 18, 2001. (1)

4.4 Equity Registration Rights Agreement by and between Tribo Petroleum
Corporation and Jefferies & Company, Inc., dated June 18, 2001. (1)

4.5 Intercreditor and Collateral Agency Agreement among Tri-Union
Development Corporation, Tribo Petroleum Corporation, Tri-Union
Operating Company and Wells Fargo Bank Minnesota, National
Association, as Collateral Agent, and Firstar Bank, National
Association, as Trustee, dated June 18, 2001. (1)

4.6 Pledge and Collateral Account Agreement among Wells Fargo Bank
Minnesota, National Association, as Collateral Agent, Tribo Petroleum
Corporation, Tri-Union Development Corporation and Tri-Union Operating
Company, as Obligors, dated June 18, 2001. (1)

4.7 Mortgage, Deed of Trust, assignment of Production, Security Agreement
and Financing Statement of Tri-Union Development Corporation, dated
June 18, 2001. (1)

4.8 Waiver, Agreement and Supplemental Agreement dated as of July 3, 2002
by and among Tri-Union Development Corporation, each of the Guarantors
party thereto, U.S. Bank National Association, formerly known as
Firstar Bank National Association, Jefferies & Company, Inc. and each
of the noteholders party thereto, filed as a comparably numbered
Exhibit to the June 30, 2002 Report on Form 10-Q.

10.1 Amended and Restated Lease Agreement between Tribo Production Company,
Ltd. and Tri-Union Development Corporation dated June 18, 2001. (1)

10.2 ISDA Master Agreement by and between Bank of America, N.A. and
Tri-Union Development Corporation, dated June 18, 2001. (1)

21.1 Subsidiaries of Registrant. (1)

99.1* Certification of Chief Executive Officer pursuant to 18 U.S.C. Section
1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.

99.2* Certification of Chief Financial Officer pursuant to 18 U.S.C. Section
1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.

* Filed herewith

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

26

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

May 15, 2003 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

27

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: May 15, 2003
--------------------------------------

/s/ James M. Trimble
- -----------------------------------------------
James M. Trimble
President and Chief Executive Officer

28

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: May 15, 2003
--------------------------------------

/s/ Suzanne R. Ambrose
- -----------------------------------------------
Suzanne R. Ambrose
Vice President and Chief Financial Officer

29

INDEX TO EXHIBITS

99.1 Certification of Chief Executive Officer

99.2 Certification of Chief Financial Officer