TRI UNION DEVELOPMENT CORP - 10-K Annual Report

Back to GetFilings.com

U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X] ANNUAL 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 fiscal year ended December 31, 2002

Commission file number: 333-66282

TRI-UNION DEVELOPMENT CORPORATION
(Exact name of registrant as specified in its charter)

Texas 76-0381207
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification Number)

801 Travis, Suite 2102 77002
Houston, Texas (Zip Code)
(Address of principal executive offices)

(713) 533-4000
(Registrant's telephone number, including area code)

Securities Registered pursuant to Section 12(b) of the Act:

None

Securities Register pursuant to Section 12(g) of the Act:

None

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).

yes X no
------ ------

Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

yes X no
------ ------

As of March 31, 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.

Documents incorporated by reference: None

TRI-UNION DEVELOPMENT CORPORATION
(formerly Tribo Petroleum Corporation)

TABLE OF CONTENTS

Part I.

Item 1. Business ............................................................................. 2
Item 2. Properties ........................................................................... 5
Item 3. Legal Proceedings .................................................................... 20
Item 4. Submission of Matters to a Vote of Security Holders .................................. 21

Part II.

Item 5. Market for Common Stock and Related Shareholder Matters .............................. 21
Item 6. Selected Financial Data .............................................................. 23
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations .......................................................... 24
Item 7a. Qualitative and Quantitative Disclosures About Market Risks .......................... 35
Item 8. Financial Statements and Supplementary Data .......................................... 36
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure ........................................................... 36

Part III.

Item 10. Directors and Executive Officers of the Registrant ................................... 36
Item 11. Director and Executive Compensation .................................................. 37
Item 12. Security Ownership of Certain Beneficial Owners and Management ....................... 38
Item 13. Certain Relationships and Related Transactions ....................................... 38

Part IV.

Item 14. Controls and Procedures .............................................................. 40
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ..................... 41

Glossary of Selected Oil and Gas Terms ............................................................................. 42
Signatures ......................................................................................................... 45
Section 302 Officers' Certifications ............................................................................... 46
Financial Statements
Reports of Independent Public Accounts ................................................................. F-2
Consolidated Balance Sheets ............................................................................ F-3
Consolidated Statements of Operations and Comprehensive Income (Loss) .................................. F-4
Consolidated Statements of Stockholders' Equity (Capital Deficit) ...................................... F-5
Consolidated Statements of Cash Flows .................................................................. F-6
Notes to Consolidated Financial Statements ............................................................. F-8

1

SUMMARY

Unless specified otherwise, references to "Tri-Union," "we," and "our" refer to
Tri-Union Development Corporation ("TDC") and Tri-Union Operating Company
("TOC"), our wholly owned subsidiary. The consolidated historical financial,
reserve, and operating data set forth include information for our subsidiary and
us on a consolidated basis. The information in this report gives effect to our
merger with our former parent corporation, Tribo Petroleum Corporation, on July
27, 2001. If you are not familiar with some of the oil and natural gas terms
used in this report, please read "Glossary of Selected Oil and Natural Gas
Terms" beginning on page 42.

PART I.

ITEM 1. BUSINESS

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. Our operating areas are located onshore Texas
Gulf Coast, offshore Gulf Coast in the shallow waters of the Gulf of Mexico and
in the Sacramento Basin of northern California.

We have one subsidiary, Tri-Union Operating Company, which is wholly owned
by us. Tri-Union Operating Company's principal asset is a net profits interest
in a field operated by us representing less than 5% of our consolidated proved
reserves.

At December 31, 2002, we had estimated net proved reserves of 187.3 Bcfe,
approximately 45.7% of which were natural gas, with a reserve life of 18.1
years. Our reserve base is diversified across our three core areas, with 69.5 %
of our proved reserves located onshore Gulf Coast, 4.0% offshore Gulf Coast and
26.5% in California. Each of these core areas is characterized by years of
stable, historical production and numerous producing wells. We operate
approximately 98% of our proved reserves.

We own interests in 15 fields located onshore Gulf Coast, 13 producing
blocks offshore Gulf Coast and 15 fields located in California. During 2002, we
had average production of approximately 28.4 Mmcfe per day.

We have a large inventory of development projects that we have only
recently begun to exploit. Because we operate in older, more mature fields with
long production histories and many producing wells, we believe these projects
represent low-risk opportunities to add to our reserves.

In our California region during 2002, we participated in the drilling of 4
development wells, and completed 33 sidetrack/deepening and stimulation projects
of existing wells. We continue to evaluate seismic data acquired in 2001 and
expect the results to lead to a significant number of additional opportunities.
As discussed below, our current working capital constraints may restrict our
ability to pursue these opportunities.

At December 31, 2002, approximately 80% of our projected oil and natural
gas production from proved developed producing reserves was hedged through
December 31, 2004 at average SWAP prices of $3.62 per Mcf and $22.91 per Bbl, or
a weighted-average natural gas-equivalent price of approximately $3.73 per Mcfe.
In connection with the issuance of our 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 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 (Henry Hub) and $18.50 per
barrel of crude oil (West Texas Intermediate).

We acquired our first significant reserves in 1996 with the Reunion
acquisition. Since January 1997, our first full year following the Reunion
acquisition, our reserves increased from 46.9 Bcfe to 187.3 Bcfe.

On July 27, 2001, we were the surviving corporation in a merger with our
parent corporation, Tribo Petroleum Corporation. As a consequence of this
merger, we assumed all of the rights and obligations of Tribo.

RECENT DEVELOPMENTS

Senior Secured Notes. On June 18, 2001 we issued $130 million of 12.5%
senior secured notes due June 1, 2006. Interest on the notes are payable
semiannually on June 1 and December 1 of each year. Principal is payable in
installments beginning on June 1, 2002, with final maturity on June 1, 2006.

2

On June 1, 2002, we were required to make a $28,125,000 payment of
principal and interest on our senior secured notes, and an additional scheduled
interest payment of approximately $7,400,000 on December 1, 2002. We made the
scheduled principal payment of $20,000,000 due on June 1, 2002 and the scheduled
interest payment of $7,400,000 on December 1, 2002. We issued additional notes
to satisfaction of the interest payment due June 1, 2002 in the amount of
$8,125,000. In connection with the issuance of additional notes to satisfy the
June 1, 2002 interest payment, we entered into a Waiver, Agreement and
Supplemental Indenture (the "Waiver") with the holders of the senior secured
notes. The Waiver contained additional covenants, one of which required that we
obtain clear title to an oil and gas property subject to lien by no later than
August 2, 2002. Additionally, the Waiver contained covenants requiring us to
maintain average daily production levels of 28.5 Mmcfe per day and to generate
$4.0 million and $4.2 million of EBITDA, as adjusted for the non-cash effects of
oil and gas hedging contracts as of the end of September 30, 2002 and December
31, 2002, respectively. We were unable to obtain clear title to the subject
property by August 2, 2002, did not maintain the required production levels, and
did not meet the required EBITDA thresholds. As a result, an event of default
occurred under the Waiver and the Indenture for the notes. Because of the event
of default, the holders of the senior secured notes have the right, upon
compliance with the procedures set forth in the indenture, to declare the entire
principal and interest of the notes immediately due and payable. Accordingly,
the senior secured notes and related deferred loan costs have been classified as
current in the accompanying consolidated balance sheet at December 31, 2002.

On June 1, 2003, we are required to pay approximately $27.4 million of
principle and interest on the senior secured notes, and an additional scheduled
interest payment of $6,133,000 due on December 1, 2003.

Change of control. As additional consideration to cause the holders of our
senior secured notes to approve the Waiver, we issued 76,667 shares of our
common stock to the holders of the senior secured notes. As a result of this
issuance, Mr. Richard Bowman ceased to own a majority of our common stock. Mr.
Bowman has initiated litigation against us in connection with this issuance of
common stock.

Abandonment Costs and Bonding Requirements. We operate oil and natural gas
properties in the Gulf of Mexico, which obligates us to pay substantial costs to
abandon wells that are no longer producing, to remove any and all structures and
facilities and to verify site clearance. We estimate that our abandonment costs
during 2003 and 2004 will be $5.8 million and $6.8 million respectively, and
$11.1 million thereafter. Under requirements of the U.S. Department of Interior,
U.S. Minerals Management Service ("MMS"), we have caused surety bonds in the
amount of $9.9 million to be issued to secure our obligations. The issuer of the
bonds has notified us on several occasions that it intends to cancel all or a
portion of the outstanding bonds. The issuer of the bonds has cancelled a
portion of our bonds, but a $3.0 million area wide development bond remains in
effect and allows us to continue production, however, we cannot pursue any new
development. If the bond issuer were to cancel the remaining bond, the MMS will
have the right, which we expect they would exercise, to issue a shut-in order,
requiring that we cease producing the bonded off-shore properties we operate. If
the MMS issues a shut-in order, the MMS would, in effect, take over operation of
our operated offshore facilities, and we would no longer have access to such
facilities. The cost incurred by the MMS to operate our facilities would be
required to be paid by us. In addition, the shut-in of our wells by the MMS will
require us to begin abandonment operations earlier than scheduled, thereby
accelerating our obligation to pay abandonment costs described above. The MMS
may also have the ability to assess fines and penalties against us in connection
with such shut-in.

Capital Expenditures. Our current working capital constraints have required
us to limit our budgeted capital expenditures during 2002 and 2003. During 2003,
we currently intend to utilize cash flows from operations for the drilling of
one Yegua gas well in the Barber's Hill field in Texas currently budgeted for an
amount of approximately $1.7 million and two Forbes gas wells in Grimes field in
California for a budgeted total of approximately $0.7 million during the first
half of 2003. Additionally, we intend to utilize cash flows from operations to
commence the plugging and abandonment of 7 offshore facilities, totaling
approximately $10.0 million over the next 18 months.

Management's Plan. We do not expect that our cash flows from operation will
be sufficient to finance the payment of principal and interest on the senior
secured notes, our abandonment liabilities and our capital budget. We are
evaluating our alternatives to finance these obligations. The alternatives we
are evaluating include

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

3

We have retained an investment bank to solicit bids for our oil and gas
properties. In addition, we have had extended discussions with holders of our
senior notes regarding a restructuring of the notes. We have also had
discussions with possible investors regarding an investment in our company. None
of these discussions have resulted in an offer or formal proposal.

A restructuring that involves a sale of all or substantially all of our
assets or requires the issuance of certain amounts of equity may require the
approval of Mr. Bowman as a stockholder. We are currently involved in litigation
with Mr. Bowman (see Item 3 - "Legal Proceedings").

Uncertainty regarding the amount and timing of the various alternatives
begin reviewed, as well as current operating losses and our existing capital
deficit, raises substantial doubt about the Company's ability to continue as a
going concern.

OUR BANKRUPTCY AND RECAPITALIZATION

In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35 million in debt outstanding. We incurred approximately another
$63 million in debt in connection with the acquisition. A portion of this debt
was in the form of a short-term, amortizing bank loan. In August 1998, before we
were able to refinance our bank loan, commodity prices began falling, with oil
prices ultimately reaching a 12-year low in December 1998. The resultant
negative effect on our cash flow from the deterioration of commodity prices,
coupled with the required amortization payments on our bank loan, severely
restricted the amount of capital we were able to dedicate to development
drilling. Consequently, our oil and natural gas production declined, further
negatively affecting our cash flow. In October 1998, our short-term loan matured
and we arranged a forbearance agreement providing for interest payments to be
partially capitalized and providing us additional time to refinance our
obligations. In July 1999, the forbearance agreement terminated and we made
negotiated interest payments while attempting to negotiate a restructuring of
our obligations. By March 2000, the aggregate principal balance of our bank debt
had increased as a result of capitalized interest and expenses to approximately
$105 million. In February 2000, the bank declared a default on the loan,
demanded payment of all principal and interest and posted the shares of Tribo
Petroleum Corporation, our parent corporation and a guarantor of the loan, for
foreclosure. As a consequence of the bank's foreclosure action, on March 14,
2000, we chose to seek protection under Chapter 11 of the Bankruptcy Code in
U.S. Bankruptcy Court for the Southern District of Texas, Houston Division.
Tri-Union Operating Company continued to operate outside of bankruptcy.

As a result of the redeployment of funds formerly utilized for amortization
payments, we conducted a limited but highly successful development-drilling
program during the period of the bankruptcy, which resulted in an increase of
our average daily production. This production increase, coupled with improved
commodity prices, allowed us to increase our cash position to approximately
$66.7 million immediately prior to closing of the offering of our senior secured
notes from approximately $1.4 million on March 14, 2000. The senior secured
notes were issued on June 18, 2001 as part of a private unit offering, with each
unit consisting of one note in the principal amount of $1,000 and one share of
class A common stock of our former parent corporation, Tribo Petroleum
Corporation, with which we merged on July 27, 2001. The units were sold to
Jefferies & Company, Inc., as initial purchaser. The initial purchaser sold the
units to qualified institutional buyers in reliance on Rule 144A under the
Securities Act. The proceeds of the offering of the notes and our available cash
balances allowed us to satisfy all creditor claims in full, including interest,
in accordance with the amended plan of reorganization that we filed on May 9,
2001 and to exit bankruptcy on June 18, 2001.

SENIOR SECURED NOTES

The senior secured notes were issued on June 18, 2001 at an original
issuance amount of $130 million under an indenture complying with the Trust
Indenture Act of 1939. U.S. Bank National Association (f/k/a Firstar Bank,
National Association) is the trustee under the indenture. The notes bear
interest at 12.5% per annum, payable semiannually on June 1 and December 1 of
each year. Principal is payable in installments beginning on June 1, 2002, with
final maturity on June 1, 2006. On June 1, 2003, the Company is required to pay
an installment equal to the greater of $20,000,000 or 15.3% of the aggregate
principal balance of the notes. On June 1, 2004, the Company is required to pay
an installment equal to the greater of $15,000,000 or 11.5% of the aggregate
principal balance of the notes. There are limits on the Company's ability to
redeem the notes, including penalties if redeemed prior to June 1, 2005.

Commencing with the quarter ended June 30, 2004, and continuing each
quarter thereafter, the Company is required to offer to apply fifty percent of
its cash flow in excess of $1,000,000 for the quarter to the pro rata redemption
of the notes.

4

The notes are senior secured obligations, secured by a first priority lien
on substantially all of the Company's oil and gas assets, and are
unconditionally guaranteed by the Company's only subsidiary, Tri-Union Operating
Company, which guarantee is secured by a first priority lien on substantially
all of the oil and gas assets of Tri-Union Operating Company. Under the terms of
an Intercreditor Agreement, the liens are held by a collateral agent for the
benefit of hedge counter parties and the holders of the notes. Proceeds from the
sale of collateral upon default are to be applied to the satisfaction of amounts
owing to hedge counter parties under approved hedge agreements before being
applied to interest and principal owing upon the notes.

The indenture contains certain covenants, including covenants that limit
the Company's ability to incur additional debt, to sell or transfer its assets
and covenants that require the board of directors to consist of no fewer than
three individuals, at least 60% of which are required to be independent.
Additionally, the Company is required to hedge its oil and natural gas
production so as to maintain hedged revenue to interest expense ratio of at
least three to one and to maintain a two year rolling hedge program until the
maturity of the notes. The Company is not permitted to hedge more than 80% of
its projected proved developed producing volumes of oil and natural gas, except
under price floor contracts or options, and the Company is not required to enter
into hedges when certain benchmark prices are less than $2.75 per MMBtu or
$18.50 per Bbl.

ITEM 2. PROPERTIES

Our oil and natural gas properties are primarily located in three core
areas of operation: (1) onshore Gulf Coast in Texas; (2) offshore Gulf Coast in
the shallow waters of the Gulf of Mexico; and (3) in the Sacramento Basin of
northern California. All of our oil and natural gas properties are subject to
the lien of the indenture that secures the senior secured notes, as well as
liens imposed by operation of law, such as mechanic's liens and liens for
property taxes not yet due. None of our properties has an attached payment or
performance obligation.

Our onshore Gulf Coast properties accounted for 69.5% of our proved
reserves at December 31, 2002 and 57.2% of our production during 2002. Our
onshore Gulf Coast proved reserves were distributed among 15 fields and
approximately 289 producing wells and a number of undeveloped locations. Most of
our onshore Gulf Coast producing wells have been on production for several years
and their respective production decline rates are relatively slow and well
established. Our working interests in the fields range from 17.5% to 100% with
an average working interest of 87.3%. We operate 14 of our 15 fields in the
onshore Gulf Coast area and 8 of our 14 top value properties are located in the
area. Each of these top value properties is operated by us and, in aggregate,
accounted for 82.9% of the production from the area during 2002 and 89.8% of our
proved reserves in the area at December 31, 2002.

Our offshore Gulf Coast properties accounted for 4.0% of our proved
reserves and 14.3% of our production for the year ended December 31, 2002. Our
offshore Gulf Coast proved reserves were distributed among 13 fields. Our
working interests in the fields range from 5.0% to 100%. We operate 3 of our 13
fields in the area. As indicated under "Recent Developments," these properties
will require material expenditure to abandon wells in the future.

Our California properties accounted for 26.5% of our proved reserves and
28.5% of our production for the year ended December 31, 2002. At December 31,
2002, our proved reserves in the area were distributed among 15 fields. Most of
our producing wells in California benefit from long production histories and
well established decline curves. Additionally, we have benefited from a net
sales price for our natural gas production in this area that has generally
exceeded NYMEX natural gas prices. Our working interests in California range
from approximately 2.5% to 100% with an average working interest of 57%. We
operate 10 of our 15 fields in the area. Three of our 14 top value properties
are located in California. We operate all 3 of these properties, which account
for approximately 78.4% of the production from the area during 2002 and 94.8% of
our proved reserves in the area at December 31, 2002. We conducted a 3-D seismic
survey covering approximately 33 square miles of our leasehold, which was
completed in January 2002. We anticipate that the 3-D seismic survey will
confirm specific locations for previously identified development prospects and
may additionally yield opportunities to drill exploratory wells in our Grimes
and Sutter City fields. Our $0.7 million capital budget for the area during 2003
includes recompletion and low-risk development drilling projects targeting 1.4
Bcfe of proved undeveloped reserves.

The following table and discussion shows our estimated net proved reserves,
PV-10 values, 2002 net production and descriptive information for our three core
areas and the principal properties within each core area. These principal
properties accounted for approximately 90.5% of our net proved reserves at
December 31, 2002. These same properties accounted for 77.1% of our total oil
and natural gas production during 2002. The estimates of reserve values include
future assumed production attributable to future development and plugging and
abandonment activities that the Company does not currently have the ability to
fund. If the Company is unable to obtain additional funds, it may not be able to
develop its oil and natural gas properties as estimated in its December 31, 2002
reserve report. The information set forth below is based on the report of our
independent engineers as described below under "Oil and Natural Gas Reserves."

5

- ----------

(1) Based on our PV-10 Value and proved reserve estimates as of December 31,
2002.

(2) For the twelve months ended December 31, 2002.

Onshore Gulf Coast

Hastings Complex. The Hastings Complex includes three fields, encompasses
approximately 8,800 gross acres and is located approximately 30 miles south of
Houston in Brazoria County, Texas. In March 1998 we acquired working interests
in the three fields ranging from 68.3% to 100%. The fields produce from multiple
Miocene and Frio reservoirs at depths ranging from 2,000 feet to 7,000 feet. At
the time of our acquisition, the fields had produced in excess of 4,351 Bcfe
since discovery in 1934 by Stanolind Oil and Gas Co. Net production from the
field was approximately 9,607 Mcfe per day during 2002.

Since assuming operations in August 1998, we have increased production and
reduced operating expenses in the field. We were able to achieve this with
minimal capital investment by re-engineering the field's artificial lift system,
exploiting behind pipe opportunities and eliminating uneconomic wells. At
December 31, 2002 we had proved reserves of 76,635 MMcfe. During 2003, we intend
to continue our production and cost optimization efforts.

Constitution Field. In March 1998 we acquired our working interests in the
Constitution field, which is located in Jefferson County, Texas. Our working
interests range from 25.0% to 100.0%. The field produces from the Yegua
reservoir at depths ranging from 13,500 feet to 15,011 feet. As of the date we
assumed operations, the net daily production from the field was approximately
339 Mcfe. During 2000 we recompleted our Westbury Farms #1 well to the Yegua
Sand and then fracture stimulated the reservoir. Initial net production after
stimulation was approximately 10,013 Mcfe per day. Our success in the Westbury
Farms #1 resulted in reserve additions from four additional proved undeveloped
locations. Net daily production from the Constitution field during 2002 was 758
Mcfe and at December 31, 2002 we had proved reserves of 6,624 MMcfe.

6

Word Field. The Word field is located in Lavaca County, Texas and produces
from the Lower Wilcox and Edwards Limestone reservoirs at depths from 8,100 feet
to 13,200 feet. In March 1998 we acquired working interests that range from
87.5% to 100.0%. At the time of our acquisition, the field had produced over 47
Bcfe since its discovery in 1944 and was then producing at a net daily rate of
702 Mcfe per day. Net daily production from the field during 2002 averaged 312
Mcfe per day and at December 31, 2002 we had proved reserves of 7,472 MMcfe,
including reserves from one proved behind pipe objective and four proved
undeveloped Edwards locations.

AWP Field. Our interest in the AWP field covers 5,144 acres in McMullen
County, Texas. The field produces from the Olmos and Wales reservoirs at depths
ranging from 5,775 feet to 8,950 feet. In March 1998 we acquired our working
interest in the field, which ranges from 97.2% to 100.0%. At the time of our
acquisition, the field had produced over 430 Bcfe since its discovery in 1981.
Net daily production from our acreage in the field in 2002 averaged
approximately 599 Mcfe and we had proved reserves of 9,732 MMcfe at December 31,
2002, including reserves attributable to eight proved undeveloped Olmos
locations and 10 behind pipe Wales objectives. During recent years, the field
has experienced a resurgence of activity by other operators due to advances in
fracture stimulation technology. Consequently, we believe that significant
low-risk drilling and refracturing opportunities exist on our acreage.

Sour Lake Field. The Sour Lake field, discovered in 1902, is the second
oldest oil field in Texas. It is located 15 miles west of Beaumont, Texas in
Hardin County and produces from the Miocene, Frio and Yegua reservoirs at depths
ranging from 800 feet to 7,577 feet. Our acreage was acquired from Apache in
March 1998. Apache had acquired the acreage from Texaco, who discovered the
field. We own 100% of the working interest and mineral estate in fee under 930
acres in the field. Our largest contiguous lease position in the field, 815
acres, is situated over the structural high and is the field's most prolific
area. Net daily production from the field during 2002 averaged approximately 917
Mcfe and we had proved reserves of 3,169 MMcfe at December 31, 2002, including
reserves attributable to six proved behind pipe objectives and two proved
undeveloped locations.

North Alvin Field. In 1996, as part of the Reunion acquisition, we acquired
working interests ranging from 34.3% to 41.6% in the North Alvin field, located
in Brazoria County, Texas. The field produces from Frio sandstones at depths
ranging from 7,900 feet to 8,600 feet. At the time of our acquisition the field
had produced over 28.4 Bcfe. Net daily production from the field in 2002
averaged approximately 278 Mcfe and we had proved reserves of 1,832 MMcfe at
December 31, 2002. The proved reserves in the field include undeveloped reserves
attributable to four reservoirs that we believe can be accessed by one drilling
well.

South Liberty Field. The South Liberty field is located 35 miles east of
Houston in Liberty County, Texas. We own a 100% working interest in the field.
We acquired our interest in South Liberty in March 1998 and at the time of the
acquisition the field had produced over 632 Bcfe since its discovery in 1925.
The field produces from Miocene, Frio, Yegua and Cook Mountain reservoirs at
depths ranging from 1,500 feet to 11,000 feet. Net daily production from the
field during 2002 averaged approximately 825 Mcfe and we had proved reserves of
5,834 MMcfe at December 31, 2002.

Barber's Hill Field. We acquired our 100% working interest in the Barber's
Hill field in 1998 with the Apache acquisition. To further develop the Yegua
sand reserves in the field, a 3-D seismic program completed in 2001 delineated
one PUD location, offsetting previous Texaco Yegua wells in the field. Net daily
production from the field during 2002 averaged approximately 190 Mcfe and we had
proved reserves of 5,569 MMcfe at December 31, 2002, which included the proved
undeveloped drilling opportunity.

Offshore Gulf Coast

South Timbalier 162 Field. We acquired a 100% working interest in the South
Timbalier 162 Field in 1997. The field was originally developed by Shell Oil and
Amoco during the 1960's. Production has come from over 10 productive reservoirs
ranging from 6,000 feet to 10,000 feet. Net production during 2002 was 414 Mcfe
per day and we have 1,693 Mmcfe of proved reserves at December 31, 2002. We have
three reservoirs with proved behind pipe reserves in two wells currently
shut-in.

South Marsh Island 255 Field. We own a 25% working interest in this Ocean
Energy operated field. We produced 1,684 Mcfe per day during 2002 from this
dually completed well and have 1,601 Mmcfe of proved reserves at December 31,
2002. The reserves include one non-producing plugback in the current wellbore.

7

High Island 537 Field. We own a 100% working interest in this field as a
result of a late 1997 acquisition. We have 2,208 Mmcfe behind-pipe reserves in
two reservoirs in one well in the field.

California

Sutter Buttes Field. Acquired in 1996, our largest contiguous operation in
California is in the Sutter Buttes field in northern California, located
approximately 40 miles north of Sacramento in Sutter and Colusa Counties. Our
working interests range from 53.2% to 100%. The Sutter Buttes field is comprised
of over 43,000 contiguous gross acres of leasehold with approximately 60
producing wells, which we operate. At December 31, 2002 we owned 38,000 net
acres in the field. We have extensive operating expertise in this area and
significant experience with the Forbes and Kione producing reservoirs. From
November 1998 to February 2002, we drilled 13 development wells targeting the
Forbes and Kione reservoirs at depths of 3,100 feet to 7,100 feet. Twelve of the
wells were successful and resulted in significant increases in our production
and cash flow. Our net daily production during 2002 averaged 2,100 Mcfe and our
proved reserves at December 31, 2002 were 26,679 MMcfe. Additionally, we
conducted a 3-D Seismic survey on 15 square miles in the Sutter City Field. The
Sutter City leases have produced exclusively from the shallower Kione sands. The
3-D seismic survey will evaluate the deeper Forbes interval that has been
prolific on our adjacent acreage.

Grimes Field. Our Grimes field, also acquired in 1996, is located to the
southwest of Sutter Buttes and also produces from the Forbes and Kione
sandstones. Our working interests range from 6.3% to 96.0%. Net daily production
during 2002 averaged 2,869 Mcfe and we had proved reserves of 5,843 MMcfe at
December 31, 2002. There has been limited development in the field during recent
years. During 2001 we successfully conducted an 18 square mile 3-D survey over
our acreage in the Grimes field. The 3-D survey indicates we have multiple
development and exploitation drilling opportunities similar to those that we
have completed in the Sutter Buttes area since late 1998. We have 3 PUD
locations in the Grimes field.

Sycamore Field. We acquired our 80% working interest in this field in the
Reunion Acquisition in 1996. Net daily production from the field during 2002
averaged 1,385 Mcfe per day. Plug back activity on existing wells has yielded
significant upside production during 2001 and 2002. We continued our workover
efforts into 2002. Proved reserves in the field are 14,532 Mmcfe at December 31,
2002, which includes 14 PUD locations.

OIL AND NATURAL GAS RESERVES

The following table sets forth information with respect to our estimated
net proved oil and natural gas reserves and the related present values of such
reserves at the dates shown. The reserve and present value data for our existing
properties as of December 31, 2000 was prepared by Huddleston & Co., Inc. and by
DeGolyer and MacNaughton as of December 31, 2001 and 2002.

- ----------

(1) The average prices used in calculating PV-10 Value and Standardized Measure
as of December 31, 2002 were $4.49 per Mcf and $30.09 per Bbl. The SEC does
not permit disclosure of PV-10 Value in financial statements filed with the
SEC.

(2) Represents PV-10 Value adjusted for the effects of future estimated income
tax expense. Income tax expense is computed based on applying the
appropriate statutory tax rate to the excess of future cash inflows less
future production and development costs over the current tax basis of the
properties involved, less applicable carryforwards, for both regular and
alternative minimum tax. Standardized Measure is the measure of future net
cash flows permitted by SEC rules to be included in financial statements
filed with the SEC.

8

(3) Does not include reserve estimates for the Champion #1-H well (see Item 3 -
Legal Proceedings).

Effective February 1, 2001, we gained an incremental 3.3 Bcfe of proved
reserves, estimated at December 31, 2001, in our Hastings Complex due to the
resolution of certain litigation which resulted in an assignment of additional
interests.

Estimated quantities of proved reserves and future net revenues are
affected by oil and natural gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating oil and natural
gas reserves and their values, including many factors beyond the control of the
producer. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers, including those used by us, may
vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities,
prevailing oil and natural gas prices and operating costs. Accordingly, reserve
estimates are often different from the quantities of oil and natural gas that
are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based.

In general, the volume of production from oil and natural gas properties
declines as reserves are depleted. Except to the extent we acquire properties
containing proved reserves or conduct successful exploration and development
activities, or both, our proved reserves will decline as reserves are produced.
Our future oil and natural gas production is, therefore, highly dependent upon
our level of success in finding or acquiring additional reserves. Exploring for,
developing or acquiring new reserves requires substantial amounts of capital. If
the Company is unable to obtain additional funds, it may not be able to develop
its oil and natural gas properties as estimated in the December 31, 2002 reserve
report.

We file reports of our estimated oil and natural gas reserves with the
Department of Energy. The reserves reported to this agency are required to be
reported on a gross operated basis and therefore are not comparable to the
reserve data reported herein.

NET PRODUCTION, UNIT PRICES AND COSTS

The following table sets forth certain information with respect to oil and
natural gas production, prices and costs attributable to all of our oil and
natural gas property interests for the periods shown:

- ----------

(1) Reflects the actual realized prices received, including the results of
hedging activities. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations."

9

PRODUCING WELLS

The following table sets forth the number of productive wells in which we
owned an interest as of December 31, 2002:

Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections and oil
wells awaiting connection to production facilities. Wells that are completed in
more than one producing horizon are counted as one well.

ACREAGE

The following table sets forth our developed and undeveloped gross and net
leasehold acreage as of December 31, 2002:

Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves.

DRILLING ACTIVITIES

The table below sets forth our drilling activity on our properties for the
periods ending December 31, 2000, 2001, and 2002:

OIL AND NATURAL GAS MARKETING AND HEDGING

The revenues generated by our operations are highly dependent upon the
prices of and demand for oil and natural gas. The price we receive for our oil
and natural gas production depends on numerous factors beyond our control.
Historically the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. Prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in the
supply and demand for oil and natural gas, market uncertainty and a variety of
additional factors. These factors include the level of consumer product demand,
weather conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions in the Middle East, the
actions of OPEC, the foreign supply of oil and natural gas and overall economic
conditions. It is impossible to predict future oil and natural gas price
movements with any certainty.

We, from time to time, use SWAP and option contracts to mitigate our
exposure to the volatility of price changes on commodities we produce and sell,
as well as to lock in prices to protect the economics related to certain capital
projects.

10

At December 31, 2002, approximately 80% of our projected oil and natural
gas production from proved developed producing reserves is hedged through
December 31, 2004 at SWAP prices that average $3.62 per Mcf and $22.91 per Bbl,
or a weighted-average natural gas-equivalent price of approximately $3.73 per
Mcfe. Additionally, at December 31, 2002, the Company held 12 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, 2004. These California contracts will settle on the basis
differential between NYMEX and PG&E Citygate. 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. As of March 31, 2003, the Company has oil and natural gas SWAP
contracts in place through February 2005. In March 2002, we terminated certain
of our derivatives contracts for net proceeds of $2,252,971 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 (Henry Hub)
and $18.50 per barrel of crude oil (West Texas Intermediate). As discussed
above, we are evaluating, among other things, the sale of oil and natural gas
properties in order to repay indebtedness under our senior secured notes, fund
our offshore abandonment liabilities and meet our other obligations. In order to
facilitate our ability to sell our properties, we have discontinued our hedging
of production.

The table below sets forth the settlement results of our hedges for the
years ending December 31, 2001 and 2002:

RISKS RELATING TO OUR BUSINESS, FINANCES AND OPERATIONS

Our bankruptcy may adversely affect our ability to conduct our future
operations.

On June 18, 2001, we exited bankruptcy under Chapter 11 of the U.S.
Bankruptcy Code. Our prior bankruptcy may adversely affect the conduct of our
future operations by causing vendors and others from whom we purchase goods or
services to be reluctant to do business with us. These vendors may request
payment in advance, refuse to extend us credit, or give us terms less favorable
than our competitors. We currently do business with certain vendors that require
us to pay in advance for goods or services. These limitations make us more
susceptible to timing differences between our receipt of payment and our
expenditures, which requires us to carefully manage our collections and
disbursements, and may hinder our ability to adjust rapidly to changing market
conditions. In addition, our recourse to bankruptcy protection were we to
require it is limited for the 6 years following the date we filed bankruptcy,
March 14, 2000, unless we waive the benefits of our past discharge.

We are in default of our senior secured notes and we may be unable to refinance
the senior secured notes if the holders were to exercise their rights to demand
the re payment of the entire amount of principal and interest.

We have outstanding $118.1 million of senior secured notes. We are in
default under the indenture for senior notes for violation of a number of
covenants. Because of these defaults, the holders of notes have the right to
accelerate the notes and declare all principal and interest under the notes
immediately due and payable. We do not have sufficient funds or sources of
borrowings to repay the entire amount of the senior notes if the holders were to
accelerate the notes. We are required to make substantial principal payments on
the senior notes in 2003, which we do not currently have the capital resources
to make. We are currently evaluating various alternatives to enable us to meet
our financial obligations, including the senior notes, including sale of oil and
gas properties or production payments, issuances of

11

additional equity or restructuring of the indebtedness. No assurances can be
made that we will be able to effect a transaction with provides that liquidity
we need to meet our obligations to the senior note holders. If we do not meet
our obligations to the senior note holders, they will be able to effect various
remedies, including foreclosing on our oil and gas properties.

We have substantial obligations to plug and abandon our offshore Gulf of Mexico
properties in 2003, 2004 and beyond. Payment of those obligations could be
accelerated if the issuer of our bond to the MMS terminates the bond.

We estimate that our abandonment costs during 2003 and 2004 will be
$5,819,000 and $6,830,000, respectively, and $11,137,000 thereafter. Under
requirements of the U.S. Management and Minerals Service ("MMS"), we have caused
a bond in the amount of $9.5 million to be issued to secure our obligations. The
issuer of the bond has notified us on several occasions that it intends to
cancel the bond. While the issuer of the bond has not cancelled the bond to
date, no assurances can be made that the issuer will not cancel the bond in the
future. If the bond issuer were to cancel the bond, the MMS will have the right,
which we expect they would exercise, to issue a shut-in order, requiring that we
cease production from our off-shore properties we operate. If the MMS issues a
shut-in order, the MMS would take over operation of our operated offshore
facilities, and we would no longer have access to such facilities. The cost
incurred by the MMS to operate our facilities would be required to be paid by
us. In addition, the shut-in of our wells by the MMS will require us to begin
abandonment operations earlier than scheduled, thereby accelerating our
obligation to pay abandonment costs described above. The MMS may also have the
ability to assess fines and penalties against us in connection with such
shut-in.

Our significant leverage and lack of capital resources may affect our ability to
successfully operate and service our senior secured debt obligations, which are
currently in default.

Our level of indebtedness as of December 31, 2002, was $118.1 million and
we are in default under the terms of our senior secured notes. Under the
indenture we are permitted to incur, subject to certain conditions, up to $20.0
million of additional secured debt through the issuance of additional notes and
additional amounts by other means.

Our level of indebtedness and lack of capital resources could have several
important effects on our future operations, which in turn could have important
consequences to you as a holder of the notes, including, without limitation:

o causing us to be unable to satisfy our payments due on the notes, or
other obligations;

o impairing our ability to obtain additional financing for working capital,
capital expenditures or general corporate or other purposes in the future;

o placing us at a competitive disadvantage relative to competitors that
have less indebtedness, by requiring us to dedicate a substantial portion
of our cash flow from operations to payments on our indebtedness and
thereby reducing the availability of our cash flow to fund working capital,
capital expenditures, general corporate expenditures and other purposes;

o impair our ability to satisfy certain plugging and abandonment and
related dismantlement obligations or our ability to maintain the required
levels of surety bonds, pursuant to the requirements of state and federal
regulatory agencies

o causing us to be unable to repurchase, upon a change of control, all of
the outstanding notes, together with any accrued and unpaid interest to the
date of repurchase;

o causing us to be unable to repurchase notes pursuant to an asset sale
offer or an excess cash flow offer; and

o limiting or hindering our ability to adjust rapidly to changing market
conditions, making us more vulnerable in the event of a downturn in general
economic conditions or our business.

Historically, we have financed acquisition, exploration and development
activities primarily through various credit facilities and with internally
generated funds. Our ability to expend the capital necessary to undertake or
complete future activities may be limited and we may not have adequate funds
available to us to carry out our growth strategy. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations,"
beginning on page 24, and our consolidated financial statements and the related
notes thereto.

12

Our estimates of oil and natural gas reserves and future net revenue are
uncertain and inherently imprecise.

This annual report contains estimates of our proved reserves and the
estimated future net revenues from our proved reserves. Estimating oil and
natural gas reserves and their values involves numerous uncertainties, including
many factors beyond our control. Reservoir engineering is a subjective process
of estimating underground accumulations of oil and natural gas, which cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net revenues necessarily depend upon a number
of variable factors and assumptions, including the following:

o historical production from the area compared with production from other
producing areas;

o the assumed effects of regulation by governmental agencies; and

o assumptions concerning future oil and natural gas prices, future
operating costs, severance and excise taxes, development costs and workover
and remedial costs.

Because of the variable factors and assumptions involved in the estimation
of reserves, different engineers or the same engineers at different times may
reach substantially different results in their estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, their classification of reserves based on risk recovery and
their estimates of the future net revenues expected from reserves. In addition,
reserve estimates may be adjusted downward or upward because of changes in such
factors and assumptions.

Because all reserve estimates are subjective to some degree, each of the
following items may differ materially from those assumed in the estimated
reserves:

o the quantities of oil and natural gas that are ultimately recovered;

o the production and operating costs incurred;

o the amount and timing of future development expenditures; and

o future oil and natural gas prices.

The present values of estimated future net revenues referred to in this
annual report should not be construed as the current market value of the
estimated oil and natural gas reserves attributable to our properties. In
accordance with applicable requirements of the SEC, the estimated discounted
future net revenues from proved reserves are generally based on prices and costs
as of the date of the estimate, whereas actual future prices and costs may be
materially higher or lower. Actual future net revenues also will be affected by
factors such as:

o the amount and timing of actual production;

o supply and demand for oil and natural gas;

o curtailments or increases in consumption by natural gas purchasers; and

o changes in governmental regulations or taxation.

The timing of actual future net revenues from proved reserves, and their
actual present value, will be affected by both the timing of the production and
the incurrence of expenses in connection with development and production of oil
and natural gas properties. In addition, the calculation of the present value of
the future net revenues using a 10% discount, as required by the SEC, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with our reserves or the oil and
natural gas industry in general.

Oil and natural gas prices are volatile. A decline in prices could adversely
affect our financial results, cash flows, access to capital and ability to pay
debt.

The price we receive for our oil and natural gas production has a
significant effect on our financial results, profitability, future rate of
growth and the carrying value of our oil and natural gas properties. Prices also
affect the amount of cash flow available to pay debt, to make capital
expenditures and our ability to borrow money or obtain other forms of financing.
Historically, prices for oil and natural gas have been volatile and may continue
to be volatile in the future.

13

Additionally, oil and natural gas prices may vary significantly by geographic
region and have been particularly volatile in California where much of our
natural gas is produced and sold. Wide fluctuations in oil and natural gas
prices may result from relatively minor changes in the supply of and demand for
oil and natural gas, market uncertainty and other factors beyond our control
including:

o worldwide and domestic supplies of oil and natural gas;

o weather conditions;

o the level of consumer demand;

o the price and availability of alternative fuels;

o the availability of pipeline capacity;

o the price and level of foreign imports;

o domestic and foreign governmental regulations and taxes;

o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;

o political instability or armed conflict in oil producing regions; and

o the overall economic environment.

These factors and the volatility of the energy markets generally make it
extremely difficult to predict future oil and natural gas price movements with
any certainty. Declines in oil and natural gas prices would not only reduce
revenue, but could reduce the amount of oil and natural gas that we can produce
economically and, as a result, could adversely effect both our financial
condition and our oil and natural gas reserves. Potential weaknesses in
commodity prices could have a contributing effect to declines in our cash flows,
which, in conjunction with our debt service obligations, have caused us to limit
our capital expenditures. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operation - Liquidity and Capital Resources",
beginning on page 24, and our consolidated financial statements and the related
notes.

Drilling involves numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be encountered.

Our success is significantly affected by risks associated with drilling and
other operational activities. We do not ourselves conduct the actual drilling
operations, but hire drilling companies at standard industry rates. Perhaps the
most significant drilling risk is the risk that no oil or natural gas will be
found that can be produced at a profit. New wells we drill may be unproductive
or we may not be able to recover all or any portion of our investment in wells
drilled. The seismic data and other technologies we may use do not allow us to
know conclusively prior to drilling a well that oil or natural gas is present or
may be produced economically. The cost of drilling, completing and operating a
well is often uncertain, and cost factors can adversely affect the economics of
a project. Our efforts will be unprofitable if we drill dry holes or wells that
are productive but do not produce enough reserves to return a profit after
drilling, operating and other costs. If we are not successful in finding
productive oil and natural gas reservoirs or drilling productive oil and natural
gas wells, or if drilling costs are significantly higher than projected, our
financial results may suffer. Further, drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, including the
following:

o unexpected drilling conditions;

o pressure or irregularities in formations;

o equipment failures or accidents;

o adverse weather conditions;

o compliance with environmental and other governmental requirements;

14

o title problems; and

o costs of, shortages of or delays in the availability or delivery of
equipment or qualified operating personnel.

Hedging transactions may limit our potential profits from operations.

To manage our exposure to price risks in the marketing of our oil and
natural gas production, we have in the past and will be required in the future
under the terms of the indenture, subject to certain conditions, to enter into
oil and natural gas price hedging arrangements with respect to a portion of our
expected production. Our hedging arrangements may include futures contracts on
the NYMEX. Our hedging transactions may limit our potential profits if oil and
natural gas prices were to rise substantially over the price established by the
hedge.

Hedging transactions may expose us to the risk of loss in certain
circumstances, including instances in which:

o our production is materially less than expected;

o there is volatility of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement or
the sales prices for the quality of our oil and natural gas and the sales
price of the quality assumed in the hedge; or

o the counterparties to our future contracts fail to perform the contracts.

If we are unable to adequately replace our reserves, our ability to sustain
production and our long-term financial performance will be adversely impacted.

The volume of production from oil or natural gas properties generally
decreases as more oil and natural gas is produced from a property and reserves
are depleted. The rate at which the decrease occurs depends upon the geologic
characteristics of a particular property. If we do not find new oil and natural
gas production either by our exploration and development efforts or acquisition,
then our proved reserves will decrease as we produce oil and natural gas. Our
future oil and natural gas production rates are therefore highly dependent upon
our level of success in finding, developing or acquiring additional reserves.
Finding, developing or acquiring additional reserves requires significant
capital expenditures. At December 31, 2002, approximately 35% of our total
estimated proved reserves were undeveloped. By their nature, undeveloped
reserves are less certain than developed reserves and recovery of such reserves
will require greater capital expenditures and successful drilling operations. If
we do not make significant capital expenditures, we may not be able to replace
produced reserves.

Historically, we have funded our capital expenditures primarily through
various credit facilities and with internally generated funds. Future cash flows
are subject to a number of variables, such as the level of production from
existing wells, prices of oil and natural gas and our success in developing and
producing new reserves. If revenue were to decrease as a result of lower oil and
natural gas prices or decreased production, and our access to capital were
limited, we would have a reduced ability to replace our reserves. Due to our
limited capital resources and required debt repayment, if revenue were to
decrease as a result of lower oil and natural gas prices or decreased
production, we might not be able to make sufficient capital investments to
replace our oil and natural gas reserves. Even if funds are available, we may
not be able to successfully find, develop or acquire additional oil and natural
gas proved reserves that are economically recoverable.

Our business involves operating hazards and uninsured risks.

Our drilling and production and other operations, and the transportation of
production by others, also involve a number of hazards and risks such as fires,
natural disasters, explosions, blowouts and spills. If any of these risks occur,
we could sustain substantial losses as a result of:

o injury or loss of life;

o severe damage or destruction to property, natural resources and
equipment;

o pollution or other environmental damage;

o clean-up responsibilities;

15

o regulatory investigations and penalties; and

o suspension of operations.

We are not fully insured against some of these risks, either because the
insurance is not available or because of high premium costs. If a significant
accident or other event happens and is not fully covered by insurance, we could
be required to pay some or all of the costs associated with the accident or
event, which may require us to divest resources needed for other purposes. Also,
we cannot predict the continued availability of insurance at premium levels
that, in our sole discretion, justify its purchase.

Our industry is extremely competitive and many of our competitors have superior
resources.

The energy industry is extremely competitive. This is especially true with
regard to exploration for, and development and production of, new sources of oil
and natural gas. As an independent producer of oil and natural gas, we encounter
substantial competition in acquiring properties suitable for exploration, in
contracting for drilling equipment and other services, in marketing oil and
natural gas and in securing trained personnel. We frequently compete against
companies that have substantially larger financial resources, staffs and
facilities. If we directly compete against one of those larger companies in a
desired acquisition of oil and natural gas properties or in the hiring of
experienced and skilled personnel, we may not have the resources available to
obtain the desired result.

We depend heavily on the services of key personnel and the loss of their
services could have an adverse effect on our ability to operate.

We depend to a large extent on the services of James M. Trimble, Jeffrey T.
Janik and Suzanne R. Ambrose. The loss of the services of these key personnel
could impair our ability to manage our business and properties. We do not
currently have employment contracts with these key personnel and do not
currently maintain key man life insurance on their lives. We believe that our
success is also dependent upon our ability to continue to employ and retain
skilled technical personnel.

Higher oil and natural gas prices adversely affect the cost and availability of
drilling and production services.

Higher oil and natural gas prices generally stimulate increased demand and
result in increased prices for drilling rigs, crews and associated supplies,
equipment and services. We have occasionally experienced significantly higher
costs and reduced availability for drilling rigs and other related services.

Our operations are subject to significant government regulation that may change
over time.

Our oil and natural gas operations are subject to various federal, state
and local governmental laws and regulations that may change in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling and abandonment bonds or
other financial responsibility requirements, reports concerning operations, the
spacing of wells, utilization and pooling of properties, taxation and the
environment. From time to time, regulatory agencies have imposed price controls
and production limitations to conserve supplies of oil and natural gas. A
significant portion of our production of natural gas is from our properties in
the Sacramento Basin in California. As a result of the recent energy crises in
California, certain bills are currently being considered by the California
legislature, which could impose civil and criminal penalties on producers of
natural gas or electric power who curtail production or sell energy "at prices
above marginal cost." We cannot determine at this time the effect, if any, that
such legislation, were it enacted, would have on our operations. We are not
aware that any similar legislation is currently proposed by any other state in
which we operate.

In addition, the production, handling, storage, transportation and disposal
of oil and natural gas, their by-products and other substances and wastes
generated, produced or used in connection with oil and natural gas operations
are regulated under federal, state and local laws and regulations relating to
the protection of health and the environment. These laws and regulations may
impose increasingly strict requirements for water and air pollution control,
spill cleanups and solid waste management. Our failure to meet any of the
foregoing requirements could result in a suspension of our operations, as well
as administrative, civil, and even criminal penalties.

We may not be able to profitably sell all of the oil and natural gas we produce.

The marketability of our oil and natural gas production depends upon the
availability and capacity of natural gas gathering systems, pipelines and
processing facilities. If such capacity is not available, we might have to
shut-in

16

producing wells or delay or discontinue development plans for properties. In
addition, federal and state regulation of oil and natural gas production and
transportation, general economic conditions and changes in supply and demand
could adversely affect our ability to produce and market our oil and natural gas
on a profitable basis.

Competition and Markets

Competition is intense in all areas of our operations. Major and
independent oil and natural gas companies and oil and natural gas syndicates
actively bid for desirable oil and natural gas properties, as well as for the
equipment and labor required to operate and develop such properties. Many of our
competitors have financial resources and acquisition, exploration and
development budgets that are substantially greater than ours, which may
adversely affect our ability to compete with these companies. Many of our
competitors have been engaged in the energy business for a much longer time than
us. Such companies may be able to pay more for productive oil and natural gas
properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. Our ability to acquire additional properties and to
discover reserves in the future will depend on our ability to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment.

The market for oil and natural gas produced by us depends on factors beyond
our control, including domestic and foreign political conditions, the overall
level of supply of and demand for oil and natural gas, the price of imports of
oil and natural gas, weather conditions, the price and availability of
alternative fuels, the proximity and capacity of natural gas pipelines and other
transportation facilities and overall economic conditions. The oil and natural
gas industry as a whole also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual consumers.

REGULATION

General. Various aspects of our oil and natural gas operations are subject
to extensive and continually changing regulation, as legislation affecting the
oil and natural gas industry is under constant review for amendment or
expansion. Numerous departments and agencies, both federal and state, are
authorized by statute to issue, and have issued, rules and regulations binding
upon the oil and natural gas industry and its individual members. The Federal
Energy Regulatory Commission ("FERC") regulates the transportation and sale of
natural gas in interstate commerce pursuant to the Natural Gas Act of 1938
("NGA") and the Natural Gas Policy Act of 1978 ("NGPA"). In the past, the
federal government has regulated the prices at which oil and natural gas could
be sold. While sales by producers of natural gas and all sales of crude oil,
condensate and natural gas liquids can currently be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA
in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act"). The Decontrol Act removed all remaining NGA and NGPA price and
nonprice controls affecting wellhead sales of natural gas effective January 1,
1993.

Regulation of Sales and Transportation of Natural Gas. Our sales of natural
gas are affected by the availability, terms and cost of transportation. The
price and terms for access to pipeline transportation are subject to extensive
regulation. In recent years, the FERC has undertaken various initiatives to
increase competition within the natural gas industry. As a result of initiatives
like FERC Order No. 636, issued in April 1992, the interstate natural gas
transportation and marketing system has been substantially restructured to
remove various barriers and practices that historically limited non-pipeline
natural gas sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies and large
industrial and commercial customers. The most significant provisions of Order
No. 636 require that interstate pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all natural gas
supplies. In many instances, the results of Order No. 636 and related
initiatives have been to substantially reduce or eliminate the interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services. While the United States Court of
Appeals upheld most of Order No. 636, certain related FERC orders, including the
individual pipeline restructuring proceedings, are still subject to judicial
review and may be reversed or remanded in whole or in part. While the outcome of
these proceedings cannot be predicted with certainty, we do not believe that we
will be affected materially differently than our competitors.

The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
rate making methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad inquiry into issues facing the natural gas industry to assist
the FERC in establishing regulatory goals and priorities in the post-Order No.
636 environment. Similarly, the Texas Railroad Commission has been

17

reviewing changes to its regulations governing transportation and gathering
services provided by intrastate pipelines and gatherers. While the changes being
considered by these federal and state regulators would affect us only
indirectly, they are intended to further enhance competition in natural gas
markets. We cannot predict what further action the FERC or state regulators will
take on these matters, however, we do not believe that any action taken will
affect us materially differently than other natural gas producers with whom we
compete.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.

Oil Price Controls and Transportation Rates. Our sales of crude oil,
condensate and natural gas liquids are not currently regulated and are made at
market prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market.

Environmental Matters. Extensive federal, state and local laws regulating
the discharge of materials into the environment or otherwise relating to the
protection of the environment affect our oil and natural gas operations.
Numerous governmental departments issue rules and regulations to implement and
enforce such laws, which are often difficult and costly to comply with and which
carry substantial administrative, civil and even criminal penalties for failure
to comply. These laws, rules and regulations may require the acquisition of
certain permits, restrict or prohibit the types, quantities and concentration of
substances that can be released into the environment in connection with drilling
and production, restrict or prohibit drilling activities that could impact
wetlands, endangered or threatened species or other protected natural resources
and impose substantial liabilities for pollution resulting from our operations.
Some laws, rules and regulations relating to protection of the environment may,
in certain circumstances, impose strict liability for environmental
contamination, rendering a person liable for environmental damages and cleanup
costs without regard to negligence or fault on the part of such person. Other
laws, rules and regulations may restrict the rate of oil and natural gas
production below the rate that would otherwise exist. In addition, state laws
often require various forms of remedial action to prevent pollution, such as
closure of inactive pits and plugging of abandoned wells. The regulatory burden
on the oil and natural gas industry increases our cost of doing business and
consequently affects our profitability. We believe that we are in substantial
compliance with current applicable environmental laws, rules and regulations,
that we have no material commitments for capital expenditures to comply with
existing environmental requirements and that continued compliance with existing
requirements will not have a material adverse impact on our operations. However,
environmental laws, rules and regulations have been subject to frequent changes
over the years, and the imposition of more stringent requirements could have a
material adverse effect upon our capital expenditures, earnings or competitive
position as well as those of the oil and gas industry in general.

The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund Law," and analogous state laws impose
liability without regard to fault or the legality of the original conduct on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the current or former owner or operator of the site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Under CERCLA, such persons may be
subject to joint and several liability for the costs of investigating and
cleaning up hazardous substances that have been released into the environment,
for damages to natural resources and for the costs of certain health studies. In
addition, companies that incur liability frequently also confront third party
claims because it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment.

The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and other wastes associated with the
exploration, development or production of oil and natural gas from regulation as
"hazardous waste." Disposal of such non-hazardous oil and natural gas
exploration, development and production wastes usually are regulated by state
law. Other wastes handled at exploration and production sites or generated in
the course of providing well services may not fall within this exclusion.
Moreover, stricter standards for waste handling and disposal may be imposed on
the oil and natural gas industry in the future. From time to time legislation is
proposed in Congress that would revoke or alter the current exclusion of
exploration, development and production wastes from the RCRA definition of
"hazardous wastes" thereby potentially subjecting such wastes to more stringent
handling, disposal and cleanup requirements. State initiatives to further
regulate the disposal of oil and natural gas wastes and naturally occurring
radioactive materials could have a similar impact on us. If such legislation
were enacted it could have a significant impact on our operating costs, as well
as those of the oil and natural gas industry in general. The impact of future
revisions to environmental laws and regulations cannot be predicted.

18

We own or lease, and have in the past owned or leased, properties that have
been used for the exploration and production of oil and natural gas. Although we
have utilized operating and disposal practices that were standard in the
industry at the time, hydrocarbons or other wastes may have been disposed of or
released on or under these properties or on or under other locations where such
wastes have been taken for storage or disposal. In addition, many of these
properties have been operated by third parties whose treatment and release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously released
wastes or property contamination.

The Oil Pollution Act of 1990 ("OPA") and rules and regulations promulgated
pursuant thereto impose a variety of obligations on "responsible parties" with
respect to the prevention of oil spills and liability for damages resulting from
such spills. A "responsible party" includes the owner or operator of an onshore
facility, vessel, or pipeline or the lessee or permittee of the area in which an
offshore facility is located. Under OPA, a person owning or operating a facility
from which there is a discharge or threat of a discharge of oil into navigable
waters or adjoining shorelines is subject to strict joint and several liability
for all containment and cleanup costs and certain other damages, including
natural resource damages. OPA establishes a liability limit for onshore
facilities of $350 million and for offshore facilities, all removal costs plus
$75 million; however, a party cannot take advantage of this liability limit if
the spill is caused by gross negligence or willful misconduct, resulted from a
violation of a federal safety, construction, or operating regulation, or if a
party fails to report a spill or cooperate in the cleanup. Few defenses exist to
the liability imposed by OPA. OPA also imposes ongoing requirements on a
responsible party, including preparation of an oil spill contingency plan and
proof of financial responsibility to cover a substantial portion of
environmental cleanup and restoration costs that could be incurred by
governmental entities in connection with an oil spill. Under OPA and rules
adopted by the Minerals Management Service ("MMS"), responsible parties of
covered offshore facilities that have a worst case oil spill of more than 1,000
barrels must demonstrate financial responsibility in amounts ranging from at
least $10 million in state waters to at least $35 million in Outer Continental
Shelf ("OCS") waters, with higher amounts of up to $150 million in certain
limited circumstances where the MMS believes such a level is justified by the
risks posed by the operations or if the worst case oil spill discharge volume
possible at the facility may exceed applicable threshold volumes specified in
the MMS's rules. We believe that we are in substantial compliance with OPA,
including having appropriate spill contingency plans and certificates of
financial responsibility in place.

The Federal Water Pollution Control Act ("FWPCA") and analogous state laws
impose strict controls regarding the discharge of pollutants, including produced
waters and other oil and natural gas wastes, into state waters or waters of the
United States. The discharge of pollutants into regulated waters is prohibited,
except in accord with the terms of a permit issued by EPA or the state.
Sanctions for unauthorized discharges include administrative, civil and criminal
penalties, as well as injunctive relief. We believe we are in substantial
compliance with applicable FWPCA requirements and that any non-compliance would
not have a material adverse effect on us.

Our operations are also subject to the Clean Air Act ("CAA") and comparable
state and local requirements. Amendments to the CAA were adopted in 1990 and
contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. We may be required to incur certain capital expenditures in the next
several years for air pollution control equipment in connection with obtaining
and maintaining operating permits and approvals for air emissions. However, we
believe our operations will not be materially adversely affected by any such
requirements, and the requirements are not expected to be any more burdensome to
us than to other similarly situated companies involved in oil and natural gas
exploration and production activities.

We maintain insurance against "sudden and accidental" occurrences, which
may cover some, but not all, of the risks described above. The insurance we
maintain may not cover the risks described above. There can be no assurance that
such insurance will continue to be available to cover all such costs or that
such insurance will be available at premium levels that justify its purchase.
The occurrence of a significant event not fully insured or indemnified against
could have a material adverse effect on our financial condition and operations.

Regulation of Oil and Natural Gas Exploration and Production. Our
exploration and production operations are subject to various types of regulation
at the federal, state and local levels. Such regulations include requiring
permits and drilling bonds for the drilling of wells, regulating the location of
wells, the method of drilling and casing wells, and the surface use and
restoration of properties upon which wells are drilled. Many states also have
statutes or regulations addressing conservation matters, including provisions
for the utilization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and natural gas wells and
the regulation of spacing, plugging and abandonment of such wells. Some state
statutes limit the rate at which oil and natural gas can be produced from our
properties.

19

EMPLOYEES

As of March 31, 2003, we had 30 full time salaried employees and
approximately 12 contract employees. None of our employees are subject to a
collective bargaining agreement. In addition to our employees, we may utilize
the services of independent geological, engineering, land and other consultants
from time to time.

TITLE TO PROPERTIES

We have obtained title reports on substantially all of our producing
properties and believe that we have satisfactory title to such properties in
accordance with standards generally accepted in the oil and natural gas
industry. As is customary in the oil and natural gas industry, we perform a
minimal title investigation before acquiring undeveloped properties. We also
obtain title opinions prior to the commencement of drilling operations on such
properties. Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens
which we believe do not materially interfere with the use of or materially
affect the value of such properties.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we are party to litigation or other legal proceedings
that we consider to be a part of the ordinary course of our business. Other than
as set forth below, we are not involved in any legal proceedings nor are we
party to any pending or threatened claims that could reasonably be expected to
have a materially adverse effect on our financial condition, cash flow or
results of operations.

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 (see Item 4 - Submission of Matters to a Vote of
Security Shareholders) 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 primarily 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 gave Bowman and Lovett notice of its intent to vacate the
Lovett offices as of the end of March 2003. Lovett has counterclaimed against
the Company alleging an anticipated 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 agreed to ask the
Court for a trial setting in the Harris County action in January 2004.

20

Bankruptcy filing

On March 14, 2000, we filed a voluntary petition under Chapter 11 of the
U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern
District of Texas, Houston Division. We filed our amended plan of reorganization
in the bankruptcy proceeding on May 9, 2001. Our plan provided for payment in
cash, or segregation of funds for the payment, to each creditor of its full,
allowed claim, including interest, on the closing date of the senior secured
notes. Our plan was confirmed by a court order on May 23, 2001, subject to the
completion of the offering of the old notes. Upon the closing of the offering,
we paid or segregated funds for the payment of all allowed claims in accordance
with our plan and the court order and, except as specifically discussed below,
lawsuits, administrative actions and other proceedings that arose prior to the
confirmation were dismissed as to us. Claims that we dispute will be heard by
the bankruptcy court. If claims are resolved for less than the amount segregated
by us, we will receive the balance of the funds.

Chieftain International

On March 31, 1999, Chieftain International (U.S.), Inc. ("Chieftain") filed
suit against us in the United States District Court for the Eastern District of
Louisiana (the "District Court") alleging that we owed certain joint interest
expenses in the approximate amount of $3.0 million, together with accrued
interest, attorney's fees, and costs, in connection with Chieftain's operation
of two offshore mineral leases. Chieftain took no action with regard to its
lawsuit during our bankruptcy, as the litigation in the District Court was
stayed pursuant to 11 U.S.C. Section 362. Since emerging from bankruptcy,
Chieftain successfully re-opened the litigation in the District Court and has
claimed that we now owe approximately $5.1 million, together with accrued
interest, attorneys' fees, and costs. However, pursuant to our confirmed plan of
reorganization, approximately $5.5 million was segregated in an interest bearing
account pending the trial and/or non-judicial resolution of our dispute with
Chieftain. On April 17, 2002, we entered into an agreement with Chieftain to
stay the litigation for a six-month period in which we conducted an audit of
Chieftain's books and records relating to the litigation and transferred to
Chieftain $5 million of the funds segregated pending the trial and/or
non-judicial resolution of our dispute with Chieftain. Recently, we completed
our joint audit of Chieftain's books and records and set-up an appropriate
framework to fully and finally compromise any and all disputes we have with
Chieftain and the related lawsuit. Formal settlement and release documents are
presently being prepared.

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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II.

ITEM 5. MARKET FOR COMMON STOCK AND RELATED SHAREHOLDER MATTERS

An aggregate of 510,000 shares of our common stock were issued and
outstanding on December 31, 2002, consisting of 445,000 shares of class A common
stock and 65,000 shares of class B common stock. There is no market for our
common stock. We have not paid and have no intention of paying dividends on our
common stock.

The following description of the capital shares does not purport to be
complete or to give full effect to the provisions of statutory or common law and
is subject in all respects to the applicable provisions of our Certificate of
Incorporation.

21

Effective June 15, 2001, the Company was authorized to issue two classes of
common stock, class A and class B. The holders of the common stock are entitled
to one vote for each share on all matters voted upon by shareholders, including
the election of directors. Such holders are not entitled to vote cumulatively
for the election of directors. Holders of a majority of the shares of common
stock entitled to vote in any election of directors may elect all of the
directors standing for election, subject to the rights of holders of class B
common stock described below.

Holders of class A and class B common stock are together entitled to
participate pro rata in such dividends as may be declared in the discretion of
the board of directors out of funds legally available therefore. Holders of
class A and class B common stock together are entitled to share ratably in the
net assets of the Company upon liquidation after payment or provision for all
liabilities and any preferential rights. Holders of common stock have no
preemptive rights to purchase shares of stock of the Company. Shares of common
stock are not subject to any redemption provisions and are not convertible into
any other securities of the Company, except that each share of class B common
stock is convertible into one share of class A common stock under certain
circumstances.

Special Rights of Class B Common Stock

In addition to the rights of the holders of common stock set forth above,
the holders of a majority of the class B common stock, voting together as a
single class, are entitled to designate one person to serve as a non-voting
advisory observer to the Company's board of directors, and further, at any time,
to cause the Company to increase the size of its board of directors and to
immediately elect to the board of directors a number of directors (having full
voting power) nominated by a majority of the holders of the class B common stock
sufficient to constitute a majority of the board of directors. Until there are
no outstanding shares of class B common stock, the board of directors may not
consist of more than seven directors other than those nominated by the holders
of the class B common stock in accordance with the foregoing. Only the holders
of the class B common stock may remove the directors that such holders are
entitled to designate.

In addition to any vote required by law, all matters submitted to a vote of
the Company's shareholders will require the approval of the holders of a
majority of the issued and outstanding shares of class B common stock, voting
separately as a single class. In addition, any amendment to the Company's Bylaws
will require the approval of the holders of the majority of the issued and
outstanding shares of class B common stock.

Changes in Securities

On July 3, 2002, the Company issued 76,667 shares of its class A common
stock, par value $0.01 per share to the holders of its 12.5% senior secured
notes. The issuance of the additional shares of class A common stock resulted in
a change of control with respect to beneficial ownership of our common stock. An
aggregate of 510,000 shares of our common stock were issued and outstanding at
July 3, 2002 consisting of 445,000 shares of class A common stock and 65,000
shares of class B common stock. Of these shares, Richard Bowman, our former
President and Chief Executive Officer, owns 238,333 shares of class A common
stock and no shares of class B common stock, or 47% of our common stock. The
holders of the senior secured notes hold an aggregate of 206,667 shares of class
A common stock and Jefferies & Company, Inc. holds an aggregate of 65,000 shares
of class B common stock, or 53% of our common stock. Prior to the July 3, 2002
issuance of an additional 76,667 shares of class A common stock, Richard Bowman
owned 55% of the issued and outstanding shares of common stock. As a result of
the aforementioned changes in securities and the resulting change in control,
federal tax laws will restrict the Company's ability to utilize its net
operating loss carryforward's. As of March 31, 2003, these shares have not been
registered with the Securities and Exchange Commission.

22

ITEM 6. SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following tables set forth our selected consolidated historical
financial data for the periods shown. The following information should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations," and the consolidated financial statements and
related notes included in this report on Form 10-K.

23

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion of our 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.

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.

GENERAL

We are an independent oil and natural gas company engaged in the
acquisition, development, exploration and production of oil and natural gas
properties in three core areas, onshore Gulf Coast, Gulf of Mexico and the
Sacramento Basin of northern California.

We commenced operations in 1992 and from our inception until mid-1996 we
primarily acquired and developed properties onshore in south and southeast
Texas. We expanded into the Sacramento Basin of northern California with our
acquisition of Reunion in 1996. We established a core area of operation in the
shallow waters of the Gulf of Mexico in 1997 with acquisitions from Apache and
Statoil. In 1998 we expanded our onshore Gulf Coast properties by completing our
largest acquisition to date, the $63.0 million acquisition of onshore Texas oil
and natural gas properties from Apache. We have since focused our efforts and
capital resources on developing our assets.

We have one subsidiary, Tri-Union Operating Company, which is wholly owned
by us. Tri-Union Operating's principal asset is a net profits interest in a
field operated by us representing less than 5% of our consolidated proved
reserves.

In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation with the proceeds from a short-term,
amortizing bank loan. In August 1998, before we were able to refinance our bank
loan, commodity prices began falling, with oil prices ultimately reaching a
12-year low in December 1998. The resultant negative effect on our cash flow
from the deterioration of commodity prices, coupled with the required
amortization payments on our bank loan, severely restricted the amount of
capital we were able to dedicate to development drilling. Consequently, our oil
and natural gas production declined, further negatively affecting our cash flow.
In October 1998, our short-term loan matured and we arranged a forbearance
agreement providing for interest payments to be partially capitalized. In July
1999, this forbearance agreement terminated and we made negotiated interest
payments while attempting to negotiate a restructuring of our obligations.

On March 14, 2000, we chose to seek protection under Chapter 11 of the U.S.
Bankruptcy Code. Tri-Union Operating continued to operate outside of bankruptcy.
On July 18, 2001, we sold in a private unit offering $130,000,000 of senior
secured notes, each unit consisting of one note in the principal amount of
$1,000 and one share of class A common stock of Tribo Petroleum Corporation, our
former parent corporation. The proceeds from the unit offering and our available
cash balances were sufficient to allow us to pay or segregate funds for the
payment of all creditor claims in full, including interest, and to exit
bankruptcy on June 18, 2001.

24

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 mmbl 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 2000, 2001, and 2002 our capital expenditures on oil and gas
activities totaled approximately $10.9 million, $13.6 million and $6.5 million,
respectively. These expenditures related to operations in our three core areas.
In 2000, 75%, or $8.2 million of our capital expenditures were for development
drilling and recompletions. The remaining 25% was primarily incurred on items
such as platform and pipeline improvements that were identified at the time of
our acquisition of the properties, compressor installations and the plugging and
abandonment of an offshore platform. During 2001, 73%, or $9.9 million of our
development capital expenditures were for the recompletion and drilling of 30
projects. The remaining 27%, or $3.7 million of our development capital
expenditures were primarily on the plugging and abandonment of 4 offshore
facilities and the acquisition of 3-D seismic in California. 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.

On July 27, 2001, we were the surviving corporation in a merger with our
parent corporation, Tribo Petroleum Corporation. As a consequence of this
merger, we assumed all of the rights and obligations of Tribo, including those
under the indenture governing the senior secured notes. The financial
information contained herein is the consolidated financial information for
Tribo, our subsidiary and us.

On June 13, 2002, our Chief Executive Officer and President, Richard
Bowman, resigned his positions and was replaced by James M. Trimble, effective
July 19, 2002. Mr. Bowman retains ownership of approximately 47% of the
Company's outstanding common stock.

We use the full cost method of accounting for oil and natural gas property
acquisition, exploitation and development activities. Under this method, all
productive and nonproductive costs incurred in connection with the acquisition
of, exploration for and development of oil and natural gas reserves are
capitalized. Capitalized costs include lease acquisitions, geological and
geophysical work, delay rentals and the costs of drilling, completing and
equipping oil and natural gas wells. Gains or losses are recognized only upon
sales or dispositions of significant amounts of oil and natural gas reserves.
Proceeds from all other sales or dispositions are treated as reductions to
capitalized costs.

RESULTS OF OPERATIONS

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

For the year ended December 31, 2002, our consolidated net loss was
$39,527,353, a $56,021,504 decrease from the consolidated net income of
$16,494,151 for the year ended December 31, 2001.

Oil and Natural Gas Revenues. Oil and natural gas revenues decreased
$42,349,960, or 53%, to $38,166,315 for the year ended December 31, 2002 from
$80,516,275 for the year ended December 31, 2001. The decrease is primarily the
result of a decrease in production volumes and a substantial decrease in the
average price we received for oil and natural gas during the period. Production
volumes decreased 4,956 Mcfe, or 32% to 10,381 Mcfe for the year ended December
31, 2002 from 15,337 Mcfe for the year ended December 31, 2001. The average
price received during 2002 for sales of natural gas was $3.68 per Mcfe, a
decrease of $1.57 per Mcfe, or 30% when compared to an average price received
during 2001 of $5.25 per Mcfe. During the second quarter of 2002, we sold
certain of our Texas Gulf Coast and all of our Louisiana properties. The decline
in production volumes is further attributable to a reduction in production from
our Westbury Farm #1 well in the Constitution field due to two wells drilled on
adjoining acreage, not owned or operated by us, directly offsetting our
production. Further contributing to the production decline are two wells, which
watered-out in our Ord Bend field in California. After watering out, these two
wells were recompleted to two zones at reduced production rates. Additionally,
production from our North Alvin, Spindletop, Sour Lake, South Liberty and

25

Hastings fields experienced abnormal production declines partially due to a
curtailed workover program during the second and third quarters of 2002. The
following table summarizes the consolidated results of oil and natural gas
production and related pricing for the years ended December 31, 2001 and 2002:

Loss on Marketable Securities. Losses on marketable securities were
$556,735 for the year ended December 31, 2001. In satisfaction of certain
related party transactions, we entered into an agreement whereby we transferred
to Atasca certain minor oil and gas properties and trading securities owned by
Tribo Petroleum Corporation. The marketable securities were sold during July
2001 and proceeds in the amount of $102,458 were transferred to Atasca. The sale
of these trading securities resulted in a loss, with the change in fair value
recognized during the period included in earnings.

Gain on Derivatives Contract. In connection with the issuance of the senior
secured notes, we agreed to maintain, subject to certain conditions, on a
monthly basis, a rolling two-year derivatives contract until the maturity of the
notes on approximately 80% of our projected oil and natural gas production from
proved developed producing reserves and the basis differential attributable to
approximately 80% of our projected proved developed producing natural gas
production from our California properties. At December 31, 2001,we had
derivative contracts in place through, December 31, 2003 at estimated net
realized prices that we expect will exceed $3.96 per Mcf and $24.42 per Bbl, or
a weighted natural gas-equivalent price of approximately $4.01 per Mcfe. The
estimated fair value of this derivatives contract at December 31, 2001 resulted
in the recording of a gain on derivatives contract of $12,498,944. Our
production was not hedged at December 31, 2000.

Other Income. Other income increased $752,563 to $780,967 for the year
ended December 31, 2001 from $28,404 for the year ended December 31, 2000. The
increase was primarily the result of the sale of emission reduction credits from
our Hastings Field. The income recognized as a result of the sales of the
emission credits was offset by a loss on the sale of zero coupon U.S. Treasury
Bonds with a 2019 maturity, purchased and held in trust and pledged to the
Minerals Management Service ("MMS") for the plugging and abandonment ("P&A") of
certain wells and the decommissioning of offshore platforms. These zero coupon
U.S. Treasury Bonds were sold to satisfy a re-bonding requirement as stipulated
by the MMS during our bankruptcy. New bonds in the amount of approximately $9.8
million were issued during June 2001 with the cash proceeds from the sale of the
zero coupon U.S. Treasury bonds. These proceeds were deposited into a restricted
interest bearing money market account as collateral for the new P&A performance
bonds.

28

Lease Operating Expenses. Lease operating expenses increased $462,613 or
2%, to $19,947,972 for the year ended December 31, 2001 from $19,485,359 for the
year ended December 31, 2000. Lease operating expense was $1.30 per Mcfe for the
year ended December 31, 2001, an increase of 9% from $1.19 per Mcfe for the year
ended December 31, 2000. The increase was primarily the result of higher
electricity and fuel costs, and the result of MMS required compliance work at
our Matagorda Island A-4 and Brazos 104 facility during the first half of 2001.
The increase in lease operating expense was partially offset as a result of the
sale of our Ship Shoal 58 field in June 2001 and the P&A of the West Cameron
531, South Marsh Island 232 and Brazos 476 wells and platform, where lease
operations have ceased.

Workover Expense. Workover expenses decreased $732,718, or 11%, to
$5,916,356 for the year ended December 31, 2001 from $6,649,074 for the year
ended December 31, 2000. Workover expense was $0.39 per Mcfe for the year ended
December 31, 2001, a decrease of 5% from $0.41 per Mcfe for the year ended
December 31, 2000. During the last half of 2000 and the first half of 2001, an
accelerated workover program was completed which returned several marginal
shut-in wells to production. During the last half of 2001, workover expenses
have returned to a more normal level of expenditure.

Production Taxes. Production taxes decreased $228,180 or 12%, to $1,740,162
for the year ended December 31, 2001 from $1,968,342 for the year ended December
31, 2000. Production taxes were $0.11 per Mcfe for the year ended December 31,
2001, a decrease of 8% from $0.12 per Mcfe for the year ended December 31, 2000.
Production taxes are computed by multiplying produced volumes or revenues by a
tax rate specified by the taxing authority. Decreases in oil and natural gas
volumes during the year ended December 31, 2001 contributed to the decrease in
the amount of production taxes paid during the period.

Depreciation, Depletion and Amortization Expense. DD&A decreased
$1,317,636, or 10%, to $12,188,841 for the year ended December 31, 2001 from
$13,506,477 for the year ended December 31, 2000. DD&A was $0.79 per Mcfe for
the year ended December 31, 2001, a decrease of 5% from $0.83 per Mcfe for the
year ended December 31, 2000. A decrease in oil and natural gas volumes produced
during the year ended December 31, 2001 resulted in a decrease in the amount of
depletion computed on those volumes.

General and Administrative Expense. G&A increased $2,644,186, or 61%, to
$6,972,544 for the year ended December 31, 2001 from $4,328,358 for the year
ended December 31, 2000. G&A was $0.45 per Mcfe for the year ended December 31,
2001, an increase of 67% from $0.27 per Mcfe for the year ended December 31,
2000. The increase was primarily the result of an increase in salary, director
fees and related expenses of $254,460, an increase in legal and audit and tax
service fees of $762,515 and an increase in bad debt expense of $1,562,041.

Interest Expense. Interest expense increased $8,387,094, or 66%, to
$21,144,957 for the year ended December 31, 2001 from $12,757,863 for the year
ended December 31, 2000. The increase was primarily the result of non-cash
amortization of bond discount and deferred loan costs to interest expense of
$3,922,432 and $3,208,149 respectively, for the year ended December 31, 2001.

Reorganization Costs. Tri-Union Development Corporation filed for
bankruptcy protection on March 14, 2000. We incurred reorganization costs of
$21,487,191 for the year ended December 31, 2000 and $8,834,468 for the year
ended December 31, 2001. Reorganization costs primarily included the following:

Rejection of fixed-price physical delivery contract -- The bankruptcy
court approved a motion to reject a fixed-price physical delivery contract.
A claim was filed by the damaged party resulting in a liability of
$17,559,272 (see Note 9). During the years ended December 31, 2000 and
2001, the Company incurred reorganization expenses related to this claim of
$17,559,272 and $737,022, respectively.

Professional fees and other -- The Company was required to hire
certain legal and accounting professionals to help the Company and its
Creditors in its bankruptcy proceedings. These fees were $3,611,760 during
2000 and $3,781,716 during 2001.

Retention costs -- In an effort to maintain certain key employees
through the bankruptcy period, the Company incurred retention bonuses of
$855,000 and $301,740 during the years ended December 31, 2000 and 2001,
respectively. During August 2001, we paid the retention bonus to our
employees.

29

Interest expense - The Company paid interest expense of $2,974,270 as
a result of our emergence from bankruptcy during 2001.

Atasca transaction - As a condition of TDC's plan of reorganization,
the Company agreed to transfer all of the oil and natural gas properties
and certain marketable securities owned by Tribo Petroleum Corporation, as
of May 1, 2001 to its affiliate, Atasca Resources, Inc., at their net book
values of approximately $1,098,000 and $102,000, respectively. In
connection with this transaction, all balances owing to and from the
Company by its affiliates on May 1, 2001 were forgiven. These balances
aggregated to a net receivable from the affiliates of $785,000. As a
consequence of these transactions, the Company recorded a one-time
reorganization expense of $1,985,442 in 2001.

Interest Income -- The Company earned interest income of $538,841 from
March 14, 2000 through December 31, 2000, and $945,722 from January 1, 2001
through June 18, 2001.

Provision for Income Taxes. A $79,000 provision for income tax was made for the
year ended December 31, 2000, primarily as a result of alternative minimum tax
considerations. No provision for federal income tax was required for the year
ended December 31, 2001.

LIQUIDITY AND CAPITAL RESOURCES

In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35.0 million in debt outstanding. We incurred approximately $63.0
million of additional debt in connection with the Apache acquisition. In August
1998, before we were able to refinance our debt, commodity prices began falling,
with oil prices ultimately reaching a 12-year low in December of that year. The
resultant negative effect on our cash flow from the deterioration of commodity
prices, coupled with the required amortization payment on our bank loan,
severely restricted the amount of capital we were able to dedicate to
development drilling. Consequently, our oil and natural gas production declined,
further negatively affecting our cash flow. In October 1998, our loan matured
and we arranged a forbearance agreement providing for interest payments to be
partially capitalized and providing us with additional time to refinance our
obligations. In July 1999, the forbearance agreement terminated and we made
negotiated interest payments while attempting to negotiate a restructuring of
our obligations. By March 2000, the aggregate principal balance of our bank debt
had increased as a result of capitalized interest and expenses to approximately
$105.0 million. In February 2000, the bank declared the loan in default,
demanded payment of all principal and interest and posted the shares of Tribo
Petroleum Corporation, at that time our parent corporation and a guarantor of
the loan, for foreclosure. As a consequence of the bank's actions, on March 14,
2000, we filed for bankruptcy protection. After the filing, we operated as a
"debtor-in-possession," continuing in possession of our estate, the operation of
our business and the management of our properties. Under Chapter 11, certain
claims against us in existence prior to the filing of the petition were stayed
from enforcement or collection. These claims are reflected in full in the
consolidated December 31, 2002 and 2001 balance sheets as "Accounts payable
subject to renegotiation."

After we entered into bankruptcy in March 2000, commodity prices began to
recover, with natural gas prices eventually reaching historically high levels,
particularly in California. During the year ended December 31, 2002, the average
prices we received for natural gas and oil were $3.23 per Mcf and $24.49 per
Bbl.

We filed our amended plan of reorganization in the bankruptcy court on May
9, 2001, which provided for our exit from bankruptcy upon the completion of a
$130.0 million unit offering of senior secured notes and class A common stock.
Our plan was confirmed by a court order entered as of May 23, 2001, subject to
the completion of the offering. On June 18, 2001, the offering closed and we
exited bankruptcy. The proceeds of the offering and our available cash balances
at closing were sufficient to allow us to pay or segregate funds for the payment
of all claims in full, including interest.

During the last two quarters of 2001 and continuing into 2002, commodity
prices again declined. These price declines, coupled with production declines
beginning in the third quarter of 2001, predominately attributable to
unanticipated production declines in two wells, adversely impacted our cash
flows during the latter part of 2001 and continuing into 2002. Commodity price
hedges that we had entered into in connection with the closing of the offering
only partially offset the adverse impact from the decline in commodity prices on
our cash flows.

At December 31, 2002, we had approximately $118.1 million of 12.5% senior
secured notes outstanding. The notes mature on June 1, 2006 and require
amortization payments of the greater of $20.0 million and 15.3% as of June 1,
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, a principal payment in the amount of $20.0 million was made on the
notes reducing the outstanding

30

balance on the notes to $110.0 million. Interest in the amount of $8.1 million
was deferred until July 1, 2002. On July 3, 2002, the Company entered into a
Waiver, Agreement and Supplement (the "Waiver") to the Indenture whereby the
interest was added to the outstanding balance of the notes, bringing the total
amount of outstanding debt to $118.1 million. In addition, the Company issued to
the Noteholders 76,667 shares of Class A common stock, par value $0.01 per
share. The Waiver contained additional covenants, one of which required the
Company to obtain clear title to an oil and gas property subject to lien by no
later than August 2, 2002. Additionally, the Waiver contained additional
covenants, which required the Company to maintain minimum daily production
levels of 28.5 Mmcfe of average daily production and report $4.0 million and
$4.2 million of EBITDA, as adjusted for the non-cash effects of oil and gas
hedging contracts, as of the end of September 30, 2002 and December 31, 2002,
respectively. The Company has been unable to achieve the required daily
production and did not generate the required levels of adjusted EBITDA. 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, an event of default occurred to the Waiver and the original Indenture
whereby the senior secured notes became due on demand. Accordingly, the senior
secured notes and related deferred loan costs have been classified as current in
the accompanying consolidated balance sheet at December 31, 2002.

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, additional SWAP contracts will not be put in place. As a result, the
Company has informed the Indenture Trustee that a default exists pursuant to the
Indenture requirements to maintain a two-year hedge program.

At December 31, 2002, our unrestricted cash balance was $1.5 million, a
$3.2 million decrease from our cash balance at December 31, 2001.

Net cash provided by operating activities after reorganization items
increased $37.4 million to $10.2 million for the year ended December 31, 2002
compared to net cash used by operating activities after reorganization items of
$27.3 million for the year ended December 31, 2001. The increase is primarily
the result of a $52.5 million decrease in net cash used in 2001 to pay accounts
payable subject to renegotiation and accounts payable and accrued liabilities.
The Company reported a net loss of $39.5 million for the year ended December 31,
2002 when compared to net income of $16.5 million for the year ended December
31, 2001. During the year ended December 31, 2002, we recorded a loss on the
mark-to-market value of our derivative contracts of $16.4 million when compared
to income on the mark-to-market value of derivative contracts of $12.5 million
for the year ended December 31, 2001. Additionally, on June 18, 2001, we
deposited $13.5 million into a restricted cash account as required by our plan
of reorganization to satisfy the payment in full of all remaining disputed
pre-petition claims. As of December 31, 2002, $11.9 million of cash deposited
into this restricted account was disbursed to us or to claimants of pre-petition
claims. At December 31, 2002, the balance in the restricted account was $1.6
million. During the year ended December 31, 2001, reorganization cost were $8.8
million when compared to ($0.1) million for the year ended December 31, 2002, or
a decrease of $8.9 million.

Net cash provided by investing activities was $6.8 million during the year
ended December 31, 2002 compared to net cash used in investing activities of
$7.5 million during the year ended December 31, 2001. The increase in net cash
provided by investing activities is primarily the result of the sale of certain
oil and natural gas properties and net realized proceeds in the amount of $10.1
million. Additionally, the Company recognized $2.3 million of proceeds from the
sale of derivative contracts and $1.0 million of cash settlements on derivative
contracts during the year ended December 31, 2002. Additions to oil and natural
gas properties were $6.5 million during the year ended December 31, 2002 when
compared to additions of $13.6 million for the year ended December 31, 2001.

The following table sets forth the investing activities to the Company's
oil and natural gas properties for the years ended December 31, 2000, 2001 and
2002:

Net cash used in financing activities was $20.2 million for the year ended
December 31, 2002 when compared to net cash provided by financing activities of
$6.5 million during the year ended December 31, 2001. The increase in net cash

31

used in financing activities is the result of our payment of $20.0 million of
principal due on June 1, 2002 compared to the payment of loan fees in the amount
of $3.2 million in 2001.

CONTRACTUAL OBLIGATIONS AND CONTINGENT LIABILITIES AND COMMITMENTS

The Company has contractual obligations and commitments primarily with
regard to future payments of principal and interest on the senior secured debt
and lease arrangements. The following table quantifies our future contractual
obligations and commercial commitments as of December 31, 2002:

Our senior secured notes are currently in default. The amount above represents
the current outstanding principal balance and does not include interest, which
accrues at a rate of 12.5%, and any other penalties or fees.

Included in operating lease commitments are amounts for the leased office space
from a Bowman affiliate, Lovett Properties, Ltd. The Company has alleged that
the lease is void and unenforceable (see Item 3 - Legal Proceedings).

CAPITAL REQUIREMENTS

Historically, our principal sources of capital have been cash flow from
operations, short-term reserve-based bank loans, proceeds from asset sales and
the offering of our 12.5% senior secured notes. Our principal uses for capital
have been the acquisition and development of oil and natural gas properties.

On June 1, 2002, the Company was required to make a $28,125,000 payment of
principal and interest on its senior secured notes, and an additional scheduled
interest payment of approximately $7,400,000 on December 1, 2002. In addition,
the Company has a scheduled principal and interest payment of approximately
$27,400,000 due June 1, 2003. The Company made its scheduled principal payment
of $20,000,000 due on June 1, 2002 and its scheduled interest payment of
$7,400,000 on December 1, 2002, but refinanced its scheduled June 1, 2002
interest payment of $8,125,000 into additional promissory notes under the terms
of a Waiver, Agreement and Supplemental Indenture (the "Waiver"). The Waiver
contained additional covenants, one of which required the Company to obtain
clear title to an oil and gas property subject to lien by no later than August
2, 2002. Additionally, the Waiver contained covenants requiring the Company to
maintain average daily production levels of 28.5 Mmcfe per day and to generate
$4.0 million and $4.2 million of EBITDA, as adjusted for the non-cash effects of
oil and gas hedging contracts as of the end of September 30, 2002 and December
31, 2002, respectively. As the Company was unable to obtain clear title by that
date, did not maintain the required production levels, and did not report $4.0
million and $4.2 million of EBITDA, an event of default occurred to the Waiver
and the original Indenture whereby the senior secured notes became due on
demand. Accordingly, the senior secured notes and related deferred loan costs
have been classified as current in the accompanying consolidated balance sheet
at December 31, 2002. While the Company continues to delay certain of its
workover and capital improvement projects in order to maximize available cash to
meet its debt obligations, the foregoing event of default could have a material
adverse impact on the Company's ability to meet its debt and working capital
requirements. Should the noteholders demand payment on the notes, the Company
will not have the ability to generate sufficient resources to satisfy this
obligation. These conditions raise substantial doubt about the Company's ability
to continue as a going concern.

The Company is currently marketing certain of its oil and gas properties in
order to meet these scheduled debt obligations and working capital requirements.
To date, no offers to purchase any of the Company's oil and gas properties have
been received.

To the extent the cash generated from oil and gas property sales and cash
flows from continuing operations are insufficient to meet our scheduled debt
obligations and our projected working capital needs, we will have to raise
additional capital. No assurance can be given that additional funding will be
available, or if available, will be on terms acceptable to us. Uncertainty
regarding the amount and timing of any proceeds from our plans to raise
additional capital raises substantial doubt about our ability to continue as a
going concern. The accompanying consolidated financial statements do not include
any adjustments relating to the recoverability and classification of asset
carrying amounts or the amount and classification of liabilities that might be
necessary should we be unable to continue as a going concern.

32

Recently Issued Accounting Pronouncements

In June 2001, FASB issued Statement of Financial Accounting Standards
("SFAS") No. 141, Business Combinations (SFAS No. 141), and No. 142, Goodwill
and Other Intangible Assets (SFAS No. 142). SFAS 141 requires the use of the
purchase method of accounting and prohibits the use of the pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001.
SFAS No. 141 required the Company to recognize acquired intangible assets apart
from goodwill if the acquired intangible assets meet certain criteria. SFAS No.
141 applies to all business combinations initiated after June 30, 2001, and for
purchase business combinations completed on or after July 1, 2001. SFAS No. 141
also requires upon adoption of SFAS No. 142 that the Company reclassify the
carrying amounts of intangible assets and goodwill based on the criteria in SFAS
No. 141. SFAS No. 142 requires that companies no longer amortize goodwill, but
instead test goodwill for impairment at least annually. In addition, SFAS No.
142 requires that the Company identify reporting units for the purposes of
assessing potential future impairments of goodwill and to reassess the
amortization of intangible assets with an indefinite useful life. An intangible
asset with an indefinite useful life should be tested for impairment in
accordance with SFAS No. 142. SFAS No. 142 is required to be applied in fiscal
years beginning after December 15, 2001 to all goodwill and other intangible
assets recognized at that date, regardless of when those assets were initially
recognized. SFAS No. 142 requires the Company to complete a transitional
goodwill impairment test six months from the date of adoption. The Company is
also required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. The adoption of SFAS No. 141
and SFAS No. 142 did not materially impact the Company's financial position and
results of operations.

In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). SFAS No. 143 amends SFAS No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies, and is applicable
to all companies. SFAS No. 143, which is effective for fiscal years beginning
after June 15, 2002, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal obligations associated
with the retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived asset,
except for certain obligations of lessees. As used in SFAS No. 143, a legal
obligation is an obligation that a party is required to settle as a result of an
existing or enacted law, statue, ordinance, or written or oral contract or by
legal construction of a contract under the doctrine of promissory estoppel. We
will adopt SFAS No. 143 in the first quarter, 2003. The Company is continuing
its assessment of how the adoption of SFAS No. 143 will impact its financial
position and results of operations.

In August 2001, FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-lived Assets ("SFAS No. 144"). SFAS No. 144, which supercedes
SFAS No. 121, Accounting for the Impairment of Long-lived Assets and Long-lived
Assets to be Disposed Of and amends Accounting Research Bulletin No. 51,
Consolidated Financial Statements, addresses financial accounting and reporting
for the impairment or disposal of long-lived assets. SFAS No. 144 is effective
for fiscal years beginning after December 15, 2001, and interim financials
within those fiscal years, with early adoption encouraged. The provisions of
SFAS No. 144 are generally to be applied prospectively. The adoption of SFAS No.
144 did not have a material effect on our financial condition or results of
operations.

In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the current requirement that gains and
losses on debt extinguishment must be classified as extraordinary items in the
income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS No. 145 eliminates an inconsistency in lease accounting by
requiring that modifications of capital leases that result in reclassification
as operating leases be accounted for consistent with sale-leaseback accounting
rules. The statement also contains other nonsubstantive corrections to
authoritative accounting literature. The changes related to debt extinguishment
will be effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for transactions occurring after
May 15, 2002. Adoption of this standard will not have any immediate effect on
our consolidated financial statements. The Company will apply this guidance
prospectively.

On June 20, 2002, FASB's Emerging Issues Task Force (EITF) reached a
partial consensus on Issue No. 02-03, Recognition and Reporting of Gains and
Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities, and No.
00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue
No. 98-10. The EITF concluded that, effective for periods ending after July 15,
2002, mark-to-market gains and losses on energy trading contracts (including
those to be physically settled) must be retroactively presented on a net basis
in earnings. In addition, companies must disclose volumes of physically-settled
energy trading contracts. The Company is evaluating the impact of this new
consensus on the presentation of its consolidated income statement but believes
it will not have a material impact on total revenues and expenses. The consensus
will have no impact on net income.

33

In June 2002, FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally Emerging Issues Task Force (EITF) Issue No. 94-3. The Company will
adopt the provisions of SFAS No. 146 for restructuring activities initiated
after December 31, 2002. SFAS No. 146 requires that the liability for costs
associated with an exit or disposal activity be recognized when the liability is
incurred. Under EITF No. 94-3, a liability for an exit cost is recognized at the
date of a company's commitment to an exit plan. SFAS No. 146 also establishes
that the liability should initially be measured and recorded at fair value.
Accordingly, SFAS No. 146 may affect the timing of recognizing future
restructuring costs as well as the amount recognized. Adoption of this standard
will not have any immediate effect on our consolidated financial statements. The
Company will apply this guidance prospectively.

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 will not have an
effect on our consolidated financial statements.

In January 2003, the FASB issued FASB Interpretation ("FIN") No. 46,
"Consolidation of Variable Interest Entities," and interpretation of Accounting
Research Bulletin No. 51, "Consolidated Financial Statements." FIN No. 46
explains how to identify variable interest entities and how an enterprise
assesses its interest in a variable interest entity to decide whether to
consolidate that entity. This Interpretation requires existing unconsolidated
variable interest entities to be consolidated by their beneficiaries if the
entities do not effectively disperse risks among parties involved. FIN No. 46 is
effective immediately for variable interest entities created after January 31,
2003, and to variable interest entities in which an enterprise obtains an
interest after that date. The Interpretation applies in the first year or
interim period beginning after June 15, 2003, to variable interest entities in
which an enterprise holds a variable interest that is acquired before February
1, 2003. The Company does not expect that the adoption of FIN No. 46 will have a
material effect on its financial position or results of operations.

CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES

The Securities and Exchange Commission recently issued disclosure guidance
for "critical accounting policies." The SEC defines critical accounting policies
as those that require application of management's most difficult, subjective or
complex judgments, often as a result of the need to make estimates about the
effect of matters that are inherently uncertain and may change in subsequent
periods.

Our significant accounting policies are described in Note 3 in the Notes to
Consolidated Financial Statements. Not all of these significant accounting
policies require management to make difficult, subjective or complex judgments
or estimates. However, the following policies could be deemed to be critical
within the SEC definition.

Oil and Natural Gas Interests

Full Cost Method - The Company uses the full cost method of accounting for
exploration and development activities as defined by the SEC. Under this method
of accounting, the costs for unsuccessful, as well as successful, exploration
and development activities are capitalized as properties and equipment. This
includes any internal costs that are directly related to exploration and
development activities but does not include any costs related to production,
general corporate overhead or similar 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

34

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,
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 be reduced. Estimates of future net cash flows from proved reserves of
gas, oil and condensate are made in accordance with SFAS No. 69, "Disclosures
about Oil and Gas Producing Activities."

Derivative Financial Instruments

As a condition of the bond indenture agreement, the company entered into
commodity price SWAP derivative contracts to manage price risk with regard to
80% of its natural gas and crude oil production.

Statement of Accounting Financial Standards No. 133 (SFAS No. 133),
"Accounting for Derivative Instruments and Hedging Activities", as amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB No. 133", and SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
was effective for the Company as of January 1, 2001. SFAS No. 133 requires that
an entity recognize all derivatives as either assets or liabilities measured at
fair value. The accounting for changes in the fair value of a derivative depends
on the use of the derivative. Derivatives that are not hedges must be adjusted
to fair value through income. If the derivative is a hedge, depending on the
nature of the hedge, 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 generally
accepted accounting principles 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. Our significant estimates include the valuation of
deferred tax assets, reserve for doubtful accounts and assumptions underlying
our full cost ceiling test and calculation of depletion, depreciation and
amortization. Actual results may differ from these estimates.

ITEM 7a. QUALITATIVE AND 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.

At December 31, 2002, approximately 80% of our projected oil and natural
gas production from proved developed producing reserves is hedged through
December 31, 2004 at SWAP prices that average $3.62 per Mcf and $22.91 per Bbl,
or a weighted-average natural gas-equivalent price of approximately $3.73 per
Mcfe. 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. In March 2002, we terminated certain of our
derivatives contracts and

35

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
(Henry Hub) and $18.50 per barrel of crude oil (West Texas Intermediate).

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Attached, beginning on F-1, following signature page.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES

None.

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Our directors and principal executive officers are:

James M. Trimble has served as President, Chief Executive Officer and
Director since July 19, 2002. Most recently, he served as President of Elysium
Energy, L.L.C., from July 2000 until the contribution of its properties to a
public oil and gas company in November 2001. Prior to Elysium, Mr. Trimble
served at Cabot Oil & Gas Corporation from May 1983 to May 2000 in several
managerial and senior level executive positions. Before joining Cabot, Mr.
Trimble served as President of Volvo Petroleum, Inc., a Houston based, private
domestic and international exploration and production company. Mr. Trimble
replaced Mr. Dutt as our Chairman of the Board effective February 26, 2003.

Suzanne R. Ambrose has served with us since November 1998 when she joined
us as an accounting consultant. In February 2000, Ms. Ambrose became our Vice
President, Accounting. In June 2001, Ms. Ambrose became our Vice President,
Treasurer and Chief Accounting Officer. In November 2001, Ms. Ambrose became our
Vice President, Treasurer and Chief Financial Officer. Prior to joining us, Ms.
Ambrose provided accounting advice and services, on a contract basis, to WRT
Energy, Inc., an oil and natural gas exploration and production company, from
May 1996 to November 1998, and HLS Offshore, L.L.C., an oil field services
company, from January 1998 through May 1998. Ms. Ambrose served as controller of
Offshore Petroleum Divers, Inc., a wholly-owned subsidiary of Offshore Pipeline,
Inc., an oil field services company, from March 1989 through November 1995.

Jeffery T. Janik has served with us since June 1998 when he joined us as
Operations Manager. In June 2001, Mr. Janik became our Vice President,
Operations. Prior to joining us, Mr. Janik served as Vice President of
Operations at Baker-MO Services, Inc., an oil and gas service contractor from
April 1993 to June 1998.

G. Bryan Dutt founded Ironman Energy Capital, L.P., a private investment
limited partnership, in 1999 and serves as its Managing Partner. Mr. Dutt served
as managing partner of Centennial Energy Partners; a private investment limited
partnership, from 1995 to 1999. From 1985 to 1995, he was an energy analyst at
Howard, Weil, Labouisse, Friedrichs Inc., an energy investment banking firm. He
is a past president of the New Orleans Financial Analyst. Mr. Dutt served as our
Chairman of the Board from June 13, 2002 until February 26, 2003 when Mr.
Trimble was appointed Chairman.

David L. Ducote has served as President of Tchoupitoulas Partners, a real
estate acquisition and development company since 1993, and Fulcrum Capital, a
merchant bank and vehicle for private investments since 1998. Additionally,
since 1993, Mr. Ducote has served as the Chairman of Park One Holdings; a
company, which owns, manages and operates structured parking facilities. Prior
to assuming his current positions, Mr. Ducote was associated with the investment
banking firm of Howard, Weil, Labouisse, Friedrichs, Inc.

36

Donald W. Riegle, Jr. served in the U.S. Senate from 1976 through 1994 and
in the U.S. House of Representatives from 1967 through 1975. He served on the
Senate Banking Committee for eighteen years and as its chairman from 1989 to
1994. In March 2001, Mr. Riegle became Chairman of Government Relations for APCO
Worldwide, a global public affairs and strategic communications firm
headquartered in Washington, D.C. In January 1995, following his retirement from
the Senate, Mr. Riegle joined Shandwick International, a public relations and
public affairs firm, and component of the Interpublic Group of Companies, where
he served until March 2001 as Chairman of Government Relations. Mr. Riegle
currently serves on the board of Anthem, Inc., which is listed on the New York
Stock Exchange.

Oliver G. Richard III served as Chairman, President and Chief Executive
Officer of Columbia Energy Group from April 1995 until its acquisition in
November 2000. From November 2000 to present, Mr. Richard has been engaged in
private investment activities. Mr. Richard was appointed to the Federal Energy
Regulatory Commission by President Ronald Reagan and served from 1982 to 1985.
While at the FERC, he was instrumental in forging initiatives to increase
competition and efficiencies among federally regulated energy providers.

MANAGEMENT OF TRI-UNION OPERATING COMPANY

The principal executive officers of Tri-Union Operating Company are the
same as the principal executive officers of Tri-Union Development Corporation.
The sole director of Tri-Union Operating is James M. Trimble.

ITEM 11. DIRECTOR AND EXECUTIVE COMPENSATION

DIRECTOR COMPENSATION

We compensate each director $75,000 per year and reimburse reasonable out
of pocket expenses incurred in connection with attending board meetings.

EXECUTIVE COMPENSATION

The following table sets forth certain information for fiscal years 2000,
2001 and 2002 with respect to the compensation paid to Mr. Trimble, our Chief
Executive Officer and our other executive officers that received annual
compensation (including salary and bonuses earned) that exceeded $100,000 for
those years. Tri-Union's compensation committee of the Board of Directors
determines the compensation of our executive officers.

- ----------

(1) Amount includes automobiles furnished by us and premium payments we made
for health and life insurance policies for the referenced individuals.

(2) Amount includes employment on a contract basis until February 2000.

(3) We had no stock option plans during 2000, 2001 or 2002.

37

(4) Resigned effective September 2001.

(5) Resigned effective June 13, 2002.

RETENTION BONUSES

To provide an incentive for our executive officers and key employees
through the pendency of our bankruptcy, we incurred retention bonuses of
$855,000 and $301,740 during the years ended December 31, 2000 and 2001,
respectively. Following the closing of the original offering and our exit from
bankruptcy those funds were distributed to 67 persons as bonuses, including
$100,000 to R. Kelly Plato, $110,000 to Jeffrey T. Janik and $100,000 to Suzanne
Ambrose. No additional retention bonuses were paid to our employees during 2002.

EMPLOYMENT AGREEMENTS WITH EXECUTIVE OFFICERS

We do not currently have employment agreements with our executive officers.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

An aggregate of 510,000 shares of our common stock were issued and
outstanding on December 31, 2002, consisting of 445,000 shares of class A common
stock and 65,000 shares of class B common stock. Of these shares, Richard
Bowman, owns 238,333 shares of class A common stock (or 47% of our common
stock), the purchasers of units in the original offering own an aggregate of
206,667 shares of class A common stock (or 40% of our common stock) and
Jefferies & Company, Inc. owns 65,000 shares of class B common stock (or 13% of
our common stock).

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

We historically have had a series of informal relationships with Richard
Bowman and his affiliated companies, including advances to Richard Bowman, for
travel and other business expenses. On June 13, 2002, our former Chief Executive
Officer and President, Richard Bowman, resigned his positions and was replaced
by James M. Trimble, effective July 19, 2002. Mr. Bowman retains ownership of
approximately 47% of the Company's outstanding common stock. All informal
related party relationships were severed with Mr. Bowman.

OFFICE LEASE

Effective April 1, 2001, we relocated our executive offices to 530 Lovett
Boulevard, Houston, Texas, in a building owned by an affiliate, Tribo Production
Co. Ltd. ("TPL"), and subsequently assigned to Lovett Properties, Ltd.
("Lovett"), both of which are beneficially owned by Richard Bowman, our former
President, Chief Executive Officer and director. We occupy the entire building,
which has approximately 9,355 square feet of office space. We currently occupy
this space at a base rental of $26,000 per month. The base rental is subject to
adjustment for changes in the consumer price index during the term of the lease.
Pursuant to the lease, we are responsible for certain expenses associated with
the building, including property taxes, insurance, maintenance and utilities.
The lease expires on March 31, 2006. The lease contains five one-year renewal
options at the then prevailing market rental rate, which may be exercised upon
six months notice to our landlord. The Company has given Bowman and Lovett
notice of its intent to vacate the Lovett offices as of the end of March 2003.
Lovett has counterclaimed against the Company alleging an anticipated 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. As a result of the Company's decision to vacate the Lovett
offices, net capitalized leasehold improvements in the amount of $331,144 will
be expensed during the first quarter of 2003.

Effective April 1, 2003, the Company has entered into a rental agreement
with Blue Dolphin Services Company, a company for which our Chairman, Chief
Executive Officer and President is currently serving on the board of directors,
whereby we will sub-lease approximately 5,237 square feet of office space in
Houston, Texas for a term of approximately 46 months. Our monthly rental rate
will range from $5,892 for months one through five to $6,546 per month for the
remaining term of the lease.

38

CERTAIN TRANSACTIONS WITH ATASCA RESOURCES, INC.

We have historically provided general and administrative services, such as
accounting, landman and engineering services to Atasca Resources, Inc.
("Atasca"), an entity owned and controlled by Richard Bowman. During 2000, we
commissioned an independent peer group analysis of companies similar to Atasca
in order to determine market levels for such services. Based upon this analysis
and the actual services performed, we allocated certain general and
administrative expenses to Atasca. For the year ended December 31, 2001 and
2002, we received reimbursements totaling $60,000 and $30,000, respectively from
Atasca for these services. We discontinued providing general and administrative
services for Atasca effective July 31, 2002.

In addition, during 2001 and continuing until Tribo's properties were
assigned to Atasca and we merged with Tribo, a small number of Tribo's oil and
natural gas properties were operated by Atasca. Tribo paid Atasca for ordinary
and customary lease operating expense incurred in connection with the operation
of these properties. During the year ended December 31, 2001, we received oil
and natural gas revenues of $155,490 and incurred production and overhead
expenses of $104,739. During the year ended December 31, 2002, we received oil
and natural gas revenues of $1,404 and incurred production and overhead expenses
of $2,652.

CASH ADVANCES WITH AFFILIATED ENTITIES

Historically, we have made cash advances to, and have received cash
advances from, Atasca, Tribo Production Co., Ltd., BL Production Co., Ltd., and
Atasca Properties, Ltd.; entities that are beneficially owned or controlled by
Richard Bowman. The advances were made primarily for insurance, oilfield
services and related activities and reimbursement of corporate expenses. Cash
advanced from these affiliates was $292,221 for the year ended December 31,
2001, and $252,211 for the year ended December 31, 2002, reducing the net
balance owed to us from these entities to a receivable from affiliate in the
amount of $72,496 at December 31, 2001 and payable to affiliate in the amount of
$103,217 at December 31, 2002. On June 18, 2001, all net amounts due from Mr.
Bowman and entities owned by him were forgiven as partial consideration for the
assignment by Mr. Bowman of his interest in a $3.3 million litigation settlement
with Credit Lyonnais as more fully described in the "Satisfaction of Certain
Related Party Obligations" section.

OTHER TRANSACTIONS WITH RICHARD BOWMAN

The total amount owed to us by Mr. Bowman for travel and other business
expenses was $133,670 and $427,331 at December 31, 2001 and 2002, respectively.
The receivable from Mr. Bowman in the amount of $427,331 is combined with the
payable to affiliate in the amount of $103,217, resulting in a net amount owed
us in the amount of $324,114. A provision for doubtful account in the amount of
$324,114 has been recorded at December 31, 2002 pending the resolution of
certain legal proceedings (see Item 3 - Legal Proceedings). These advances were
non-interest bearing and due on demand. On June 18, 2001, accumulated amounts
due from Mr. Bowman and entities owned by him were forgiven as partial
consideration for the assignment by Mr. Bowman of his interest in a $3.3 million
litigation settlement with Credit Lyonnais as more fully described in the
"Satisfaction of Certain Related Party Obligations" section.

SATISFACTION OF CERTAIN RELATED PARTY OBLIGATIONS

As noted in "Business and Properties -- Legal Proceedings," Richard Bowman
agreed to assign his interest in a $3.3 million litigation settlement with
Credit Lyonnais to us. Mr. Bowman agreed to assign this interest to us in return
for our transfer to Atasca of certain oil and natural gas properties (totaling
approximately 1.2 Bcfe, or 0.7% of our proved reserves, as of December 31, 2000)
at their book value of approximately $1.1 million and certain marketable
securities owned by Tribo Petroleum Corporation and the forgiveness of net
obligations owed to us by Mr. Bowman. Additionally, we released Tribo Production
Company, Ltd., BL Production Co., Ltd., and Atasca Properties, Ltd., (all wholly
owned by Mr. Bowman) from the net obligations they each owed to us. In July
2001, we merged with Tribo Petroleum Corporation. After giving effect to these
transactions, all balances owing to and from these related parties and us were
satisfied. As a consequence of these transactions, we recorded a one-time
reorganization expense of $1,985,442. The following table summarizes the oil and
gas properties and marketable securities transferred to Atasca, the net balances
owing to us by Mr. Bowman, Atasca Resources, Inc., and all other companies
controlled by Mr. Bowman that we forgave in this transaction.

39

Assets transferred and receivables forgiven by TDC
Oil and gas properties transferred to Atasca .................................... $ 1,097,611
Marketable securities transferred to Atasca ..................................... 102,454
Richard Bowman .................................................................. 581,975
Due from Tribo Production Co., Ltd. ............................................. 491,878
Due from Atasca Resources, Inc. ................................................. 109,796
Due from BL Production, LLC ..................................................... 55,844
------------
Total ......................................................... $ 2,439,558
============

Liabilities of TDC cancelled
Due to Tribo Production Co., Ltd. ............................................... $ 2,388
Due to Atasca Resources, Inc. ................................................... 396,742
Due to Atasca Properties, Ltd. .................................................. 16,885
Due to BL Production, LLC ....................................................... 23,458
Due to Atasca Properties, Ltd. .................................................. 14,643
------------
Total Liabilities Cancelled ................................... 454,116
------------
Net Assets Transferred and Receivables Forgiven ............... $ 1,985,442
============

PART IV.

ITEM 14. CONTROLS AND PROCEDURES

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 annual 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.

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.

40

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

* 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.

41

GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in
the oil and natural gas industry that are used in this annual report. All
volumes of natural gas referred to herein are stated at the legal pressure base
to the state or area where the reserves exit and at 60 degrees Fahrenheit and in
most instances are rounded to the nearest major multiple.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume of oil,
condensate or natural gas liquids.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet of natural gas equivalent determined using the
ratio of six Mcf of natural gas to one Bbl of oil condensate or natural gas
liquids.

Behind pipe. Oil and natural gas in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of oil and natural gas from another formation penetrated by the well
bore.

Boe. Barrel of oil equivalent, determined using the ratio of one Bbl of
crude oil, condensate or natural gas liquids to six Mcf of natural gas.

Completion. The installation of permanent equipment for the production of
oil and natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

Development. The drilling and bringing into production of wells in addition
to the exploratory or discovery well on a lease.

Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.

Dry hole or well. A well found to be incapable of producing oil or natural
gas in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.

Exploration. The search for oil and natural gas. Exploration operations
include: aerial surveys, geophysical surveys, geological studies, core testing,
and the drilling of test wells (wildcat wells).

Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be,
in which working interests are owned.

Horizontal drilling. A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of oil and natural gas.

MBbls. One thousand barrels of oil.

MBoe. One thousand barrels of oil equivalent determined using the ratio of
one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.

Mcf. One thousand cubic feet of natural gas.

Mcfd. One thousand cubic feet of natural gas per day.

Mcfe. One thousand cubic feet equivalent determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

42

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMcf. One million cubic feet.

MMcfe. One million cubic feet of natural gas equivalent determined using
the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.

MMS. The Minerals Management Service.

Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Plugback. A workover procedure that converts a well from a deeper
non-producing zone to a shallower producing zone.

Present value and PV-10 Value. When used with respect to oil and natural
gas reserves, represents the estimated future net revenue to be generated from
the production of proved reserves, determined in all material respects in
accordance with the rules and regulations of the SEC (generally using prices and
costs in effect as of the date indicated) without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
future income tax expenses or to depreciation, depletion and amortization,
discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing oil or
natural gas in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production.

Proved developed reserves. Proved reserves that are expected to be
recovered from existing wellbores, whether or not currently producing, without
drilling additional wells. Production of such reserves may require a
recompletion.

Proved reserves. The estimated quantities of crude oil, natural gas, and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.

Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage.

Recompletion. The completion for production of an existing wellbore in
another formation from that in, which the well has been previously completed.

Reserve life. A ratio determined by dividing proved reserves by production
from such reserves for the prior 12-month period.

Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reserves.

Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.

Standardized Measure. The estimated future net revenue, including the
effects of estimated future income tax expense, to be generated from the
production of proved reserves, determined in all material respects in accordance
with

43

the rules and regulations of the SEC (generally using prices and costs in effect
as of the date indicated) without giving effect to non-property related expenses
such as general and administrative expenses and debt service or to depreciation,
depletion and amortization, discounted using an annual discount rate of 10%.

Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.

Wellbore. The hole made by the drill bit.

Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.

Workover. Operations on a producing well to restore or increase production.

44

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf the undersigned, thereunto duly authorized.

TRI-UNION DEVELOPMENT CORPORATION

By: /s/ JAMES M. TRIMBLE 3/31/03
- ----------------------------------------------- --------------------
James M. Trimble Date
Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dated indicated.

By: /s/ SUZANNE R. AMBROSE 3/31/03
- ----------------------------------------------- --------------------
Suzanne R. Ambrose Date
Vice President, Treasurer and Chief
Financial Officer

By: /s/ G. BRYAN DUTT 3/31/03
- ----------------------------------------------- --------------------
G. Bryan Dutt Date
Director

By: /s/ DAVID L. DUCOTE 3/31/03
- ----------------------------------------------- --------------------
David L. Ducote Date
Director

By: /s/ DONALD W. RIEGLE, JR. 3/31/03
- ----------------------------------------------- --------------------
Donald W. Riegle, Jr. Date
Director

By: /s/ OLIVER G. RICHARD III 3/31/03
- ----------------------------------------------- --------------------
Oliver G. Richard III Date
Director

45

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 annual report on Form 10-K of Tri-Union
Development Corporation;

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual 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 annual 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
annual 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 annual report (the "Evaluation Date"); and

c) presented in this annual 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 annual 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: March 31, 2003
-----------------------------------------

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

46

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 annual report on Form 10-K of Tri-Union
Development Corporation;

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual 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 annual 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:

b) 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
annual report is being prepared;

c) 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 annual report (the "Evaluation Date"); and

d) presented in this annual 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 annual 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: March 31, 2003
------------------------------------------

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

47

INDEX TO AUDITED FINANCIAL STATEMENTS

TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Public Accountants ............................................ F-2
Consolidated Balance Sheets as of December 31, 2001 and 2002 ........................ F-3
Consolidated Statements of Operations and Comprehensive Income (Loss) for
the Years Ended December 31, 2000, 2001 and 2002 ................................. F-4
Consolidated Statements of Stockholders' Equity (Capital Deficit) for the Years
Ended December 31, 2000, 2001 and 2002 ........................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31,
2000, 2001 and 2002 .............................................................. F-6
Notes to Consolidated Financial Statements .......................................... F-8

F-1

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors
Tri-Union Development Corporation (formerly Tribo Petroleum Corporation)
Houston, Texas

We have audited the accompanying consolidated balance sheets of Tri-Union
Development Corporation (formerly Tribo Petroleum Corporation) and subsidiary as
of December 31, 2001 and 2002, and the related consolidated statements of
operations and comprehensive income (loss), stockholders' equity (capital
deficit) and cash flows for each of the three years in the period ended December
31, 2002. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Tri-Union
Development Corporation and subsidiary at December 31, 2001 and 2002, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. As discussed in Note
2 to the consolidated financial statements, the Company incurred a net loss of
$39.5 million in 2002, and at December 31, 2002 had a capital deficit of $27.1
million and a working capital deficit of $107.9 million, and is in default of
its senior secured notes. These factors raise substantial doubt about the
Company's ability to continue as a going concern. Management's plans in regard
to these matters are also described in Note 2. The consolidated financial
statements do not include any adjustments that might result from the outcome of
these uncertainties.

BDO SEIDMAN, LLP

Houston, Texas
March 14, 2003

F-2

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

F-3

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

See accompanying notes to consolidated financial statements.

F-4

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (CAPITAL DEFICIT)

See accompanying notes to consolidated financial statements.

F-5

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

See accompanying notes to consolidated financial statements.

F-6

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

Supplemental disclosures of cash flow information:
Interest paid during the period ............................................ $ 4,039,520 $ 24,805,447 $ 7,439,049
Income taxes paid .......................................................... -- 79,000 --
Non-cash transactions:
Transfer of long-term debt to pre-petition liabilities subject to
compromise .............................................................. 104,700,000 -- --
Discount on unit offering .................................................. -- (24,750,000) --
Issuance of Class A and B common stock in conjunction with units offering .. -- 28,600,000 --
Transfer of oil and natural gas properties to affiliate .................... -- 1,097,611 --
Reorganization costs accrued in accounts payable and accrued liabilities ... 1,914,753 967,505 865,155
Reorganization costs accrued in pre-petition liabilities subject to
compromise .............................................................. 17,794,272 -- --
Purchase of derivative contracts as other long-term liability .............. -- -- 1,797,942
Issuance of Class A common stock in conjunction with refinancing of
senior secured notes .................................................... -- -- 850,000
Conversion of accrued interest payable to senior secured debt .............. -- -- 8,125,000

See accompanying notes to consolidated financial statements.

F-7

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- BASIS OF PRESENTATION

Basis of Presentation

Tri-Union Development Corporation ("New TDC") formerly Tribo Petroleum
Corporation ("Tribo") was incorporated in the state of Texas in September 1992.
New TDC and its subsidiary ("the Company") is an independent oil and natural gas
company engaged in the acquisition, operation and development of oil and natural
gas properties primarily in areas of Texas, 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 New TDC 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, New TDC had an additional wholly owned subsidiary
Tri-Union Development Corporation ("TDC"). In July 2001, New TDC and TDC merged
and the surviving corporation was New TDC. Accordingly, the assets, liabilities
and operations of TDC are included with those of New TDC for all periods
presented in the financial statements.

NOTE 2 -- GOING CONCERN UNCERTAINTIES AND MANAGEMENT'S PLANS TO RESOLVE THE
GOING CONCERN UNCERTAINTIES

As discussed in Note 8, a sequence of events occurred in the second and
third quarters of 2002, as a result of which the Company became in default of
its senior secured notes and the notes became due on demand. Accordingly, the
senior secured notes and related deferred loan costs have been classified as
current in the accompanying consolidated balance sheet at December 31, 2002.
While the Company continues to delay certain of its workover and capital
improvement projects in order to maximize available cash to meet its debt
obligations, the foregoing event of default could have a material adverse impact
on the Company's ability to meet working capital requirements and repay its
indebtedness. Should the noteholders demand payment on the notes, the Company
will not have the ability to generate sufficient resources to satisfy this
obligation. Additionally, in 2002, the Company incurred a net loss of $39.5
million and at December 31, 2002 has a capital deficit of $27.1 million and a
working capital deficit of $107.9 million. 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 issuing 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 extended discussions with holders
of our 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 have 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 (see Note 11 - "Commitments and
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 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

F-8

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

Use of Estimates

The accompanying financial statements are prepared in conformity with
accounting principles generally accepted in the United States of America which
require management to make estimates and assumptions that effect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Significant assumptions are
required in the valuation of proved oil and natural gas reserves, which as
described herein may affect the amount at which oil and natural gas properties
are recorded. Actual results could differ materially from these estimates.

Restricted Cash and Bonds

The Company had restricted cash balances at December 31, 2001 and 2002 of
$683,813 and $721,952, respectively. These restricted cash balances are pledged
for regulatory operating deposits and performance bonds.

Until July 2001, the Company held zero coupon U.S. Treasury Bonds with a
2019 maturity value of $12,250,000, held in trust and pledged as collateral for
bonds issued to the Minerals Management Service ("MMS") for the plugging and
abandonment of certain wells and the decommissioning of offshore platforms.
During July 2001, the Company was required to replace its pledged collateral and
issue $9,850,000 of new bonds to the MMS. The zero U.S. Treasury Bonds were sold
for $4,248,048 and cash in the amount of $4,500,000 was deposited into a
restricted interest bearing money market account as collateral for the new
bonds. At December 31, 2001 and 2002, the restricted money market account had a
balance of $4,542,019 and $4,618,135, respectively.

Oil and Natural Gas Interests

The Company follows the full cost method of accounting for oil and natural
gas property acquisition, exploration 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
for each cost center 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.

Internal costs, including salaries, benefits and other internal salary
related costs, which can be directly identified with acquisition, exploration or
development activities are capitalized while any costs related to production,
general corporate overhead, or similar activities are charged to expense.
Geological and geophysical costs not directly associated with a specific
unevaluated property are included in the amortization base as incurred.
Capitalized internal costs directly identified with the Company's acquisition,
exploration and development activities amounted to approximately $767,000,
$856,000 and $1,202,000 in 2000, 2001 and 2002, respectively. Internal costs
included in capitalized oil and gas properties amounted to approximately
$3,067,000 and $4,269,000 at December 31, 2001 and 2002, respectively.

The capitalized costs of oil and natural gas properties, plus estimated
future development costs relating to proved reserves and estimated costs of
plugging and abandonment, net of estimated salvage value, are amortized on the
unit-of-production method based on total proved reserves. The computation of
depreciation, depletion and amortization ("DD&A") takes into consideration
restoration, dismantlement and abandonment costs and the anticipated proceeds
from equipment salvage. The estimated restoration, dismantlement and abandonment
costs for onshore properties are expected to be offset by the estimated salvage
value of lease and well equipment. As of December 31, 2001 and 2002 the Company
has recorded an offshore abandonment liability of $3,383,000 and $4,455,000,
respectively, based on total expected abandonment costs of approximately
$12,238,000 and $23,786,000, respectively. This liability is included in
accumulated DD&A on the consolidated balance sheets. For the years ended
December 31, 2000, 2001 and 2002, the Company recorded accretion of its offshore
abandonment liability of $1,083,000, $709,000, and $1,072,000, respectively.
This accretion is recorded as a component of DD&A expense in the consolidated
statements of operations.

F-9

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

The costs of unproved properties are excluded from amortization until the
properties are evaluated, subject to an annual assessment of whether impairment
has occurred. In determining whether impairment of unevaluated properties has
occurred, management evaluates, among other factors, current oil and natural gas
industry conditions, capital availability, primary lease terms of the
properties, holding periods of the properties, and available geological and
geophysical data. Any impairment assessed is added to the costs being amortized.
Costs of drilling exploratory dry holes are included in the amortization base
immediately upon determination that a well is dry. At December 31, 2002, all of
the Company's oil and gas properties were classified as evaluated and are
included in the amortization base. The Company's proved oil and natural gas
reserves were estimated by an independent petroleum engineering firm.

The capitalized oil and natural gas property costs, less accumulated
depreciation, depletion and amortization and related deferred income taxes, if
any, are generally limited to an amount (the ceiling limitation) equal to the
sum of (a) the present value of estimated future net revenues computed by
applying current prices in effect as of the balance sheet date (with
consideration of price changes only to the extent provided by contractual
arrangements) to estimated future production of proved oil and natural gas
reserves, less estimated future expenditures (based on current costs) to be
incurred in developing and producing the reserves using a discount factor of 10%
and assuming continuation of existing economic conditions; and (b) the cost of
investments in unevaluated properties excluded from the costs being amortized.
No ceiling write down was recorded in 2000, 2001 or 2002.

General and administrative expenses are reported net of amounts allocated
to working interest owners of the oil and natural gas properties operated by the
Company, net of amounts charged for administrative and overhead costs and net of
amounts capitalized pursuant to the full cost method of accounting.

Furniture, Fixtures and Equipment

Furniture, fixtures and equipment are carried at cost. Depreciation is
provided on the straight-line basis using estimated useful lives of three to ten
years. At the time of a retirement or sale, the related cost and accumulated
depreciation are removed from the accounts, and any resulting gain or loss is
recorded to income. Maintenance and repairs are charged to expense as incurred.
Renewals, betterments and expenditures that increase the value of the property
or extend its useful life, are capitalized.

Cash Equivalents

The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.

Allowance for Doubtful Accounts

Accounts receivable are customer obligations due under normal trade terms.
We sell our production to companies involved in the transportation and refining
of oil and natural gas. We perform continuing credit evaluations of our
customers' financial condition and although we generally do not require
collateral, letters of credit may be required from our customers in certain
circumstances.

Senior management reviews accounts receivable on a monthly basis to
determine if any receivables will potentially be uncollectible. We include any
accounts receivable balances that are determined to be uncollectible, along with
a general reserve, in our overall allowance for doubtful accounts. After all
attempts to collect a receivable have failed, the receivable is written off
against the allowance. Based on the information available to us, we believe our
allowance for doubtful accounts as of December 31, 2002 is adequate. However,
actual write-offs might exceed the recorded allowance.

Financial Instruments and Concentration of Credit Risk

Financial instruments that subject the Company to credit risk consist of
accounts receivable. The receivables are primarily from companies in the oil and
natural gas industry or from individual oil and natural gas investors. During
2000, 2001 and 2002, the Company had revenues from certain customers exceeding
10% of total revenues as follows:

F-10

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

In the case of receivables from joint interest owners, the Company may have
the ability to offset amounts due against the participant's share of production
from the related property.

The estimated fair value of financial instruments has been determined by
the Company using available market information and appropriate valuation
methodologies. The fair value of these instruments approximates their carrying
value at December 31, 2001 and 2002.

Income Taxes

The Company accounts for income taxes using the "liability method."
Accordingly, deferred tax liabilities or assets are determined based on
temporary differences between the financial statement and income tax bases of
assets and liabilities using enacted tax rates in effect for the year in which
the differences are expected to reverse. The effect of a change in tax rates is
recognized in income in the period such change occurs. A valuation allowance is
provided for deferred tax assets to the extent realization is not judged to be
more likely than not.

Environmental Matters

Environmental costs are expensed or capitalized depending on their future
economic benefit. Costs that relate to an existing condition caused by past
operations and have no future economic benefit are expensed. Liabilities for
future expenditures of a noncapital nature are recorded when future
environmental expenditures and/or remediation is deemed probable, and the costs
can be reasonably estimated. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.

Derivative Transactions

Statement of Financial Accounting 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 are adjusted to fair
value through income. If the derivative is a hedge, depending on the nature of
the hedge, changes in the fair value of derivatives are either 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 is immediately recognized in earnings. At December 31, 2002, the
Company had maintained a rolling two-year combination of commodity price SWAP
and price floor agreements in order to manage the price risk associated with a
portion of its projected production. These derivative transactions were not
designated for hedge accounting under SFAS No. 133 and, accordingly, changes in
the estimated value of derivative contracts held at the balance sheet date are
recognized in the statement of operations as non-cash gains or losses on
derivative contracts. Conversely, cash settlements realized from the Company's
derivative contracts are included in oil and natural gas revenues in the
accompanying consolidated statements of operations. At December 31, 2002, the
estimated fair value of the Company's derivative contracts held represents a net
current liability of $3,379,875 and a net non-current liability of $1,912,722.
During the year ended December 31, 2002, net cash settlements realized from the
Company's derivative contracts amounted to a net payment of $1,047,454.

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

F-11

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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, the
Company has informed the Indenture Trustee that a default exists pursuant to the
Indenture requirements to maintain a two-year hedge program.

Earnings (Loss) Per Share

Basic earnings per share includes no dilution and is computed by dividing
income available to common stockholders by the weighted average number of common
shares outstanding for the period. Diluted earnings per share reflects the
potential dilution of securities that could share in the earnings of an entity.
The Company had no potentially dilutive securities for the years ended December
31, 2000, 2001 or 2002.

Comprehensive Income (Loss)

The Company has elected to report comprehensive income (loss) in a
consolidated statement of operations and comprehensive income (loss).
Comprehensive income (loss) is comprised of net income (loss) and all changes to
stockholders' equity, except those due to investments by stockholders, changes
in paid-in capital and distributions to stockholders, and is presented net of
income taxes.

Reclassifications

Certain reclassifications have been made to the 2000 and 2001 balances to
conform to the 2002 presentation.

Recently Issued Accounting Pronouncements

In June 2001, FASB issued Statement of Financial Accounting Standards
("SFAS") No. 141, Business Combinations (SFAS No. 141), and No. 142, Goodwill
and Other Intangible Assets (SFAS No. 142). SFAS 141 requires the use of the
purchase method of accounting and prohibits the use of the pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001.
SFAS No. 141 required the Company to recognize acquired intangible assets apart
from goodwill if the acquired intangible assets meet certain criteria. SFAS No.
141 applies to all business combinations initiated after June 30, 2001, and for
purchase business combinations completed on or after July 1, 2001. SFAS No. 141
also requires upon adoption of SFAS No. 142 that the Company reclassify the
carrying amounts of intangible assets and goodwill based on the criteria in SFAS
No. 141. SFAS No. 142 requires that companies no longer amortize goodwill, but
instead test goodwill for impairment at least annually. In addition, SFAS No.
142 requires that the Company identify reporting units for the purposes of
assessing potential future impairments of goodwill and to reassess the
amortization of intangible assets with an indefinite useful life. An intangible
asset with an indefinite useful life should be tested for impairment in
accordance with SFAS No. 142. SFAS No. 142 is required to be applied in fiscal
years beginning after December 15, 2001 to all goodwill and other intangible
assets recognized at that date, regardless of when those assets were initially
recognized. SFAS No. 142 requires the Company to complete a transitional
goodwill impairment test six months from the date of adoption. The Company is
also required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. The adoption of SFAS No. 141
and SFAS No. 142 in 2002 did not materially impact the Company's financial
position and results of operations.

In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). SFAS No. 143 amends SFAS No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies, and is applicable
to all companies. SFAS No. 143, which is effective for fiscal years beginning
after June 15, 2002, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal obligations associated
with the retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived asset,
except for certain obligations of lessees. As used in SFAS No. 143, a legal
obligation is an obligation that a party is required to settle as a result of an
existing or enacted law, statue, ordinance, or written or oral contract or by
legal construction of a contract under the doctrine of promissory estoppel. The
Company will adopt SFAS No. 143 in the first quarter of 2003. The Company is
continuing its assessment of how the adoption of SFAS No. 143 will impact its
financial position and results of operations.

F-12

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

In August 2001, FASB issued SFAS No. 144, Accounting for the Impairment or
Disposal of Long-lived Assets ("SFAS No. 144"). SFAS No. 144, which supercedes
SFAS No. 121, Accounting for the Impairment of Long-lived Assets and Long-lived
Assets to be Disposed Of and amends Accounting Research Bulletin No. 51,
Consolidated Financial Statements, addresses financial accounting and reporting
for the impairment or disposal of long-lived assets. SFAS No. 144 is effective
for fiscal years beginning after December 15, 2001, and interim financials
within those fiscal years, with early adoption encouraged. The provisions of
SFAS No. 144 are generally to be applied prospectively. The 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, FASB issued SFAS No. 145, Rescission of FASB Statements No.
4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
This statement eliminates the current requirement that gains and losses on debt
extinguishment must be classified as extraordinary items in the income
statement. Instead, such gains and losses will be classified as extraordinary
items only if they are deemed to be unusual and infrequent, in accordance with
the current GAAP criteria for extraordinary classification. In addition, SFAS
No. 145 eliminates an inconsistency in lease accounting by requiring that
modifications of capital leases that result in reclassification as operating
leases be accounted for consistent with sale-leaseback accounting rules. The
statement also contains other nonsubstantive corrections to authoritative
accounting literature. The changes related to debt extinguishment will be
effective for fiscal years beginning after May 15, 2002, and the changes related
to lease accounting will be effective for transactions occurring after May 15,
2002. Adoption of this standard will not have any immediate effect on our
consolidated financial statements. The Company will apply this guidance
prospectively.

On June 20, 2002, FASB's Emerging Issues Task Force (EITF) reached a
partial consensus on Issue No. 02-03, Recognition and Reporting of Gains and
Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities, and No.
00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue
No. 98-10. The EITF concluded that, effective for periods ending after July 15,
2002, mark-to-market gains and losses on energy trading contracts (including
those to be physically settled) must be retroactively presented on a net basis
in earnings. In addition, companies must disclose volumes of physically-settled
energy trading contracts. The Company is evaluating the impact of this new
consensus on the presentation of its consolidated income statement but believes
it will not have a material impact on total revenues and expenses. The consensus
will have no impact on our results of operations.

In June 2002, FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally Emerging Issues Task Force (EITF) Issue No. 94-3. The Company will
adopt the provisions of SFAS No. 146 for 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. Adoption of this standard will
not have any immediate effect on our consolidated financial statements. The
Company will apply this guidance prospectively.

In November 2002, the Financial Accounting Standards Board (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 will not have an
effect on its consolidated financial statements.

F-13

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

In January 2003, 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. Apart from our wholly owned subsidiary, whose results are currently
consolidated in the accompanying financial statements, the Company does not
currently believe that any other entities will be consolidated as a result of
FIN 46.

NOTE 4 -- EMERGENCE FROM BANKRUPTCY

During February 2000, the Company defaulted under the terms of a $105
million Acquisition Facility with a bank, and the bank demanded payment of all
principle and interest. On March 14, 2000, TDC (the "Debtor") sought protection
under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for
the Southern District of Texas, Houston Division ("Bankruptcy Court").

All payments made from TDC to TOC, TPC or any related party during the
Bankruptcy was required to be approved by the Bankruptcy Court.

Reorganization Costs -- As a result of TDC filing for protection under
Chapter 11 of the U.S. Bankruptcy Code, the Company incurred certain
reorganization costs (benefits) during the years ended December 31, 2000, 2001
and 2002 totaling $21,487,191, $8,834,468 and ($77,100), respectively which
include the following:

Rejection of fixed-price physical delivery contract -- The bankruptcy
court approved a motion to reject a fixed-price physical delivery contract.
A claim was filed by the damaged party resulting in a liability of
$17,559,272 (see Note 9). During the years ended December 31, 2000 and
2001, the Company incurred reorganization expenses related to this claim of
$17,559,272 and $737,022, respectively.

Professional fees and other -- The Company was required to hire
certain legal and accounting professionals to help the Company and its
Creditors in its bankruptcy proceedings. These fees were $3,611,760 during
2000, $3,781,716 during 2001 and $106,352 during 2002.

Retention costs -- In an effort to maintain certain key employees
through the bankruptcy period, the Company incurred retention bonuses of
$855,000 and $301,740 during the years ended December 31, 2000 and 2001,
respectively. During August 2001, we paid the retention bonus to our
employees.

Interest expense - The Company paid interest expense of $2,974,270
during the year ended December 31, 2001as a result of our emergence from
bankruptcy.

Atasca transaction - As a condition of TDC's plan of reorganization,
the Company agreed to transfer all of the oil and natural gas properties
and certain marketable securities owned by Tribo Petroleum Corporation, as
of May 1, 2001 to its affiliate, Atasca Resources, Inc., at their net book
values of approximately $1,098,000 and $102,000, respectively. In
connection with this transaction, all balances owing to and from the
Company by its affiliates on May 1, 2001 were forgiven. These balances
aggregated to a net receivable from the affiliates of $785,000. As a
consequence of these transactions, the Company recorded a one-time
reorganization expense of approximately $1,985,000 in 2001.

Interest Income -- The Company earned interest income of $538,841 from
March 14, 2000 through December 31, 2000, and $945,722 from January 1, 2001
through June 18, 2001. During the year ended December 31, 2002, interest
income in the amount of $183,452, which had previously been deferred for
the potential future settlement of pre-petition claims, was recognized into
interest income.

On May 23, 2001, TDC's plan of reorganization was confirmed by the
bankruptcy court. In accordance with this plan, the Company paid all
pre-petition liabilities in full. In addition, as part of the confirmation of
the plan, TDC's largest creditor agreed to a $3,300,000 reduction of their claim
in settlement of a lawsuit originally brought by the Company and its chief
executive officer. The chief executive officer assigned his interest in the
settlement to the Company in exchange for certain assets, which are further
described in the "Atasca transaction" above (see Note 6).

F-14

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 5 -- ALLOWANCE FOR DOUBTFUL ACCOUNTS

The activity of the allowance for doubtful accounts on trade and affiliate
receivables for the year ended December 31, were as follows:

NOTE 6 -- RELATED PARTY TRANSACTIONS

Balances owed by/(to) affiliated companies were comprised of the following
at December 31:

Atasca Resources, Inc. and the Other Affiliates referred to above are all
owned by the Company's largest shareholder and former chief executive officer
(prior to June 18, 2001, the Company's former Chief Executive Officer was its
sole shareholder). With the Company's issuance of class A and B common stock on
June 18, 2001 (see note 12), the Company's former Chief Executive Officer's
shareholdings were effectively reduced to 55%. On July 3, 2002, the Company
issued 76,667 shares of class A common stock to the holders of its senior
secured notes. The issuance of these shares reduced the Company's former Chief
Executive Officer's shareholdings to approximately 47%.

The net amounts receivable from affiliates are recorded in the accompanying
consolidated balance sheets as Receivables from Affiliates. The amounts due to
or from affiliates have no established repayment terms and no interest is
charged. A provision for doubtful accounts in the amount of $324,114 has been
recorded at December 31, 2002 pending the resolution of Bowman related legal
proceedings.

The receivables and payables with Atasca Resources, Inc. primarily relate
to cash advances, transfers, reimbursement of corporate expenses, oil and gas
sales, production expenses, and related activities. In addition, Atasca
Resources, Inc. paid the Company a management fee of $60,000, $60,000 and
$30,000 in 2000, 2001 and 2002, respectively.

Effective April 1, 2001, the Company entered into a month-to-month lease
agreement with a related party, Tribo Production Company, Ltd., which was
subsequently assigned to Lovett Properties, Ltd. ("Lovett"), both of which are
beneficially owned by Richard Bowman, for the lease of its current office
facilities. In June 2001, the lease was amended to a five-year commitment with
terms that require the Company to pay rent of $26,000 per month. The Company has
given Bowman and Lovett notice of its intent to vacate the Lovett offices as of
the end of March 2003 (see Note 11). As a result of the Company's decision to
vacate the Lovett offices, net capitalized leasehold improvements in the amount
of $331,144 will be expensed during the first quarter of 2003.

The receivable from the Company's largest shareholder and former chief
executive officer principally relates to cash and travel advances and other
business and entertainment expenses.

The receivables from Atasca Resources, Inc. and other affiliates of the
Company are primarily for cash advances.

F-15

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

The Company earned revenues and incurred production expenses through Atasca
Resources, Inc. for the years ended December 31, as follows:

As a condition of TDC's plan of reorganization, the Company agreed to
transfer all of the oil and natural gas properties and certain marketable
securities owned by Tribo Petroleum Corporation, as of May 1, 2001 to its
affiliate, Atasca Resources, Inc., at their net book values of approximately
$1,098,000 and $102,000, respectively. Revenues from the oil and natural gas
properties totaled $1,777,649 for the year ended December 31, 2000 and $778,606
for the period from January 1 through May 1, 2001. In connection with this
transaction, all balances owing to and from the Company by its affiliates on May
1, 2001 were forgiven. These balances aggregated to a net receivable from the
affiliates of $785,000. As a consequence of these transactions, the Company
recorded a one-time reorganization expense of approximately $1,985,000 in 2001.

NOTE 7 -- OIL AND NATURAL GAS PROPERTIES

The following table sets forth information concerning the Company's oil and
natural gas properties at December 31:

At December 31, 2001 and 2002, all of the Company's oil and gas properties
were evaluated and, accordingly, were included in the amortization base.

During 2002, the Company sold certain of its oil and natural gas properties
for net cash proceeds for approximately $10,100,000. Consistent with the
Company's policy of accounting for its oil and natural gas properties using the
full cost method, the sales price was credited to oil and natural gas properties
with no corresponding gain or loss recorded as a result of the sale
transactions. Among those properties sold was the Company's interest in the
Scott, Clear Branch and Rayne Fields in Louisiana for $ net proceeds of
5,800,000.

During the second quarter of 2002, the Company participated in the
successful drilling and completion of the Champion #1-H well in Grimes County,
Texas. The well was brought into production during the second quarter of 2002
for a net cost of $2,578,895. Currently, the title to this well is in dispute
(see Note 11). As a result, the net cost to drill and complete the well is shown
on the accompanying balance sheet as other assets at December 31, 2002, pending
resolution of the title dispute.

NOTE 8 -- SENIOR SECURED NOTES AND UNIT OFFERING

On June 18, 2001, the Company completed a unit offering of (1) $130 Million
of 12.5% senior secured notes due 2006 ("Notes") and (2) 130,000 shares of class
A common stock of New TDC. Each unit consisted of a Note in the principal amount
of $1,000 and one share of class A common stock. The Notes are guaranteed by TOC
(see Note 14).

Notes

The Notes mature on June 1, 2006 and require amortization payments of the
greater of $20 million and 15.3% as of June 1, 2002 and 2003 and an amortization
payment of the greater of $15 million and 11.5% of the aggregate principal
balance of the notes as of June 1, 2004. A final amortization payment of
$75,000,000 is due June 1, 2006. Interest is payable semi-annually on June 1 and
December 1 of each year.

F-16

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

The Notes were issued at a 5.5% discount from their face amount resulting
in an aggregate discount of $7,150,000 that is being amortized as additional
interest expense over the term of the Notes. The 5.5% discount, together with
the value of the class A common stock issued in the offering which was also
accounted for as bond discount, the allocated value of the class B common stock,
and other offering costs aggregating a total of $45,016,000 (see below), make
the effective interest rate on the Notes 21.9%.

At any time prior to June 1, 2003, New TDC may redeem in the aggregate up
to 30% of the then outstanding aggregate principal amount of the Notes with the
Net Cash Proceeds of one or more equity offerings at a redemption price of
112.5% of the Notes, together with accrued and unpaid interest to the redemption
date.

Commencing with the quarter ended June 30, 2004, and continuing each
quarter thereafter, the Company is required to offer to apply fifty percent of
its cash flow in excess of $1,000,000 for the quarter to the pro rata redemption
of the notes.

The notes are senior secured obligations, secured by a first priority lien
on substantially all of the Company's oil and gas assets, and are
unconditionally guaranteed by the Company's only subsidiary, TOC, whereby the
guarantee is secured by a first priority lien on substantially all of the oil
and gas assets of TOC. Under the terms of an Intercreditor Agreement, the liens
are held by a collateral agent for the benefit of hedge counter parties and the
holders of the notes. Proceeds from the sale of collateral upon default are to
be applied to the satisfaction of amounts owing to hedge counter parties under
approved hedge agreements before being applied to interest and principal owing
upon the notes.

The indenture contains certain covenants, including covenants that limit
the Company's ability to incur additional debt, to sell or transfer its assets
and covenants that require the board of directors to consist of no fewer than
three individuals, at least 60% of which are required to be independent.
Additionally, the Company is required to hedge its oil and natural gas
production so as to maintain hedged revenue to interest expense ratio of at
least three to one. The Company is not permitted to hedge more than 80% of its
projected proved developed producing volumes of oil and natural gas, except
under price floor contracts or options, and the Company is not required to enter
into hedges when certain benchmark prices are less than $2.75 per MMBtu or
$18.50 per Bbl.

On June 1, 2002, the Company was required to make a $28,125,000 payment of
principal and interest on its senior secured notes, and an additional scheduled
interest payment of approximately $7,400,000 on December 1, 2002. In addition,
the Company has a scheduled principal and interest payment of approximately
$27,400,000 due June 1, 2003. The Company made its scheduled principal payment
of $20,000,000 due on June 1, 2002 and its scheduled interest payment of
$7,400,000 on December 1, 2002, but refinanced its scheduled June 1, 2002
interest payment of $8,125,000 into additional promissory notes under the terms
of a Waiver, Agreement and Supplemental Indenture (the "Waiver"). The Waiver
contained additional covenants, one of which required the Company to obtain
clear title to an oil and gas property subject to lien by no later than August
2, 2002 (see Note 7). Additionally, the Waiver contained covenants requiring the
Company to maintain average daily production levels of 28.5 Mmcfe per day and to
generate $4.0 million and $4.2 million of EBITDA, as adjusted for the non-cash
effects of oil and gas hedging contracts as of the end of September 30, 2002 and
December 31, 2002, respectively. As the Company was unable to obtain clear title
to the subject property by August 2, 2002, did not maintain the required
production levels, and did not meet the required EBITDA thresholds, an event of
default occurred to the Waiver and the original Indenture whereby the senior
secured notes became due on demand. Accordingly, the senior secured notes and
related deferred loan costs have been classified as current in the accompanying
consolidated balance sheet at December 31, 2002.

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, additional SWAP contracts will not be put in place. As a result, the
Company has informed the Indenture Trustee that a default exists pursuant to the
Indenture requirements to maintain a two-year hedge program.

Class A Common Stock

On June 18, 2001, the Company issued 130,000 shares of class A common stock
with an estimated fair value of $17.6 million. This amount was allocated to the
value of the class A common stock from the total proceeds received by

F-17

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

the Company in the unit offering, thereby creating an additional bond discount
which is being amortized to interest expense over the life of the bonds using
the effective interest method.

On July 3, 2002, the Company issued 76,667 shares of its class A common
stock, par value $0.01 per share to the holders of its 12.5% senior secured
notes in consideration for the Waiver described above. These shares had an
estimated fair value of $850,000 and this value was considered to be additional
loan costs of the senior secured notes as refinanced in June 2002. The issuance
of the additional shares of class A common stock resulted in a change of control
with respect to beneficial ownership of our common stock. An aggregate of
510,000 shares of our common stock were issued and outstanding at July 3, 2002
consisting of 445,000 shares of class A common stock and 65,000 shares of class
B common stock. Of these shares, Richard Bowman, our former President and Chief
Executive Officer, owns 238,333 shares of class A common stock and no shares of
class B common stock, or 47% of our common stock. The holders of the senior
secured notes hold an aggregate of 206,667 shares of class A common stock and
Jefferies & Company, Inc. holds an aggregate of 65,000 shares of class B common
stock, or a combined 53% of our common stock. Prior to the July 3, 2002 issuance
of an additional 76,667 shares of class A common stock, Richard Bowman owned 55%
of the issued and outstanding shares of common stock. As a result of the
aforementioned changes in securities and the resulting change in control,
federal tax laws may restrict the Company's ability to utilize its net operating
loss carryforward's.

Class B Common Stock

On June 18, 2001, the Company issued 65,000 shares of class B common stock
to the initial purchaser of the Notes. These shares had an estimated fair value
of $11,000,000 and this value was considered to be offering costs of the
Company's unit offering. Accordingly, $9,427,000 was allocated to the debt
component of the unit offering, and $1,573,000 was allocated to the equity
component of the unit offering. The portion of the offering costs associated
with the issuance of the Notes is being amortized as additional interest expense
over the term of the Notes. The class B common stock has special voting rights
and the ability to control the board of directors of New TDC, subject to certain
limitations (see Note 12).

In addition, the Company incurred other offering costs of $12,647,000. Of
these costs $10,839,000 was allocated to the debt component of the unit
offering, and $1,809,000 was allocated to the equity component of the unit
offering. The portion of the offering costs associated with the issuance of the
Notes is being amortized as additional interest expense over the term of the
Notes.

NOTE 9 -- DERIVATIVE TRANSACTIONS

The Company may use derivative instruments to manage exposures to commodity
prices. The Company's objectives for holding derivatives are to minimize the
risks using the most effective methods to eliminate or reduce the impacts of
this exposure.

In April 1999, the Company entered into a thirty-two month fixed-price
physical delivery contract with Aquila Energy Marketing Corporation ("Aquila")
that obligated the Company to deliver specified volumes of natural gas to Aquila
at a certain price. For the years 2000 and 2001, the Company agreed to deliver
approximately 3,098,000 Mbtu and 2,894,000 Mbtu, respectively, with prices
ranging from $2.353/Mcf to $2.697/Mcf.

With the authorization of the bankruptcy court, the Company rejected this
fixed-price physical delivery contract effective December 20, 2000. Aquila filed
a claim against the Company for damages relating to the cancellation of the
contract for $17,559,272. Subsequent to December 31, 2000, additional
information became available to the Company, resulting in an increase of our
original estimate by $737,022 in 2001. The claim was paid in 2001.

In June 2001 the Company entered into three commodity SWAP derivative
contracts as a condition of the issuance of the Notes described in Note 8. Under
the terms of the Notes, the Company must use these contracts to mitigate the
volatility of the commodity prices to ensure that the Company has sufficient
cash flows to service the Notes. The contracts are not designated for hedge
accounting under FAS No. 133; therefore, the Company recorded these contracts at
their estimated fair values, and included the changes in their fair value in the
statement of operations.

F-18

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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 year ended December 31,
2002. 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.
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, the
Company recognized $906,502 of such costs as an offset to revenues.

As of December 31, 2002 the Company had outstanding commodity price SWAP
agreements. The following table sets forth the volumes and hedge prices of our
SWAP contracts:

The contracts stipulate that the Company will receive or make payments
based upon the differential between the hedge prices and the market prices, as
defined in the contracts, for the notional quantities. The estimated fair value
of these contracts at December 31, 2002 of $5,292,597 is included in the
accompanying balance sheet as a current liability of $3,379,875 and as a
non-current liability of $1,912,722. The unrealized loss of $16,430,010 is
included in the accompanying statement of operations as "Loss on Derivative
Contracts".

Additionally, at January 1, 2003, the Company held 12 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.

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.

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.

F-19

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 10 -- INCOME TAXES

Deferred income taxes result from differences between the bases of assets
and liabilities as measured for income tax and financial reporting purposes. The
significant components of deferred tax assets and liabilities as of December 31,
were as follows:

The Company recorded a valuation allowance at December 31, 2001 and 2002
equal to the excess of deferred tax assets over deferred tax liabilities, as
management is unable to determine that these tax benefits are more likely than
not to be realized.

The following reconciles statutory federal income tax with the provision
for income tax for the years ended December 31:

At December 31, 2002, the Company had net operating loss carryforwards for
income tax reporting purposes of approximately $78,000,000, which will expire
during the years 2007 through 2022. The Internal Revenue Code significantly
limits the amount of pre-acquisition net operating loss carryforwards that are
available to offset future taxable income when a change of ownership of greater
than 50% occurs. The Company had a change of ownership on July 3, 2003 that
exceeded this threshold. As of December 31, 2002, the Company has approximately
$68,000,000 of its net operating losses that are subject to such limitations
under section 382 of the Internal Revenue Code. This limitation will be
increased by any built-in gains that are realized by 2007.

As of December 31, 2002, the Company's net operating losses expire as
follows:

F-20

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 11 -- COMMITMENTS AND CONTINGENCIES

Lease commitments

The Company has non-cancelable operating leases covering certain
compression equipment and facilities and corporate office space. The following
is a schedule of future minimum lease payments as of December 31, 2002:

Rent expense incurred under operating leases amounted to $3,390,383,
$3,539,339 and $3,487,811 for the years ended December 31, 2000, 2001 and 2002,
respectively.

Included in operating lease commitments are amounts for the leased office
space from a Bowman affiliate, Lovett Properties, Ltd. The Company has alleged
that the lease is void and unenforceable (see Note 6).

Effective April 1, 2003, the Company entered into a rental agreement with
Blue Dolphin Services Company, a company for which our Chairman, Chief Executive
Officer and President is currently serving on the board of directors, whereby we
will sub-lease approximately 5,237 square feet of office space in Houston, Texas
for a term of approximately 46 months. Our monthly rental rate will range from
$5,892 for months one through five to $6,546 per month for the remaining term of
the lease.

Lawsuits

The Company is the defendant in several lawsuits filed by companies for
breach of contract with claims and joint interest disputes. Accordingly, the
Company has accrued professional fees in the amount of $118,381 associated with
these lawsuits, which is included in the accompanying balance sheet as of
December 31, 2002.

The Company is currently involved in various legal disputes with its former
Chief Executive Officer in which he alleges certain members of the Company's
board of directors' violated fiduciary duties to the Company's shareholders by
entering into the Waiver (see Note 8). The suit further alleges the Company
entered into the Waiver transaction with the intended effect of diluting the
former executive to a minority interest in the Company. Additionally, the
Company has filed claims against the former executive, and related entities,
alleging breach of fiduciary responsibility with respect to improper use and
diversion of corporate funds used to improve a property, owned by an entity
related to the former executive, for which title has not been properly conveyed
to the Company (see Note 7). Although the outcome of these matters is uncertain,
the Company does not anticipate that their resolution will have a material
adverse impact on the Company's consolidated financial position or results of
operations.

The Company is a defendant in various lawsuits arising from normal business
activities. Management has reviewed pending litigation with legal counsel and
believes that these actions are without merit or that the ultimate liability, if
any, resulting from them will not materially affect the Company's financial
position.

Regulatory and environmental contingencies

During 2000, the Company reached a settlement with the MMS resolving a
civil enforcement action related to non-environmental infractions of platform
construction brought against the Company in August 2000 by the MMS. The Company
agreed to pay civil penalties of $506,600 with $25,325 to be paid out initially,
and the remaining $481,175 to be paid out in quarterly installments over a
two-year period. The settlement between the MMS and the Company was not an
admission of liability by the Company with respect to the violations alleged by
the MMS. On February 14, 2003, the Company paid this obligation in full.

F-21

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

The Company, as an owner and operator of oil and natural gas properties, is
subject to various federal, state and local laws and regulations relating to
discharge of materials into, and protection of, the environment. These laws and
regulations may, among other things, impose liability on the lessee under an oil
and natural gas lease for the cost of pollution clean-up resulting from
operations and subject the lessee to liability for pollution damages. The
Company maintains insurance coverage, which it believes, is customary in the
industry, although it is not fully insured against all environmental risks.

The Company is not aware of any environmental claims existing as of
December 31, 2002, which would have a material impact on its financial position
or results of operations. There can be no assurance however, that current
regulatory requirements will not change, or past non-compliance with
environmental laws will not be discovered on the Company's properties.

Other

As of December 31, 2002, the Company expects the future cost of
restoration, dismantlement and abandonment of certain offshore wells and the
decommissioning of offshore platforms to be approximately $23,786,000. In
connection therewith, the Company has provided bonds with a face value of
$9,850,000 pledged to the MMS for a portion of such estimated costs.
Additionally, we have provided various other forms of pledged collateral to
other regulatory agencies in satisfaction of their requirements. At December 31,
2001 and 2002, these pledges and bonds had a carrying value of $5,225,832 and
$5,340,087, respectively.

NOTE 12 -- CAPITAL STOCK

On June 13, 2001, the Company increased its authorized share capital to
445,000 shares of class A common stock and 65,000 shares of class B common
stock. The Company also affected a 238.333:1 stock split of its class A common
stock. The consolidated financial statements give retroactive effect to the
stock split for all periods presented. In connection with the stock split, the
par value of the class A common stock decreased from $1.00 to $0.01 per share.
The par value of the class B common stock is $0.01. The class B common stock is
convertible into class A common stock upon the occurrence of certain events, as
defined.

The holders of the Class A and Class B common stock are entitled to one
vote for each share on all matters voted upon by shareholders, including the
election of directors. Such holders are not entitled to vote cumulatively for
the election of directors. Holders of a majority of the shares of common stock
entitled to vote in any election of directors may elect all of the directors
standing for election, subject to the rights of holders of class B common stock
described below.

The holders of the class A and class B common stock are together entitled
to participate pro rata in such dividends as may be declared at the discretion
of the board of directors out of funds legally available therefore. Holders of
the class A and class B common stock together are entitled to share ratably in
the net assets of the Company upon liquidation after payment or provision for
all liabilities and any preferential rights. Holders of common stock have no
preemptive rights to purchase shares of stock of the Company. Shares of common
stock are not subject to any redemption provisions and are not convertible into
any other securities of the Company, except that each share of class B common
stock is convertible into one share of class A common stock under certain
circumstances.

Special Rights of Class B Common Stock

In addition to the rights of the holders of common stock set forth above,
the holders of a majority of the class B common stock, voting together as a
single class, are entitled to designate one person to serve as a non-voting
advisory observer to the Company's board of directors, and further, at any time,
to cause the Company to increase the size of its board of directors and to
immediately elect to the board of directors a number of directors (having full
voting power) nominated by a majority of the holders of the class B common stock
sufficient to constitute a majority of the board of directors. Until there are
no outstanding shares of class B common stock, the board of directors may not
consist of more than seven directors other than those nominated by the holders
of the class B common stock in accordance with the foregoing. Only the holders
of the class B common stock may remove the directors that such holders are
entitled to designate.

F-22

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

In addition to any vote required by law, all matters submitted to a vote of
the Company's shareholders will require the approval of the holders of a
majority of the issued and outstanding shares of class B common stock, voting
separately as a single class. In addition, any amendment to the Company's Bylaws
will require the approval of the holders of the majority of the issued and
outstanding shares of class B common stock.

Changes in Securities

On July 3, 2002, the Company issued 76,667 shares of its class A common
stock, par value $0.01 per share to the holders of its 12.5% senior secured
notes. The issuance of the additional shares of class A common stock resulted in
a change of control with respect to beneficial ownership of our common stock. An
aggregate of 510,000 shares of our common stock were issued and outstanding at
July 3, 2002 consisting of 445,000 shares of class A common stock and 65,000
shares of class B common stock. Of these shares, Richard Bowman, our former
President and Chief Executive Officer, owns 238,333 shares of class A common
stock and no shares of class B common stock, or 47% of our common stock. The
holders of the senior secured notes hold an aggregate of 206,667 shares of class
A common stock and Jefferies & Company, Inc. holds an aggregate of 65,000 shares
of class B common stock, or a combined 53% of our common stock. Prior to the
July 3, 2002 issuance of an additional 76,667 shares of class A common stock,
Richard Bowman owned 55% of the issued and outstanding shares of common stock.
As a result of the aforementioned changes in securities and the resulting change
in control, federal tax laws will restrict the Company's ability to utilize its
net operating loss carryforward's.

NOTE 13 -- SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION

Information with respect to the Company's oil and natural gas producing
activities is presented in the following tables. Estimates of reserve
quantities, as well as future production and discounted cash flows before income
taxes, were determined by an independent petroleum engineering firm, as of
December 31, 2000, 2001 and 2002. The estimates of reserve values include
estimated future development costs that the Company does not currently have the
ability to fund. If the Company is unable to obtain additional funds, it may not
be able to develop its oil and natural gas properties as estimated in its
December 31, 2002 reserve report.

Oil and Natural Gas Related Costs

The following table sets forth information concerning costs related to the
Company's oil and gas property acquisition, exploration and development
activities in the United States during the years ended December 31,2000, 2001
and 2002:

Results of Operations from Oil and Natural Gas Producing Activities

The following table sets forth the Company's results of operations from oil
and natural gas producing activities for the years ended December 31:

F-23

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

In the presentation above, no deduction has been made for indirect costs
such as corporate overhead or interest expense. No income taxes are reflected
above due to the Company's tax loss carryforwards.

Oil and Natural Gas Reserves (Unaudited)

The following table sets forth the Company's net proved oil and natural gas
reserves at December 31, 2000, 2001 and 2002 and the changes in net proved oil
and natural gas reserves for the years then ended. Proved reserves represent the
estimated quantities of crude oil and natural gas which geological and
engineering data demonstrate with reasonable certainty to be recoverable in the
future years from known reservoirs under existing economic and operating
conditions. The reserve information indicated below requires substantial
judgment on the part of the reserve engineers, resulting in estimates, which are
not subject to precise determination. Accordingly, it is expected that the
estimates of reserves will change as future production and development
information becomes available and that revisions in these estimates could be
significant. Reserves are measured in barrels (Bbls) in the case of oil, and
units of one thousand cubic feet (Mcf) in the case of natural gas.

Of the Company's total proved reserves as of December 31, 2000, 2001 and
2002, approximately 57%, 51% and 58%, respectively, were classified as proved
developed producing, 18%, 9% and 7%, respectively, were classified as proved
developed non-producing and 34%, 41% and 35%, respectively, were classified as
proved undeveloped. All of the Company's reserves are located in the continental
United States.

F-24

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

Standardized Measure of Discounted Future Net Cash Flows (unaudited)

The standardized measure of discounted future net cash flows from the
Company's proved oil and natural gas reserves is presented in the following
table:

The following table sets forth the changes in the standardized measure of
discounted future net cash flows from proved reserves during 2000, 2001 and
2002:

Estimated future net cash flows represent an estimate of future net
revenues from the production of proved reserves using current sales prices,
along with estimates of the operating costs, production taxes and future
development and abandonment costs (less salvage value) necessary to produce such
reserves. The average prices used at December 31, 2000, 2001 and 2002, were
$25.90, $18.53 and $30.09 per Bbl and $10.31, $2.54 and $4.49 per Mcf,
respectively. No deduction has been made for depreciation, depletion or any
indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs
with respect to producing oil and natural gas properties. Future development
costs are based on the best estimate of such costs assuming current economic and
operating conditions.

Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved, less
applicable carryforwards, for both regular and alternative minimum tax.

The future net revenue information assumes no escalation of costs or prices,
except for oil and natural gas sales made under terms of contracts, which
include fixed and determinable escalation. Future costs and prices could
significantly vary from current amounts and, accordingly, revisions in the
future could be significant.

F-25

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 14 - CONSOLIDATING INFORMATION

CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2001

F-26

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2002

F-27

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000

F-28

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001

F-29

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2002

F-30

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2000
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

F-31

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2001
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

F-32

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2002
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

F-33

TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

NOTE 15 -- QUARTERLY CONSOLIDATED FINANCIAL INFORMATION (UNAUDITED)

The following is a summary of the unaudited quarterly results of the Company's
operations for the years ended December 31, 2001 and 2002 (in thousands, except
per share data):

(a) Net income for the quarter ended September 30, 2001 has been reduced by
$737,022 as a result of a change in our original estimate of the loss associated
with the rejection of a fixed-price physical delivery contract during our
bankruptcy proceeding. Additional information became available to us subsequent
to the filing of our report on Form 10Q at September 30, 2001. Net income per
common share was reduced by $1.70 per share as a result of this change in
estimate.

F-34

EXHIBIT INDEX

* Filed herewith