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U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
Commission file number: 333-66282
TRI-UNION DEVELOPMENT CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0381207
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)
530 LOVETT BOULEVARD 77006
HOUSTON, TEXAS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICES)
(713) 533-4000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
INDICATE BY CHECK MARK WHETHER THE REGISTRANT: (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS.
yes [X] no [ ]
AS OF NOVEMBER 19, 2002 THERE WERE 445,000 SHARES OF CLASS A COMMON STOCK, PAR
VALUE $0.01 PER SHARE AND 65,000 SHARES OF CLASS B COMMON STOCK, PAR VALUE $0.01
PER SHARE, OUTSTANDING.
TRI-UNION DEVELOPMENT CORPORATION
(SUCCESSOR TO TRIBO PETROLEUM CORPORATION)
INDEX TO FINANCIAL INFORMATION
Part I. Financial Information
Item 1. Financial Statements
Consolidated Statements of Operations for the Three and Nine Months Ended
September 30, 2002 and 2001 (unaudited)................................................... 3
Consolidated Balance Sheets at September 30, 2002 (unaudited) and
December 31, 2001 (audited)............................................................... 4
Consolidated Statements of Cash Flows for the Nine Months Ended
September 30, 2002 and 2001 (unaudited)................................................... 5
Notes to Consolidated Financial Statements (unaudited).................................... 7
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations..................................................................... 11
Item 3. Quantitative and Qualitative Disclosure about Market Risk................................. 23
Item 4. Controls and Procedures................................................................... 24
Part II. Other Information
Item 1. Legal Proceedings......................................................................... 25
Item 2. Changes in Securities..................................................................... 26
Item 3. Defaults Upon Senior Securities........................................................... 26
Item 4. Submission of Matters to a Vote of Security Holders....................................... 27
Item 5. Forward Looking Statements................................................................ 28
Item 6. Exhibits and Reports on Form 8-K.......................................................... 29
Signatures ................................................................................................... 30
Section 302 Officers' Certification........................................................................... 31
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TRI-UNION DEVELOPMENT CORPORATION
(SUCCESSOR TO TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
2002 2001 2002 2001
-------------- ------------- ------------- --------------
Revenues and other:
Oil and natural gas revenues $ 7,934,240 $ 13,398,527 $ 29,616,995 $ 68,065,015
Loss on marketable securities - (139,556) - (556,735)
Gain (loss) on derivative contracts (369,475) 8,365,229 (14,603,065) 11,951,855
Other 104,567 (74,846) 2,560,896 822,076
-------------- ------------- ------------- --------------
Total revenues and other 7,669,332 21,549,354 17,574,826 80,282,211
-------------- ------------- ------------- --------------
Expenses:
Lease operating expense 3,836,818 4,607,123 13,793,427 15,087,552
Workover expense 702,773 884,596 3,159,375 4,224,725
Production taxes 186,564 327,232 664,419 1,668,808
Depreciation, depletion and amortization 1,774,819 3,147,998 6,339,501 10,410,040
General and administrative expenses 1,991,933 1,350,751 4,592,620 4,499,985
Interest expense 6,398,235 7,529,222 20,342,741 13,805,472
-------------- ------------- ------------- --------------
Total expenses 14,891,142 17,846,922 48,892,083 49,696,582
-------------- ------------- ------------- --------------
Income (loss) before reorganization costs and
income taxes (7,221,810) 3,702,432 (31,317,257) 30,585,629
Reorganization costs (16,539) 1,427,480 122,622 8,738,588
-------------- ------------- ------------- --------------
Income (loss) before income taxes (7,205,271) 2,274,952 (31,439,879) 21,847,041
Provision (benefit) for income taxes - (178,798) - 212,644
-------------- ------------- ------------- --------------
Net income (loss) $ (7,205,271) $ 2,453,750 $ (31,439,879) $ 21,634,397
============= ============= ============= ==============
Net income (loss) per share - basic and diluted $ (14.13) $ 5.66 $ (68.57) $ 69.05
============= ============= ============= ==============
Weighted average shares outstanding - basic
and diluted 510,000 433,333 458,511 313,333
============== ============= ============= ==============
The accompanying notes are an integral part of these
consolidated financial statements.
3
TRI-UNION DEVELOPMENT CORPORATION
(SUCCESSOR TO TRIBO PETROLEUM CORPORATION)
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
2002 2001
(unaudited) (audited)
------------------ ------------------
ASSETS
Current assets:
Cash and cash equivalents $ 2,916,611 $ 4,764,545
Restricted cash 1,578,795 8,929,566
Accounts receivable, net of allowance for doubtful accounts of
$1,422,277 and $1,376,970 10,624,724 13,860,164
Prepaid expenses and other 574,108 1,960,104
Derivative contracts - 9,525,317
Deferred loan costs, net 14,008,518 -
------------------ ------------------
Total current assets 29,702,756 39,039,696
------------------ ------------------
Oil and natural gas properties - full cost method, net 77,610,110 85,524,756
------------------ ------------------
Other assets:
Restricted cash and bonds 5,269,977 5,225,832
Furniture, fixtures and equipment, net 1,057,202 1,147,611
Receivables from affiliate, net - 206,116
Deferred loan costs, net - 17,034,817
Derivative contracts - 2,973,627
Other assets 1,782,894 -
------------------ ------------------
Total other assets 8,110,073 26,588,003
------------------ ------------------
Total assets $ 115,422,939 $ 151,152,455
================== ==================
LIABILITIES AND STOCKHOLDERS' EQUITY (CAPITAL DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities $ 20,623,091 $ 22,904,154
Accounts payable subject to renegotiation 2,068,518 5,133,667
Accrued interest 4,935,360 1,399,306
Payable to affiliate 25,732 -
Notes payable - 965,875
Derivative contracts 1,248,279 -
Other liabilities 1,797,942 -
Senior secured notes - in default (Note 2) 101,968,752 20,000,000
------------------ ------------------
Total current liabilities 132,667,674 50,403,002
Senior secured notes - 89,172,434
Derivative contracts 1,772,008 -
------------------ ------------------
Total liabilities 134,439,682 139,575,436
------------------ ------------------
Stockholders' equity (capital deficit):
Class A common stock, $0.01 par value, 445,000 shares authorized;
445,000 and 368,333 shares issued and outstanding 4,450 3,683
Class B common stock, $0.01 par value, 65,000 shares authorized;
65,000 shares issued and outstanding 650 650
Additional paid-in-capital 26,065,635 25,220,285
Deficit (45,797,684) (13,647,599)
------------------ -----------------
Total stockholders' equity (capital deficit) (19,016,743) 11,577,019
------------------ ------------------
Total liabilities and stockholders' equity (capital deficit) $ 115,422,939 $ 151,152,455
================== ==================
The accompanying notes are an integral part of these
consolidated financial statements.
4
TRI-UNION DEVELOPMENT CORPORATION
(SUCCESSOR TO TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(UNAUDITED)
Nine Months Ended September 30,
--------------------------------------
2002 2001
------------------ ------------------
Cash flows from operating activities:
Net income (loss) $ (31,439,879) $ 21,634,397
Adjustments to reconcile net income (loss) to net cash provided
by (used in) operating activities:
Depreciation, depletion and amortization 6,339,501 10,410,040
Amortization of bond discount 4,671,318 2,119,964
Amortization of debt issuance costs 3,899,575 1,713,356
Loss on sale of marketable securities - 556,735
Accretion of bond interest (44,144) (48,721)
Loss on sale of equipment 1,914 7,042
Reorganization costs 122,622 8,738,588
Cash settlements on derivative contracts (1,555,424) -
Loss on derivative floor contracts recognized in revenues 461,139 -
(Gain) loss on derivative contracts 14,603,065 (11,951,855)
Changes in assets and liabilities:
Restricted cash 7,350,771 (9,497,992)
Accounts receivable 4,233,633 6,537,658
Prepaid expenses and other 1,385,996 271,503
Receivables from (payable to) affiliates, net 231,848 92,313
Other assets (1,782,894) -
Accounts payable and accrued liabilities 9,318,899 (4,250,914)
Accounts payable subject to renegotiation (3,065,149) (38,312,867)
------------------ -----------------
Net cash provided by (used in) operating activities before
reorganization items 14,732,791 (11,980,753)
------------------ -----------------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid (61,530) (6,205,694)
Interest earned during bankruptcy - 945,722
------------------ ------------------
Net cash used in reorganization items (61,530) (5,259,972)
------------------ -----------------
Net cash provided by (used in) operating activities 14,671,261 (17,240,725)
------------------ -----------------
Cash flows from investing activities:
Purchase of marketable securities - (742,909)
Proceeds from sale of marketable securities - 555,964
Additions to oil and natural gas properties (5,218,332) (10,652,235)
Purchase of furniture, fixtures and equipment (140,787) (1,025,190)
Proceeds from disposal of equipment - 6,500
Proceeds from sale of oil and natural gas properties 6,024,565 2,225,529
Cash settlements on derivative contracts 1,555,424 -
Proceeds from sale of derivative contracts 2,252,971 -
Purchase of restricted cash and bonds - (427,717)
------------------ -----------------
Net cash provided by (used in) investing activities 4,473,841 (10,060,058)
------------------ -----------------
Cash flows from financing activities:
Proceeds from long-term debt - 113,444,294
Payments of long-term debt (20,000,000) (104,323,500)
Payment of loan fees (27,161) (2,934,978)
Payments on notes payable (965,875) (333,880)
------------------- -----------------
Net cash provided by (used in) financing activities (20,993,036) 5,851,936
Net decrease in cash and cash equivalents (1,847,934) (21,448,847)
Cash and cash equivalents - beginning of period 4,764,545 32,989,939
------------------ ------------------
Cash and cash equivalents - end of period $ 2,916,611 $ 11,541,092
================== ==================
5
TRI-UNION DEVELOPMENT CORPORATION
(SUCCESSOR TO TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(UNAUDITED)
Supplemental Disclosures of Cash Flow Information:
Interest paid $ 33,295 $ 19,525,512
Non-cash transactions:
Discount on units offering - (24,750,000)
Transfer of oil and natural gas properties to affiliate - 1,097,611
Purchase of derivative contracts with long-term liability 1,797,943 -
Sale of oil and natural gas properties in exchange for receivable 998,192 -
Issuance of class A common stock in consideration for modifying
senior secured debt terms 850,000 -
Conversion of accrued interest payable to senior secured debt 8,125,000 -
The accompanying notes are an integral part of these
consolidated financial statements.
6
TRI-UNION DEVELOPMENT CORPORATION
(SUCCESSOR TO TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
NOTE 1 -- BASIS OF PRESENTATION
Tri-Union Development Corporation ("the Company") successor to Tribo
Petroleum Corporation ("Tribo") was incorporated in the State of Texas in
September 1992. The Company with its subsidiary is an independent oil and
natural gas company engaged in the acquisition, operation and development of oil
and natural gas properties primarily in areas of Texas and Louisiana, offshore
in the shallow waters of the Gulf of Mexico and in the Sacramento Basin of
northern California.
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiary Tri-Union Operating Company ("TOC"),
which was incorporated in the State of Delaware in November 1974. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
Prior to July 2001, the Company was a wholly owned subsidiary of Tribo.
On July 27, 2001, the Company and Tribo merged and the surviving corporation was
the Company. Accordingly, the assets, liabilities and operations of Tribo are
included with those of the Company for all periods presented in the financial
statements.
NOTE 2 - LIQUIDITY, GOING CONCERN UNCERTAINTY AND MANAGEMENT'S PLANS
On June 1, 2002, the Company was required to make a $28,125,000 payment
of principle and interest on its senior secured notes, with an additional
scheduled interest payment of approximately $7,400,000 due on December 1, 2002.
In addition, the Company has a scheduled principal and interest payment of
approximately $28,700,000 due June 1, 2003. The Company made its scheduled
principal payment of $20,000,000 due on June 1, 2002, but refinanced its
scheduled interest payment of $8,125,000 into additional promissory notes under
the terms of a Waiver, Agreement and Supplemental Indenture (the "Waiver") (see
Note 7). In connection with securing the Waiver, the Company issued 76,667
shares of class A common stock. The value of these shares was determined to be
$850,000 and was recorded on the accompanying balance sheet as additional
deferred loan costs and will be amortized over the remaining term of the senior
secured notes. The Waiver contained additional covenants, one of which required
the Company to obtain clear title to an oil and gas property subject to lien by
no later than August 2, 2002. Additionally, the Waiver contained covenants
requiring the Company to maintain average daily production of 28.5 Mmcfe and to
generate $4.0 million of EBITDA, as adjusted for the non-cash effects of our oil
and gas hedging contract as of the end of the third quarter of 2002. As the
Company was unable to obtain clear title by that date, maintain the required
average daily production levels, and did not report EBITDA of $4.0 million, an
event of default occurred to the Waiver and the original Indenture whereby the
senior secured notes became due on demand. Accordingly, the senior secured notes
and related deferred loan costs have been classified as current in the
accompanying consolidated balance sheet at September 30, 2002. While the Company
continues to delay certain of its workover and capital improvement projects in
order to maximize available cash to meet its debt obligations, the foregoing
event of default could have a material impact on the Company's ability to meet
its scheduled debt obligation and working capital requirements. Should the
noteholders demand payment on the notes, the Company will not have the ability
to generate sufficient resources to satisfy this obligation. These conditions
raise substantial doubt about the Company's ability to continue as a going
concern.
The Company is currently marketing certain of its oil and gas
properties in order to meet these scheduled debt obligations and working capital
requirements. Several offers to purchase certain of the Company's oil and gas
properties have been received to date which, if accepted, and combined with the
Company's unrestricted cash balances at November 12, 2002 of approximately $4.6
million, would provide the Company with sufficient capital to meet its upcoming
December 1, 2002 scheduled debt obligation.
To the extent the cash generated from oil and gas property sales and
continuing operations are insufficient to meet the Company's scheduled debt
obligations and its projected working capital needs, the Company will have to
raise additional capital. No assurance can be given that additional funding will
be available, or if available, will be on terms acceptable to the Company.
Uncertainty regarding the
7
amount and timing of any proceeds from the Company's plans to raise additional
capital raises substantial doubt about the Company's ability to continue as a
going concern. The accompanying consolidated financial statements do not include
any adjustments relating to the recoverability and classification of asset
carrying amounts or the amount and classification of liabilities that might be
necessary should the Company be unable to continue as a going concern.
NOTE 3 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Presentation
The accompanying unaudited consolidated interim financial statements
and disclosures for the three and nine months ended September 30, 2002 and 2001,
have been prepared by the Company pursuant to the rules and regulations of the
Securities and Exchange Commission and in accordance with accounting principles
generally accepted in the United States of America ("GAAP"). In the opinion of
management, all adjustments (consisting solely of normal recurring adjustments)
necessary for a fair presentation in all material respects of the results for
the interim periods have been made. The December 31, 2001 balance sheet was
derived from audited financial statements and notes included in our annual
report on Form 10-K. The interim unaudited financial statements for the three
and nine months ended September 30, 2002 and 2001 should be read in conjunction
with the Company's annual consolidated financial statements for the years ended
December 31, 2001 and 2000. The results of operations for the three and nine
months ended September 30, 2002, are not necessarily indicative of results to be
expected for the full year.
NOTE 4 - DERIVATIVE CONTRACTS
On March 28, 2002, the Company terminated certain of its commodity
price swap derivative contracts for net proceeds of approximately $2.3 million
and replaced them with contracts providing for price floors at prices specified
under the terms of the senior secured notes of $2.75 per MMBtu of natural gas
and $18.50 per barrel of crude oil. The gain of $2.3 million from the sale of
the commodity price swap derivative contracts is included in gain (loss) on
derivative contracts in the Company's consolidated statements of operations for
the three and nine months ended September 30, 2002. The purchase price of the
floor contracts of $1,797,943 is due and payable in full on July 1, 2003 and,
accordingly, has been presented as a current liability in the accompanying
consolidated balance sheet at September 30, 2002. The purchase price of the
floor contracts is recognized as an offset to revenues in the accompanying
consolidated statements of operations based upon the cost of the individual
contracts purchased. During the three and nine months ended September 30, 2002,
the Company recognized $277,285 and $461,137, respectively, of such costs as an
offset to revenues.
The Company maintains a rolling two-year combination of commodity price
swaps and price floor agreements in order to manage the price risk associated
with a portion of its production. These derivative transactions do not qualify
for hedge accounting under Financial Accounting Standards Board ("FASB")
Statement No. 133 and, accordingly, changes in the estimated value of derivative
contracts held at the balance sheet date are recognized in the statement of
operations as non-cash gains or losses on derivative contracts. Conversely, net
cash settlements realized from the Company's derivative contracts are included
in oil and natural gas revenues in the accompanying consolidated statements of
operations. At September 30, 2002, the estimated fair value of the Company's
derivative contracts held represents a net current liability of $1,248,279 and a
net non-current liability of $1,772,008. During the three and nine months ended
September 30, 2002, net cash settlements realized from the Company's derivative
contracts amounted to approximately ($890,675) and $1,555,424, respectively.
NOTE 5 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, FASB issued Statement of Financial Accounting Standards
("SFAS") No. 141, Business Combinations (SFAS No. 141), and No. 142, Goodwill
and Other Intangible Assets (SFAS No. 142). SFAS 141 requires the use of the
purchase method of accounting and prohibits the use of the pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001.
SFAS No. 141 required the Company to recognize acquired intangible assets apart
from goodwill if the acquired intangible assets meet certain criteria. SFAS No.
141 applies to all business combinations initiated after June 30, 2001, and for
purchase business combinations completed on or after July 1, 2001. SFAS No. 141
also requires upon adoption of SFAS No. 142 that the Company reclassify the
carrying amounts of intangible assets and goodwill based on the criteria in SFAS
No. 141. SFAS No. 142 requires that
8
companies no longer amortize goodwill, but instead test goodwill for impairment
at least annually. In addition, SFAS No. 142 requires that the Company identify
reporting units for the purposes of assessing potential future impairments of
goodwill and to reassess the amortization of intangible assets with an
indefinite useful life. An intangible asset with an indefinite useful life
should be tested for impairment in accordance with SFAS No. 142. SFAS No. 142 is
required to be applied in fiscal years beginning after December 15, 2001 to all
goodwill and other intangible assets recognized at that date, regardless of when
those assets were initially recognized. SFAS No. 142 requires the Company to
complete a transitional goodwill impairment test six months from the date of
adoption. The Company is also required to reassess the useful lives of other
intangible assets within the first interim quarter after adoption of SFAS 142.
The adoption of SFAS No. 141 and SFAS No. 142 did not materially impact the
Company's financial position and results of operations.
In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). SFAS No. 143 amends SFAS No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies, and is applicable
to all companies. SFAS No. 143, which is effective for fiscal years beginning
after June 15, 2002, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal obligations associated
with the retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived asset,
except for certain obligations of lessees. As used in SFAS No. 143, a legal
obligation is an obligation that a party is required to settle as a result of an
existing or enacted law, statue, ordinance, or written or oral contract or by
legal construction of a contract under the doctrine of promissory estoppel.
While the Company is not yet required to adopt SFAS No. 143, it is not believed
the adoption will have a material effect on its financial condition or results
of operations.
In August 2001, FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-lived Assets ("SFAS No. 144"). SFAS No. 144, which
supercedes SFAS No. 121, Accounting for the Impairment of Long-lived Assets and
Long-lived Assets to be Disposed Of and amends Accounting Research Bulletin No.
51, Consolidated Financial Statements, addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001, and interim
financials within those fiscal years, with early adoption encouraged. The
provisions of SFAS No. 144 are generally to be applied prospectively. The
Company does not believe the adoption of SFAS No. 144 will have a material
effect on its financial condition or results of operations.
In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the current requirement that gains and
losses on debt extinguishment must be classified as extraordinary items in the
income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS No. 145 eliminates an inconsistency in lease accounting by
requiring that modifications of capital leases that result in reclassification
as operating leases be accounted for consistent with sale-leaseback accounting
rules. The statement also contains other nonsubstantive corrections to
authoritative accounting literature. The changes related to debt extinguishment
will be effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for transactions occurring after
May 15, 2002. Adoption of this standard will not have any immediate effect on
our consolidated financial statements. The Company will apply this guidance
prospectively.
On June 20, 2002, FASB's Emerging Issues Task Force (EITF) reached a
partial consensus on Issue No. 02-03, Recognition and Reporting of Gains and
Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities, and No.
00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue
No. 98-10. The EITF concluded that, effective for periods ending after July 15,
2002, mark-to-market gains and losses on energy trading contracts (including
those to be physically settled) must be retroactively presented on a net basis
in earnings. In addition, companies must disclose volumes of physically-settled
energy trading contracts. The Company is evaluating the impact of this new
consensus on the presentation of its consolidated income statement but believes
it will not have a material impact on total revenues and expenses. The consensus
will have no impact on net income.
9
In June 2002, FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally Emerging Issues Task Force (EITF) Issue No. 94-3. The Company will
adopt the provisions of SFAS No. 146 for restructuring activities initiated
after December 31, 2002. SFAS No. 146 requires that the liability for costs
associated with an exit or disposal activity be recognized when the liability is
incurred. Under EITF No. 94-3, a liability for an exit cost is recognized at the
date of a company's commitment to an exit plan. SFAS No. 146 also establishes
that the liability should initially be measured and recorded at fair value.
Accordingly, SFAS No. 146 may affect the timing of recognizing future
restructuring costs as well as the amount recognized. Adoption of this standard
will not have any immediate effect on our consolidated financial statements. The
Company will apply this guidance prospectively.
NOTE 6 - OIL AND NATURAL GAS PROPERTIES
During May 2002, the Company sold certain of its oil and natural gas
properties for approximately $7,700,000. Consistent with the Company's policy of
accounting for its oil and natural gas properties using the full cost method,
the sales price was credited to oil and natural gas properties with no
corresponding gain or loss recorded as a result of the sale transactions. Among
those properties sold was the Company's interest in the Scott, Clear Branch and
Rayne Fields in Louisiana for $6,450,000. Subject to the terms of the sale, the
Company entered into a Holdback Agreement whereby $998,192 of the total sales
price was held back pending completion of a post-closing review. The hold back
amount has been included in accounts receivable in the accompanying Consolidated
Balance Sheet at September 30, 2002.
During the second quarter of 2002, the Company participated in the
successful drilling and completion of the Champion #1-H well in Grimes County,
Texas. The well was brought into production during the second quarter of 2002
for a net cost to the Company of $2,328,494. Currently, the title to this well
is in dispute. As a result, the net cost to drill and complete the well, offset
by $559,098 of production revenue and $13,498 of lease operating expense is
shown on the accompanying balance sheet as other assets at September 30, 2002,
pending resolution of the title dispute.
Note 7 - Contingencies
The Company is currently involved in various legal disputes with its
former Chief Executive Officer in which he alleges certain members of the
Company's board of directors violated fiduciary duties to the Company's
shareholders by entering into the Waiver. The suit further alleges the Company
entered into the Waiver transaction with the intended effect of diluting the
former executive to a minority interest in the Company. Additionally, the
Company has filed claims against the former executive, and related entities,
alleging breach of fiduciary responsibility with respect to improper use and
diversion of corporate funds used to improve a property, owned by an entity
related to the former executive, for which title has not been properly conveyed
to the Company. Although the outcome of these matters is uncertain, the Company
does not anticipate that their resolution will have a material adverse impact on
the Company's consolidated financial position or results of operations.
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion of our financial condition and results of
operations and financial condition includes the results of operations and
financial condition of our former parent for periods presented prior to July 27,
2001, and our subsidiary and us on a consolidated basis. Our consolidated
financial statements and the related notes contain additional detailed
information that should be referred to when reviewing this material.
GENERAL
We are an independent oil and natural gas company engaged in the
acquisition, development, exploration and production of oil and natural gas
properties in three core areas, onshore Gulf Coast, Gulf of Mexico and the
Sacramento Basin of northern California.
We commenced operations in 1992 and from our inception until mid-1996
we primarily acquired and developed properties onshore in south and southeast
Texas. We expanded into the Sacramento Basin of northern California with our
acquisition of Reunion in 1996. We established a core area of operation in the
shallow waters of the Gulf of Mexico in 1997 with acquisitions from Apache and
Statoil. In 1998 we expanded our onshore Gulf Coast properties by completing our
largest acquisition to date, the $63.0 million acquisition of onshore Texas oil
and natural gas properties from Apache. We have since focused our efforts and
capital resources on developing our assets.
We have one subsidiary, Tri-Union Operating Company, which is wholly
owned by us. Tri-Union Operating's principal asset is a net profits interest in
a field operated by us representing less than 5% of our consolidated proved
reserves.
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation with the proceeds from a short-term,
amortizing bank loan. In August 1998, before we were able to refinance our bank
loan, commodity prices began falling, with oil prices ultimately reaching a
12-year low in December 1998. The resultant negative effect on our cash flow
from the deterioration of commodity prices, coupled with the required
amortization payments on our bank loan, severely restricted the amount of
capital we were able to dedicate to development drilling. Consequently, our oil
and natural gas production declined, further negatively affecting our cash flow.
In October 1998, our short-term loan matured and we arranged a forbearance
agreement providing for interest payments to be partially capitalized. In July
1999, this forbearance agreement terminated and we made negotiated interest
payments while attempting to negotiate a restructuring of our obligations.
On March 14, 2000, we chose to seek protection under Chapter 11 of the
U.S. Bankruptcy Code. Tri-Union Operating continued to operate outside of
bankruptcy. On July 18, 2001, we sold in a private unit offering $130,000,000 of
senior secured notes, each unit consisting of one note in the principal amount
of $1,000 and one share of class A common stock of Tribo Petroleum Corporation,
our former parent corporation. The proceeds from the unit offering and our
available cash balances were sufficient to allow us to pay or segregate funds
for the payment of all creditor claims in full, including interest, and to exit
bankruptcy on June 18, 2001.
At December 31, 2001, our net proved reserves were 191.7 Bcfe with a
PV-10 Value of $143.8 million and $160.8 million including our hedge position
value at such date. Our total proved reserve quantities at December 31, 2001
increased by 6% versus those at December 31, 2000. The increase in total proved
reserves was primarily due to two factors: first, based on recent drilling and
recompletion successes, we have been able to add a number of additional proved
undeveloped ("PUD's") and behind-pipe locations on our California assets;
secondly, a recent 3-D seismic survey conducted over our Barber's Hill property
has enabled us to delineate and add a PUD location in that field. Our capital
budget has been primarily focused on converting proved developed non-producing
and proved undeveloped reserves to production.
During 1999, 2000, 2001 and the first nine months of 2002, our capital
expenditures on oil and gas activities totaled approximately $13.6 million,
$10.9 million, $13.6 million and $5.2 million, respectively. These expenditures
related to operations in our three core areas. In 1998, 87% of our capital
expenditures were related to the acquisitions of reserves. In 1999 and 2000,
44%, or $10.6 million, of our capital expenditures were for development drilling
and recompletions. The remaining 56% was incurred on items such as platform and
pipeline improvements that were identified at the time of our
11
acquisition of the properties, compressor installations and on 3-D seismic
surveys. During 1999 and 2000 our development capital investments of $10.6
million were expended to complete 28 development wells, exploitation wells and
recompletions. During 2001 and the first nine months of 2002, our development
capital investments of $13.6 million and $5.2 million were expended on a large
offshore recompletion, the plugging and abandonment of four offshore facilities
and the recompletion or drilling of approximately 58 other projects.
On July 27, 2001, we were the surviving corporation in a merger with
our parent corporation, Tribo Petroleum Corporation. As a consequence of this
merger, we assumed all of the rights and obligations of Tribo, including those
under the indenture governing the senior secured notes. The financial
information contained herein is the consolidated financial information for
Tribo, our subsidiary and us.
On June 13, 2002, our Chief Executive Officer and President, Richard
Bowman, resigned his positions and was replaced by James M. Trimble, effective
July 19, 2002. Mr. Bowman retains ownership of approximately 47% of the
Company's outstanding common stock.
We use the full cost method of accounting for oil and natural gas
property acquisition, exploitation and development activities. Under this
method, all productive and nonproductive costs incurred in connection with the
acquisition of, exploration for and development of oil and natural gas reserves
are capitalized. Capitalized costs include lease acquisitions, geological and
geophysical work, delay rentals and the costs of drilling, completing and
equipping oil and natural gas wells. Gains or losses are recognized only upon
sales or dispositions of significant amounts of oil and natural gas reserves.
Proceeds from all other sales or dispositions are treated as reductions to
capitalized costs.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2002 Compared to Three Months Ended
September 30, 2001
For the three months ended September 30, 2002, consolidated net loss
was $7,205,271 as compared to consolidated net income of $2,453,750 for the
three months ended September 30, 2001.
OIL AND GAS REVENUES. Oil and natural gas revenues decreased
$5,464,287, or 41%, to $7,934,240 for the three months ended September 30, 2002,
from $13,398,527 for the three months ended September 30, 2001. The decrease in
oil and natural gas revenues was primarily the result of a decrease in
production volumes and a decrease in the average price we received for natural
gas during the period. During the second quarter of 2002, the Company sold
certain of its Texas Gulf Coast and all of its Louisiana properties. The decline
in production volumes is further attributable to a reduction in production from
our Westbury Farm #1 well in the Constitution field due to 2 wells drilled on
adjoining acreage, not owned or operated by us, directly offsetting our
production. Further contributing to the production decline are two wells that
watered-out in our Ord Bend field in California. After watering out, these 2
wells were recompleted to two zones at reduced production rates. Additionally,
production from our North Alvin, Spindletop, Sour Lake, South Liberty and
Hastings fields experienced abnormal production declines partially due to a
curtailed workover program during the second and third quarters of 2002. The
following table summarizes the consolidated results of oil and natural gas
production and related pricing for the three months ended September 30, 2002 and
2001:
For the Three Months Ended September 30,
--------------------------------------------
2002 2001 % Change
------------- ------------- -------------
Oil production volumes (Mbbls) 227 302 -25%
Gas production volumes (Mmcf) 928 1,576 -41
Total (Mmcfe) 2,289 3,388 -32
Average oil price (per Bbl) $24.69 $24.04 2%
Average gas price (per Mcf) 2.52 3.89 -35
Average price (per Mcfe) 3.47 3.95 -13
LOSS ON MARKETABLE SECURITIES. We recognized $139,556 in losses on
marketable securities for the three months ended September 30, 2001. Marketable
securities bought and held principally for the purpose of sale in the near term
are classified as trading securities. Trading securities are recorded at
12
fair value on the balance sheet as current assets, with the change in fair value
recognized during the period included in earnings. For the three months ended
September 30, 2002, we held no marketable securities for trading purposes.
LOSS ON DERIVATIVE CONTRACTS. In connection with the issuance of the
senior secured notes, we agreed to maintain, subject to certain conditions, on a
monthly basis, a rolling two-year derivatives contract until the maturity of the
notes on approximately 80% of our projected oil and natural gas production from
proved developed producing reserves. Additionally, in June 2001, we entered into
two-years of derivative contracts on the basis differential attributable to
approximately 80% of our projected proved developed producing natural gas
production from our California properties. These derivative contracts do not
qualify for hedge accounting under FAS 133, therefore, the Company marks these
transactions to fair value. On March 31, 2002, we terminated certain of our
derivative contracts and replaced them with contracts providing for price floors
at the prices specified under the terms of the senior secured notes of $2.75 per
MMBtu of natural gas and $18.50 per barrel of crude oil. Proceeds from the sale
of these contracts were approximately $2.3 million. The purchase price of the
floor contracts of approximately $1.8 million has been financed by the Company's
derivative contracts counterparty. The change in estimated fair value of these
contracts during the three months ended September 30, 2002 resulted in a net
non-cash loss on derivative contracts of $369,475 when compared to net non-cash
income on derivative contracts of $8,365,229 during the three months ended
September 30, 2001.
OTHER. Other income increased $179,413 or 240% to $104,567 for the
three months ended September 30, 2002 when compared to a loss $74,846 for the
three months ended September 30, 2001. The increase was primarily the result of
income in the amount of $100,000 for compensatory damages received during the
quarter ended September 30, 2002 offset by a reduction of emission credit income
in the amount of $50,000 recorded during the period. During the three months
ended September 30, 2001, a loss in the amount of $224,235 was recorded on the
sale of zero coupon U.S. Treasury bonds which had a maturity of 2019, held in
trust and pledged to the Minerals Management Service ("MMS") for the plugging
and abandonment of certain wells and the decommissioning of offshore platforms.
The sale of these bonds was necessary as a result of a change in MMS collateral
requirements. The loss we recorded as a result of the sale of the U.S. Treasury
bonds was partially offset by interest income of $70,196 received during the
three months ended September 30, 2001.
LEASE OPERATING EXPENSE. Lease operating expense decreased $770,305, or
17%, to $3,836,818 for the three months ended September 30, 2002 from $4,607,123
for the three months ended September 30, 2001. Lease operating expense was $1.68
per Mcfe for the three months ended September 30, 2002, an increase of 23% from
$1.36 per Mcfe for the three months ended September 30, 2001. The decrease in
lease operating expense is the result of the sale of certain of our Texas Gulf
Coast and all of our Louisiana properties during the second quarter of 2002.
Additionally, certain of our offshore properties including our High Island
leases and Galveston Island 211 were shut-in during the first and second
quarters of 2002 and continued to be shut-in during the three months ended
September 30, 2002. During the three months ended September 30, 2002, lease
operating expense, calculated on a unit of production basis increased by $0.32
per Mcfe. This increase is attributable to the 32% decline in oil and natural
gas production volumes when compared to the three months ended September 30,
2001.
WORKOVER EXPENSE. Workover expense decreased $181,823, or 21%, to
$702,773 for the three months ended September 30, 2002 from $884,596 for the
three months ended September 30, 2001. Workover expense was $0.31 per Mcfe for
the three months ended September 30, 2002, an increase of 19% from $0.26 per
Mcfe for the three months ended September 30, 2001. The decrease is primarily
the result of the Company's decision to restrict the use of cash during the
third quarter of 2002 in anticipation of the required interest payment due on
its 12.5% senior secured debt on December 1, 2002. The reduction in the amount
of workover expense incurred during the third quarter contributed to the general
decline in production volumes. During the three months ended September 30, 2002,
workover expense, calculated on a unit of production basis increased by $0.05
per Mcfe. This increase is attributable to the 32% decline in oil and natural
gas production volumes when compared to the three months ended September 30,
2001.
PRODUCTION TAXES. Production taxes decreased by $140,668 or 43% to
$186,564 for the three months ended September 30, 2002 from $327,232 for the
three months ended September 30, 2001. Production taxes were $0.08 per Mcfe for
the three months ended September 30, 2002, a decrease of 20% from $0.10 per Mcfe
for the three months ended September 30, 2001. Decreases in oil and natural
13
gas production and revenues during the three months ended September 30, 2002,
resulted in a decrease in the amount of production taxes incurred during the
period.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"). DD&A expense
decreased by $1,373,179, or 44%, to $1,774,819 for the three months ended
September 30, 2002 from $3,147,998 for the three months ended September 30,
2001. DD&A was $0.78 per Mcfe for the three months ended September 30, 2002, a
decrease of 16% from $0.93 per Mcfe for the three months ended September 30,
2001. The decrease in DD&A is the result of the decrease in production volumes
during the three months ended September 30, 2002 and the sale of certain oil and
natural gas properties during May 2002.
GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A increased $641,182, or
47%, to $1,991,933 for the three months ended September 30, 2002 from $1,350,751
for the three months ended September 30, 2001. G&A was $0.85 per Mcfe for the
three months ended September 30, 2002, an increase of 113% from $0.40 per Mcfe
for the three months ended September 30, 2001. The increase was primarily the
result of an increase of bad debt expense in the amount of $205,580 and an
increase in legal and consulting and professional fees of $818,904 during the
three months ended September 30, 2002 when compared to the three months ended
September 30, 2001. The increase in legal and consulting and professional fees
was primarily the result of services provided in connection with the Waiver
agreement and various legal matters discussed in legal proceedings (Item 1 of
Part II). This increase was partially offset by a decrease in contract labor
services of $141,569 and a decrease in insurance of $107,606 during the three
months ended September 30, 2002 when compared to the three months ended
September 30, 2001.
INTEREST EXPENSE. Interest expense decreased $1,130,987 or 15%, to
$6,398,235 for the three months ended September 30, 2002 from $7,529,222 for the
three months ended September 30, 2001. The decrease in interest expense is the
result of a decrease in the amount of outstanding debt on which interest is
calculated. Our outstanding interest bearing debt balance was $118.0 million at
September 30, 2002, a $12.0 million decrease from $130.0 million at September
30, 2001. Additionally, the decrease is attributable to a decrease of
amortization of deferred loan costs during the three months ended September 30,
2002.
REORGANIZATION COSTS. We filed a voluntary petition for relief under
the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District
of Texas, Houston Division on March 14, 2000. As a result, we incurred certain
reorganization costs. During the three months ended September 30, 2002, a
reduction in the amount of $16,539 was recorded to previously expensed
reorganization costs. This compares to reorganization costs in the amount of
$1,427,480 during the three months ended September 30, 2001. These
reorganization costs consist of the following:
Professional fees and other - We retained certain legal and accounting
professionals to assist with the bankruptcy proceedings and have incurred legal
and accounting fees associated with these proceedings totaling $190 and $245,147
for the three months ended September 30, 2002 and 2001, respectively.
Interest and amounts paid to creditors - Represents payments of amounts
owed to creditors with pre-petition claims, including interest. During the three
months ended September 30, 2002, we recorded a reduction of amounts owed to
creditors in the amount of $16,729. This compares to $1,079,880 of pre-petition
liabilities and interest paid to creditors during the three months ended
September 30, 2001.
Atasca transaction - As a condition of TDC's plan of reorganization,
the Company agreed to transfer all of the oil and natural gas properties owned
by Tribo Petroleum Corporation as of May 1, 2001 at their net book value of
$1,097,547 and certain marketable securities with a value of $102,453, to an
affiliate, Atasca Resources, Inc. In connection with this transaction, all
balances owing to and from the Company by affiliates on May 1, 2001 were
forgiven. These balances aggregated to a net receivable from the affiliates of
$785,442. As a consequence of these transactions, the Company recorded a
one-time reorganization expense of $1,985,442. The value of the marketable
securities in the amount of $102,453 was transferred to the affiliate during the
three months ended September 30, 2001. No amounts were recorded as a result of
this transaction during the three months ended September 30, 2002.
14
PROVISION FOR INCOME TAXES. A $178,798 provision for income tax was
made for the three months ended September 30, 2001, primarily as a result of
alternative minimum tax requirements. No provision for federal income tax was
required for the three months ended September 30, 2002.
Nine Months Ended September 30, 2002 Compared to Nine Months Ended
September 30, 2001
For the nine months ended September 30, 2002, consolidated net loss was
$31,439,879 as compared to consolidated net income of $21,634,397 for the nine
months ended September 30, 2001.
OIL AND GAS REVENUES. Oil and natural gas revenues decreased
$38,448,020, or 56%, to $29,616,995 for the nine months ended September 30,
2002, from $68,065,015 for the nine months ended September 30, 2001. The
decrease in oil and natural gas revenues was primarily the result of a decrease
in production volumes and a substantial decrease in the average price we
received for oil and natural gas during the period. During the second quarter of
2002, we sold certain of our Texas Gulf Coast and all of our Louisiana
properties. The decline in production volumes is further attributable to a
reduction in production from our Westbury Farm #1 well in the Constitution field
due to 2 wells drilled on adjoining acreage, not owned or operated by us,
directly offsetting our production. Further contributing to the production
decline are two wells, which watered-out in our Ord Bend field in California.
After watering out, these 2 wells were recompleted to two zones at reduced
production rates. Additionally, production from our North Alvin, Spindletop,
Sour Lake, South Liberty and Hastings fields experienced abnormal production
declines partially due to a curtailed workover program during the second and
third quarters of 2002. The following table summarizes the consolidated results
of oil and natural gas production and related pricing for the nine months ended
September 30, 2002 and 2001:
For the Nine Months Ended September 30,
--------------------------------------------
2002 2001 % Change
------------- ------------- -------------
Oil production volumes (Mbbls) 711 994 -28%
Gas production volumes (Mmcf) 3,954 6,191 -36
Total (Mmcfe) 8,220 12,155 -32
Average oil price (per Bbl) $24.05 $26.19 -8%
Average gas price (per Mcf) 3.16 6.79 -53
Average price (per Mcfe) 3.60 5.60 -36
LOSS ON MARKETABLE SECURITIES. We recognized $556,735 in losses on
marketable securities for the nine months ended September 30, 2001. Marketable
securities bought and held principally for the purpose of sale in the near term
are classified as trading securities. Trading securities are recorded at fair
value on the balance sheet as current assets, with the change in fair value
recognized during the period included in earnings. At September 30, 2002, we
held no marketable securities for trading purposes.
LOSS ON DERIVATIVE CONTRACTS. In connection with the issuance of the
senior secured notes, we agreed to maintain, subject to certain conditions, on a
monthly basis, a rolling two-year derivatives contract until the maturity of the
notes on approximately 80% of our projected oil and natural gas production from
proved developed producing reserves. Additionally, in June 2001, we entered into
two years of derivative contracts on the basis differential attributable to
approximately 80% of our projected proved developed producing natural gas
production from our California properties. These derivative contracts do not
qualify for hedge accounting under FAS 133, therefore, the Company marks these
transactions to fair value. On March 31, 2002, we terminated certain of our
derivative contracts and replaced them with contracts providing for price floors
at the prices specified under the terms of the senior secured notes of $2.75 per
MMBtu of natural gas and $18.50 per barrel of crude oil. Proceeds from the sale
of these contracts were approximately $2.3 million. The purchase price of the
floor contracts of approximately $1.8 million has been financed by the Company's
derivative contracts counterparty. The change in estimated fair value of these
contracts during the nine months ended September 30, 2002 and 2001 resulted in a
net non-cash loss on derivative contracts of $14,603,065 and net non-cash income
on derivative contracts of $11,951,855, respectively.
OTHER. Other income increased $1,738,820 or 212% to $2,560,896 for the
nine months ended September 30, 2002 when compared to $822,076 for the nine
months ended September 30, 2001. The increase was primarily the result of the
sale of emission reduction credits from our Hastings Field in the
15
amount of $2,226,450 during the nine months ended September 30, 2002 when
compared to income from the sale of emission credits in the amount of $681,690
during the nine months ended September 30, 2001. Additionally income in the
amount of $100,000 for compensatory damages was received during the nine months
ended September 30, 2002
LEASE OPERATING EXPENSE. Lease operating expense decreased $1,294,125,
or 9%, to $13,793,427 for the nine months ended September 30, 2002 from
$15,087,552 for the nine months ended September 30, 2001. Lease operating
expense was $1.68 per Mcfe for the nine months ended September 30, 2002, an
increase of 35% from $1.24 per Mcfe for the nine months ended September 30,
2001. The decrease in lease operating expense is primarily the result of the
sale of our Ship Shoal 58 field in June 2001 and the plugging and abandonment of
the West Cameron 531, South Marsh Island 232 and Brazos 476 wells and platforms,
where lease operations have ceased, in the fourth quarter of 2001. Additionally,
certain of our offshore properties including our High Island leases and
Galveston Island 211 were shut-in during the first and second quarter of 2002.
The decrease is also the result of the sale of certain of our Texas Gulf Coast
and all of our Louisiana properties during the second quarter of 2002. During
the nine months ended September 30, 2002, lease operating expense, calculated on
a unit of production basis increased by $0.44 per mcfe. This increase is
attributable to the 32% decline in oil and natural gas production volumes when
compared to the nine months ended June 30, 2001.
WORKOVER EXPENSE. Workover expense decreased $1,065,350, or 25%, to
$3,159,375 for the nine months ended September 30, 2002 from $4,224,725 for the
nine months ended September 30, 2001. Workover expense was $0.38 per Mcfe for
the nine months ended September 30, 2002, an increase of 9% from $0.35 per Mcfe
for the nine months ended September 30, 2001. The decrease is primarily the
result of the Company's decision to restrict the use of cash during the second
and third quarters of 2002 in anticipation of the required interest payment due
on its 12.5% Senior Secured Debt on December 1, 2002. The reduction in the
amount of workover expense incurred during the second and third quarters of 2002
contributed to the general decline in production volumes. During the nine months
ended September 30, 2002, workover expense, calculated on a unit of production
basis increased by $0.03 per mcfe. This increase is attributable to the 32%
decline in oil and natural gas production volumes when compared to the nine
months ended September 30, 2001.
PRODUCTION TAXES. Production taxes decreased by $1,004,389 or 60% to
$664,419 for the nine months ended September 30, 2002 from $1,668,808 for the
nine months ended September 30, 2001. Production taxes were $0.08 per Mcfe for
the nine months ended September 30, 2002, a decrease of 43% from $0.14 per Mcfe
for the nine months ended September 30, 2001. Decreases in oil and natural gas
production and revenues during the nine months ended September 30, 2002 resulted
in a decrease in the amount of production taxes incurred during the period.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"). DD&A expense
decreased by $4,070,539, or 39%, to $6,339,501 for the nine months ended
September 30, 2002 from $10,410,040 for the nine months ended September 30,
2001. DD&A was $0.77 per Mcfe for the nine months ended September 30, 2002, a
decrease of 10% from $0.86 per Mcfe for the nine months ended September 30,
2001. The decrease in DD&A is the result of the decrease in production volumes
during the nine months ended September 30, 2002 and the sale of certain oil and
natural gas properties during May 2002.
GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A increased $92,635, or
2%, to $4,592,620 for the nine months ended September 30, 2002 from $4,499,985
for the nine months ended September 30, 2001. G&A was $0.55 per Mcfe for the
nine months ended September 30, 2001, an increase of 50% from $0.37 per Mcfe for
the nine months ended September 30, 2001. The increase was primarily the result
of an increase in professional and consulting service fees of $993,595 and an
increase in director fees and related expenses in the amount of $225,000. This
increase was partially offset by decreases in salary, bonus and related overhead
expense of $636,893, contract labor of $242,983 and rent and relocation expense
of $111,223 during the nine months ended September 30, 2002.
INTEREST EXPENSE. Interest expense increased $6,537,269 or 47%, to
$20,342,741 for the nine months ended September 30, 2002 from $13,805,472 for
the nine months ended September 30, 2001. The increase is primarily the result
of non-cash amortization of bond discount and deferred loan costs to interest
expense of $4,671,318 and $3,895,886 respectively during the nine months ended
September 30, 2002 compared to $2,119,964 and $1,735,908 respectively during the
nine months ended September 30, 2001.
16
REORGANIZATION COSTS. We filed a voluntary petition for relief under
the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District
of Texas, Houston Division on March 14, 2000. As a result, we incurred certain
reorganization costs totaling $122,622 for the nine months ended September 30,
2002, a 99% decrease from $8,738,588 for the nine months ended September 30,
2001. These reorganization costs consist of the following:
Professional fees and other - We retained certain legal and accounting
professionals to assist with the bankruptcy proceedings and have incurred legal
and accounting fees associated with these proceedings totaling $93,901 and
$5,524,049 for the nine months ended September 30, 2002 and 2001, respectively.
Interest and amounts paid to creditors - Represents payments of amounts
owed to creditors with pre-petition claims, including interest. During the nine
months ended September 30, 2002 and 2001, $28,721 and $1,873,078, respectively
of pre-petition liabilities and interest were paid to creditors.
Retention costs - In an effort to maintain certain key employees
through the bankruptcy period, the Company incurred retention bonuses of
$301,740 during the nine months ended September 30, 2001. No retention bonuses
were incurred during the nine months ended September 30, 2002.
Interest - Interest income earned during bankruptcy has been recorded
as an offset to reorganization costs as prescribed by SOP 90-7. During the nine
months ended September 30, 2002 and 2001, none and $945,721 were offset to
reorganization costs, respectively.
Atasca transaction - As a condition of TDC's plan of reorganization,
the Company agreed to transfer all of the oil and natural gas properties owned
by Tribo Petroleum Corporation, as of May 1, 2001 at their net book values of
$1,097,547 and marketable securities with a value of $102,453, to an affiliate,
Atasca Resources, Inc. In connection with this transaction, all balances owing
to and from the Company by affiliates on May 1, 2001 were forgiven. These
balances aggregated to a net receivable from the affiliates of $785,442. As a
consequence of these transactions, the Company recorded a one-time
reorganization expense of $1,985,442 during the nine months ended September 30,
2001. No amounts were recorded as a result of this transaction during the nine
months ended September 30, 2002.
PROVISION FOR INCOME TAXES. A $212,644 provision for income tax was
made for the nine months ended September 30, 2001, primarily as a result of
alternative minimum tax requirements. No provision for federal income tax was
required for the nine months ended September 30, 2002.
LIQUIDITY AND CAPITAL RESOURCES
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35.0 million in debt outstanding. We incurred approximately $63.0
million of additional debt in connection with the Apache acquisition. In August
1998, before we were able to refinance our debt, commodity prices began falling,
with oil prices ultimately reaching a 12-year low in December of that year. The
resultant negative effect on our cash flow from the deterioration of commodity
prices, coupled with the required amortization payment on our bank loan,
severely restricted the amount of capital we were able to dedicate to
development drilling. Consequently, our oil and natural gas production declined,
further negatively affecting our cash flow. In October 1998, our loan matured
and we arranged a forbearance agreement providing for interest payments to be
partially capitalized and providing us with additional time to refinance our
obligations. In July 1999, the forbearance agreement terminated and we made
negotiated interest payments while attempting to negotiate a restructuring of
our obligations. By March 2000, the aggregate principal balance of our bank debt
had increased as a result of capitalized interest and expenses to approximately
$105.0 million. In February 2000, the bank declared the loan in default,
demanded payment of all principle and interest and posted the shares of Tribo
Petroleum Corporation, at that time our parent corporation and a guarantor of
the loan, for foreclosure. As a consequence of the bank's actions, on March 14,
2000, we filed for bankruptcy protection. After the filing, we operated as a
"debtor-in-possession," continuing in possession of our estate, the operation of
our business and the management of our properties. Under Chapter 11, certain
claims against us in existence prior to the filing of the petition were stayed
from enforcement or collection. These claims are reflected in full in the
consolidated September 30, 2002 and December 31, 2001 balance sheets as
"Accounts payable subject to renegotiation."
After we entered into bankruptcy in March 2000, commodity prices began
to recover, with natural gas prices eventually reaching historically high
levels, particularly in California. During the nine month
17
period ended September 30, 2002, the average prices we received for natural gas
and oil were $3.16 per Mcf and $24.05 per Bbl.
We filed our amended plan of reorganization in the bankruptcy court on
May 9, 2001, which provided for our exit from bankruptcy upon the completion of
a $130.0 million unit offering of senior secured notes and class A common stock.
Our plan was confirmed by a court order entered as of May 23, 2001, subject to
the completion of the offering. On June 18, 2001, the offering closed and we
exited bankruptcy. The proceeds of the offering and our available cash balances
at closing were sufficient to allow us to pay or segregate funds for the payment
of all claims in full, including interest.
During the last two quarters of 2001 and continuing into 2002,
commodity prices again declined. These price declines, coupled with production
declines beginning in the third quarter of 2001, predominately attributable to
unanticipated production declines in two wells, adversely impacted our cash
flows during the latter part of 2001 and continuing into 2002. Commodity price
hedges that we had entered into in connection with the closing of the offering
only partially offset the adverse impact on our cash flows from the decline in
commodity prices.
At September 30, 2002, we had approximately $118.1 million of 12.5%
senior secured notes outstanding. The notes mature on June 1, 2006 and require
amortization payments of the greater of $20.0 million and 15.3% as of June 1,
2002 and 2003 and an amortization payment of the greater of $15.0 million and
11.5% as of June 1, 2004. A final amortization payment of $75.0 million is due
June 1, 2006. Interest is payable semi-annually on June 1 and December 1 of each
year. On June 1, 2002, a principal payment in the amount of $20.0 million was
made on the notes reducing the outstanding balance on the notes to $110.0
million. Interest in the amount of $8.1 million was deferred until July 1, 2002.
On July 3, 2002, the Company entered into a Waiver, Agreement and Supplement
(the "Waiver") to the Indenture whereby the interest was added to the
outstanding balance of the notes, bringing the total amount of outstanding debt
to $118.1 million. In addition, the Company issued to the Noteholders 76,667
shares of Class A common stock, par value $0.01 per share. The Waiver contained
additional covenants, one of which required the Company to obtain clear title to
an oil and gas property subject to lien by no later than August 2, 2002.
Additionally, the Waiver contained additional covenants, which required the
Company to maintain minimum daily production levels of 28.5 Mmcfe of average
daily production and report $4.0 million of EBITDA, as adjusted for the non-cash
effects of oil and gas hedging contracts, as of the end of the third quarter of
2002. The Company has been unable to achieve the required daily production and
did not generate $4.0 million of EBITDA during the third quarter of 2002. As the
Company was unable to obtain clear title to an oil and gas property and to
maintain the required production levels, or to report EBITDA of $4.0 million, an
event of default occurred to the Waiver and the original Indenture whereby the
senior secured notes became due on demand. Accordingly, the senior secured notes
and related deferred loan costs have been classified as current in the
accompanying consolidated balance sheet at September 30, 2002.
At September 30, 2002, our cash balance was $2.9 million, a $1.8
million decrease from our cash balance at December 31, 2001.
Net cash provided by operating activities after reorganization items
increased $31.9 million to $14.7 million for the nine months ended September 30,
2002 compared to net cash used by operating activities after reorganization
items of $17.2 million for the nine months ended September 30, 2001. The
increase is the result of a $48.8 million decrease in net cash used in operating
activities for accounts payable subject to renegotiation and accounts payable
and accrued liabilities. Accounts payable subject to renegotiation and accounts
payable and accrued liabilities were $42.6 million at September 30, 2001
compared to $6.3 million at September 30, 2002. The Company reported a net loss
of $31.4 million for the nine months ended September 30, 2002 when compared to
net income of $21.6 million for the nine months ended September 30, 2001. During
the nine months ended September 30, 2002, we recorded a loss on the
mark-to-market value of our derivative contracts of $14.6 million. Additionally,
on June 18, 2001, we deposited $13.5 million into a restricted cash account as
required by our plan of reorganization to satisfy the payment in full of all
remaining disputed pre-petition claims. As of September 30, 2002, $11.9 million
of cash deposited into this restricted account was disbursed to us or to
claimants of pre-petition claims. At September 30, 2002, the balance in the
restricted account was $1.6 million.
Net cash provided by investing activities was $4.5 million during the
nine months ended September 30, 2002 compared to net cash used in investing
activities of $10.1 million during the nine months ended September 30, 2001. The
increase in net cash provided by investing activities is primarily
18
the result of the sale of certain oil and natural gas properties and net
realized proceeds in the amount of $6.0 million. Additionally, the company
recognized $2.3 million of proceeds from the sale of derivative contracts and
$1.6 million of cash settlements on derivative contracts during the nine months
ended September 30, 2002.
Net cash used in financing activities was $21.0 million for the nine
months ended September 30, 2002 when compared to net cash provided by financing
activities of $5.9 million during the nine months ended September 30, 2001. The
increase in net cash used in financing activities is the result of our payment
of $20.0 million of principal due on June 1, 2002.
CAPITAL REQUIREMENTS
Historically, our principal sources of capital have been cash flow from
operations, short-term reserve-based bank loans, proceeds from asset sales and
the offering of our 12.5% senior secured notes. Our principal uses for capital
have been the acquisition and development of oil and natural gas properties.
On June 1, 2002, the Company was required to make a $28,125,000 payment
of principle and interest on its senior secured notes, and an additional
scheduled interest payment of approximately $7,400,000 is due on December 1,
2002. In addition, the Company has a scheduled principal and interest payment of
approximately $28,700,000 due June 1, 2003. The Company made its scheduled
principal payment of $20,000,000 due on June 1, 2002, but refinanced its
scheduled interest payment of $8,125,000 into additional promissory notes under
the terms of a Waiver, Agreement and Supplemental Indenture (the "Waiver"). The
Waiver contained additional covenants, one of which required the Company to
obtain clear title to an oil and gas property subject to lien by no later than
August 2, 2002. Additionally, the Waiver contained covenants requiring the
Company to maintain average daily production levels of 28.5 Mmcfe per day and to
generate $4.0 million of EBITDA, as adjusted for the non-cash effects of oil and
gas hedging contracts as of the end of the third quarter of 2002. As the Company
was unable to obtain clear title by that date, did not maintain the required
production levels, and did not report $4.0 million of EBITDA, an event of
default occurred to the Waiver and the original Indenture whereby the senior
secured notes became due on demand. Accordingly, the senior secured notes and
related deferred loan costs have been classified as current in the accompanying
consolidated balance sheet at September 30, 2002. While the Company continues to
delay certain of its workover and capital improvement projects in order to
maximize available cash to meet its debt obligations, the foregoing event of
default could have a material adverse impact on the Company's ability to meet
its debt and working capital requirements. Should the noteholders demand payment
on the notes, the Company will not have the ability to generate sufficient
resources to satisfy this obligation. These conditions raise substantial doubt
about the Company's ability to continue as a going concern.
The Company is currently marketing certain of its oil and gas
properties in order to meet these scheduled debt obligations and working capital
requirements. Several offers to purchase certain of the Company's oil and gas
properties have been received to date which, if accepted, and combined with the
Company's cash balances at November 12, 2002 of approximately $4.6 million,
would provide the Company with sufficient capital to meet its upcoming December
1, 2002 scheduled debt obligation.
To the extent the cash generated from oil and gas property sales and
cash flows from continuing operations are insufficient to meet our scheduled
debt obligations and our projected working capital needs, we will have to raise
additional capital. No assurance can be given that additional funding will be
available, or if available, will be on terms acceptable to us. Uncertainty
regarding the amount and timing of any proceeds from our plans to raise
additional capital raises substantial doubt about our ability to continue as a
going concern. The accompanying consolidated financial statements do not include
any adjustments relating to the recoverability and classification of asset
carrying amounts or the amount and classification of liabilities that might be
necessary should we be unable to continue as a going concern.
19
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Revenues from our operations are highly dependent on the price of oil
and natural gas. The markets for oil and natural gas are volatile and prices for
oil and natural gas are subject to wide fluctuations in response to relatively
minor changes in the supply of and demand for oil and natural gas and a variety
of additional factors that are beyond our control, including the level of
consumer demand, weather conditions, domestic and foreign governmental
regulations, market uncertainty, the price and availability of alternative
fuels, political conditions in the Middle East, foreign imports and overall
economic conditions. It is impossible to predict future oil and natural gas
prices with any certainty. To reduce our exposure to oil and natural gas price
risks, from time to time we may enter into commodity price derivative contracts
to hedge commodity price risks.
In connection with the issuance of the senior secured notes, we agreed
to maintain, on a monthly basis, a rolling two-year hedge program until the
maturity of the notes, subject to certain conditions. In March 2002, we
terminated certain of our price swap derivatives contracts and replaced them
with contracts providing for price floors at the prices specified under the
terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50
per barrel of crude oil.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, FASB issued Statement of Financial Accounting Standards
("SFAS") No. 141, Business Combinations (SFAS No. 141), and No. 142, Goodwill
and Other Intangible Assets (SFAS No. 142). SFAS 141 requires the use of the
purchase method of accounting and prohibits the use of the pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001.
SFAS No. 141 required the Company to recognize acquired intangible assets apart
from goodwill if the acquired intangible assets meet certain criteria. SFAS No.
141 applies to all business combinations initiated after June 30, 2001, and for
purchase business combinations completed on or after July 1, 2001. SFAS No. 141
also requires upon adoption of SFAS No. 142 that the Company reclassify the
carrying amounts of intangible assets and goodwill based on the criteria in SFAS
No. 141. SFAS No. 142 requires that companies no longer amortize goodwill, but
instead test goodwill for impairment at least annually. In addition, SFAS No.
142 requires that the Company identify reporting units for the purposes of
assessing potential future impairments of goodwill and to reassess the
amortization of intangible assets with an indefinite useful life. An intangible
asset with an indefinite useful life should be tested for impairment in
accordance with SFAS No. 142. SFAS No. 142 is required to be applied in fiscal
years beginning after December 15, 2001 to all goodwill and other intangible
assets recognized at that date, regardless of when those assets were initially
recognized. SFAS No. 142 requires the Company to complete a transitional
goodwill impairment test six months from the date of adoption. The Company is
also required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. The adoption of SFAS No. 141
and SFAS No. 142 did not materially impact the Company's financial position and
results of operations.
In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations ("SFAS No. 143"). SFAS No. 143 amends SFAS No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies, and is applicable
to all companies. SFAS No. 143, which is effective for fiscal years beginning
after June 15, 2002, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal obligations associated
with the retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived asset,
except for certain obligations of lessees. As used in SFAS No. 143, a legal
obligation is an obligation that a party is required to settle as a result of an
existing or enacted law, statue, ordinance, or written or oral contract or by
legal construction of a contract under the doctrine of promissory estoppel.
While the Company is not yet required to adopt SFAS No. 143, it is not believed
the adoption will have a material effect on its financial condition or results
of operations.
In August 2001, FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-lived Assets ("SFAS No. 144"). SFAS No. 144, which
supercedes SFAS No. 121, Accounting for the Impairment of Long-lived Assets and
Long-lived Assets to be Disposed Of and amends Accounting Research Bulletin No.
51, Consolidated Financial Statements, addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. SFAS No. 144 is
effective for fiscal years beginning after December 15, 2001, and interim
financials within those fiscal years, with early adoption
20
encouraged. The provisions of SFAS No. 144 are generally to be applied
prospectively. The Company does not believe the adoption of SFAS No. 144 will
have a material effect on its financial condition or results of operations.
In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the current requirement that gains and
losses on debt extinguishment must be classified as extraordinary items in the
income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS No. 145 eliminates an inconsistency in lease accounting by
requiring that modifications of capital leases that result in reclassification
as operating leases be accounted for consistent with sale-leaseback accounting
rules. The statement also contains other nonsubstantive corrections to
authoritative accounting literature. The changes related to debt extinguishment
will be effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting will be effective for transactions occurring after
May 15, 2002. Adoption of this standard will not have any immediate effect on
our consolidated financial statements. The Company will apply this guidance
prospectively.
On June 20, 2002, FASB's Emerging Issues Task Force (EITF) reached a
partial consensus on Issue No. 02-03, Recognition and Reporting of Gains and
Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities, and No.
00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue
No. 98-10. The EITF concluded that, effective for periods ending after July 15,
2002, mark-to-market gains and losses on energy trading contracts (including
those to be physically settled) must be retroactively presented on a net basis
in earnings. In addition, companies must disclose volumes of physically-settled
energy trading contracts. The Company is evaluating the impact of this new
consensus on the presentation of its consolidated income statement but believes
it will not have a material impact on total revenues and expenses. The consensus
will have no impact on net income.
In June 2002, FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which addresses accounting for restructuring
and similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally Emerging Issues Task Force (EITF) Issue No. 94-3. The Company will
adopt the provisions of SFAS No. 146 for restructuring activities initiated
after December 31, 2002. SFAS No. 146 requires that the liability for costs
associated with an exit or disposal activity be recognized when the liability is
incurred. Under EITF No. 94-3, a liability for an exit cost is recognized at the
date of a company's commitment to an exit plan. SFAS No. 146 also establishes
that the liability should initially be measured and recorded at fair value.
Accordingly, SFAS No. 146 may affect the timing of recognizing future
restructuring costs as well as the amount recognized. Adoption of this standard
will not have any immediate effect on our consolidated financial statements. The
Company will apply this guidance prospectively.
CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES
The Securities and Exchange Commission recently issued disclosure
guidance for "critical accounting policies." The SEC defines critical accounting
policies as those that require application of management's most difficult,
subjective or complex judgments, often as a result of the need to make estimates
about the effect of matters that are inherently uncertain and may change in
subsequent periods.
Our significant accounting policies are described in Note 3 in the
Notes to Consolidated Financial Statements. Not all of these significant
accounting policies require management to make difficult, subjective or complex
judgments or estimates. However, the following policies could be deemed to be
critical within the SEC definition.
Oil and Natural Gas Interests
Full Cost Method - The Company uses the full cost method of accounting
for exploration and development activities as defined by the SEC. Under this
method of accounting, the costs for unsuccessful, as well as successful,
exploration and development activities are capitalized as properties and
equipment. This includes any internal costs that are directly related to
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar
21
activities. The sum of net capitalized costs and estimated future development
and abandonment costs of oil and gas properties and mineral investments are
amortized using the unit-of-production method.
Proved Reserves - Proved oil and gas reserves are the estimated
quantities of natural gas, crude oil and condensate that geological and
engineering data demonstrate with reasonable certainty can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reserves are considered "proved" if they can be produced
economically as demonstrated by either actual production or conclusive formation
tests. Reserves which can be produced economically through application of
improved recovery techniques are included in the "proved" classification when
successful testing by a pilot project or the operation of an installed program
in the reservoir provides support for the engineering analysis on which the
project or program was based. "Proved developed" oil and gas reserves can be
expected to be recovered through existing wells with existing equipment and
operating methods. The Company emphasizes that the volumes of reserves are
estimates, which, by their nature, are subject to revision. The estimates are
made using all available geological and reservoir data as well as production
performance data. These estimates, made by the Company's engineers, are reviewed
and revised, either upward or downward, as warranted by additional data.
Revisions are necessary due to changes in assumptions based on, among other
things, reservoir performance, prices, economic conditions and governmental
restrictions. Decreases in prices, for example, may cause a reduction in some
proved reserves due to uneconomic conditions.
Ceiling Test - Companies that use the full cost method of accounting
for oil and gas exploration and development activities are required to perform a
ceiling test. The full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book
value of oil and gas properties. That limit is basically the after tax present
value of the future net cash flows from proved crude oil and natural gas
reserves. This ceiling is compared to the net book value of the oil and gas
properties reduced by any related deferred income tax liability. If the net book
value reduced by the related deferred income taxes exceeds the ceiling, an
impairment or non-cash write down is required. A ceiling test impairment can
give us a significant loss for a particular period; however, future DD&A expense
would also be reduced. Estimates of future net cash flows from proved reserves
of gas, oil and condensate are made in accordance with SFAS No. 69, "Disclosures
about Oil and Gas Producing Activities."
Derivative Financial Instruments
As a condition of the bond indenture agreement, the Company entered
into commodity price swap derivative contracts and price floor contracts to
manage price risk with regard to 80% of its natural gas and crude oil
production.
Statement of Accounting Financial Standards No. 133 (SFAS No. 133),
"Accounting for Derivative Instruments and Hedging Activities", as amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB No. 133", and SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
was effective for the Company as of January 1, 2001. SFAS No. 133 requires that
an entity recognize all derivatives as either assets or liabilities measured at
fair value. The accounting for changes in the fair value of a derivative depends
on the use of the derivative. Derivatives that are not hedges must be adjusted
to fair value through income. If the derivative is designated as a hedge and
qualifies for hedge accounting, changes in the fair value of derivatives will
either be offset against the change in fair value of the hedged assets,
liabilities, or firm commitments through earnings or recognized in other
comprehensive income until the hedged item is recognized in earnings. The
ineffective portion of a derivative's change in fair value will be immediately
recognized in earnings.
Use of Estimates
The financial statements have been prepared in conformity with
accounting principles generally accepted in the United States of America,
appropriate in the circumstances. In preparing financial statements, management
makes informed judgments and estimates that affect the reported amounts of
assets and liabilities as of the date of the financial statements and affect the
reported amounts of revenues and expenses during the reporting period. Actual
results may differ from these estimates.
22
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Derivative Instruments Used In Our Production
We have entered into a combination of natural gas and crude oil price
swap and price floor derivative agreements with counterparties to manage
commodities price risk associated with a portion of our production. These
derivatives are not held for trading purposes. Under the price swap derivative
agreements, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market index, such
as the NYMEX natural gas and crude oil futures. Under the price floor
agreements, we have purchased the right to obtain a minimum fixed price on a
notional quantity of natural gas and crude oil. We entered into no commodities
price swaps or price floor agreements covering production in the first six
months of 2001. On March 31, 2002, we terminated certain of our price swap
derivative contracts and replaced them with price floors at prices specified
under the terms of the senior secured notes of $2.75 per MMBtu of natural gas
and $18.50 per barrel of crude oil. Proceeds from the sale of the price swap
contracts were approximately $ 2.3 million. The purchase price of the price
floor contracts of approximately $1.8 million has been financed by the Company's
derivative contracts counterparty. The following table reflects the production
volumes and the weighted average prices under our commodities price swaps, which
remain in place at September 30, 2002:
NYMEX SWAPS
----------------------------------------------
QUARTER ENDING VOLUME NYMEX PRICE
----------------------------------------------
MMcf MBbl $/Mmbtu $/Bbl
- ---------------------------------------------------------------------------------
Dec. 31, 2002 - 70 - 25.30
Mar. 31, 2003 - - - -
Jun. 30, 2003 - - - -
Sep. 30, 2003 708 179 3.27 22.33
Dec. 31, 2003 708 177 3.44 20.69
Mar. 31, 2004 462 115 3.36 20.97
Jun. 30, 2004 711 152 3.67 23.01
Sep. 30, 2004 718 153 3.58 22.99
- ----------------------------------------------------------------------------------------
The prices presented above are averages for each of the quarters indicated.
The following table sets forth the production volumes, which are
protected with price floors of $2.75 per MMBtu of natural gas and $18.50 per
barrel of crude oil as of September 30, 2002:
NYMEX FLOORS
---------------------
QUARTER ENDING VOLUME
---------------------
MMcf MBbl
- ----------------------------------------------------------
Dec. 31, 2002 1,320 146
Mar. 31, 2003 909 173
Jun. 30, 2003 909 173
Sep. 30, 2003 919 175
Dec. 31, 2003 919 175
Mar. 31, 2004 703 150
Jun. 30, 2004 - -
Sep. 30, 2004 - -
- -------------------------------------------------------------------
23
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The term "disclosure controls and procedures" is defined in Rule
13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term
refers to the controls and procedures of a company that are designed to ensure
that information required to be disclosed by a company in the reports that it
files under the Exchange Act is recorded, processed, summarized and reported
within required time periods. Our Chief Executive Officer and our Chief
Financial Officer have evaluated the effectiveness of our disclosure controls
and procedures as of a date within 90 days before the filing of this quarterly
report, and have concluded that as of that date, our disclosure controls and
procedures were effective at ensuring that required information will be
disclosed on a timely basis in our reports filed under the Exchange Act.
Changes in Internal Controls
We maintain a system of internal controls that is designed to provide
reasonable assurance that our books and records accurately reflect our
transactions and that our established policies and procedures are followed.
There were no significant changes to our internal controls or in other factors
that could significantly affect our internal controls subsequent to the date of
their evaluation by our Chief Executive Officer and Chief Financial Officer,
including any corrective actions with regard to significant deficiencies and
material weaknesses.
24
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are party to litigation or other legal
proceedings that we consider to be a part of the ordinary course of our
business. Other than as set forth below, we are not involved in any legal
proceedings nor are we party to any pending or threatened claims that could
reasonably be expected to have a material adverse effect on our financial
condition, cash flow or results of operations.
Disputes with Richard Bowman and Affiliates
On August 9, 2002, shareholder and former Chief Executive Officer
Richard Bowman ("Bowman") filed suit against the Company, certain members of its
board of directors, and Jefferies & Company, Inc. ("Jefferies") in the District
Court of Harris County, Texas 55th Judicial District (the "Court"). The suit
alleges that the Company, certain members of the Company's board of directors
and Jefferies violated fiduciary duties to the Company's shareholders by
entering into the Waiver (see Note 2 to the consolidated financial statements)
to the Indenture. The suit further alleges that the Company's board members in
concert with Jefferies entered into the Waiver with the intended effect of
diluting Bowman below a 50% ownership in the Company and effectively transferred
significant properties to the bondholders as a security interest. Bowman's
original petition sought to temporarily restrain the Company's ability to hold
an Annual Meeting of its Shareholders, scheduled for August 9, 2002 whereby its
Shareholders were solicited to vote on Director Nominees and the issuance of
additional common shares (see Item 4 - Submission of Matters to a Vote of
Security Shareholders) and seeks to rescind the Waiver declaring it void and
excusing all parties from all obligations under the agreement. The Company
intends to vigorously defend against Bowman's claims of breach of fudiciary
responsibility and the rescinsion of the Waiver. The Company has also filed
claims in the lawsuit, including counterclaims against Bowman and third-party
claims against Atasca Resources, Inc. ("Atasca"), Tribo Production Company
("Tribo Production"), and Lovett Properties, Ltd. ("Lovett"), three entities
owned and controlled by Bowman. The claims against Bowman allege primarily
breaches by Bowman of fiduciary duties owed to the Company. The claims against
Atasca relate to disputes concerning Bowman's actions with respect to a certain
gas well known as the Champion 1-H well in Grimes County. The claims against
Tribo Production and Lovett relate to the lease of the Company's corporate
office, which is leased from these Bowman affiliates. The Company alleges that
Bowman's actions with respect to the lease and the Champion well were violations
of his fiduciary duties, and alleges that Bowman has improperly used and
diverted corporate funds for his own benefit and for the benefit of his
affiliates. The Company seeks relief from Bowman's request to rescind the
Waiver, actual and punitive damages, equitable reformation of the lease with
Bowman's affiliates along with all costs and attorney fees.
In late August, the Company was served in another lawsuit filed by
Bowman affiliate Atasca in the District Court of Grimes County, Texas 278th
Judicial District (the "Court") for declaratory judgment. That suit seeks
judicial intervention in determining the ownership of interests in the Champion
1-H well. The Company has requested transfer of this lawsuit so that it can be
combined into the pending action in Harris County.
Bankruptcy filing
On March 14, 2000, we filed a voluntary petition under Chapter 11 of
the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern
District of Texas, Houston Division. We filed our amended plan of reorganization
in the bankruptcy proceeding on May 9, 2001. Our plan provided for payment in
cash, or segregation of funds for the payment, to each creditor of its full,
allowed claim, including interest, on the closing date of the original offering.
Our plan was confirmed by a court order on May 23, 2001, subject to the
completion of the offering of the old notes. Upon the closing of the offering,
we paid or segregated funds for the payment of all allowed claims in accordance
with our plan and the court order and, except as specifically discussed below,
lawsuits, administrative actions and other proceedings that arose prior to the
confirmation were dismissed as to us. Claims that we dispute will be heard by
the bankruptcy court. If claims are resolved for less than the amount segregated
by us, we will receive the balance of the funds.
Chieftain International
On March 31, 1999, Chieftain International (U.S.), Inc. ("Chieftain")
filed suit against us in the United States District Court for the Eastern
District of Louisiana (the "District Court") alleging that we
25
owed certain joint interest expenses in the approximate amount of $3.0 million,
together with accrued interest, attorney's fees, and costs, in connection with
Chieftain's operation of two offshore mineral leases. Chieftain took no action
with regard to its lawsuit during our bankruptcy, as the litigation in the
District Court was stayed pursuant to 11 U.S.C. Section 362. Since emerging from
bankruptcy, Chieftain successfully re-opened the litigation in the District
Court and has claimed that we now owe approximately $5.1 million, together with
accrued interest, attorneys' fees, and costs. However, pursuant to our confirmed
plan of reorganization, approximately $5.5 million was segregated in an interest
bearing account pending the trial and/or non-judicial resolution of our dispute
with Chieftain. On April 17, 2002, we entered into an agreement with Chieftain
to stay the litigation for a six-month period in which we will conduct an audit
of Chieftain's books and records relating to the litigation. However, $5 million
of the funds segregated pending the trial and/or non-judicial resolution of our
dispute with Chieftain was transferred to Chieftain prior to the commencement of
our audit. We have and will continue to maintain $500,000 in the segregated
account pending a resolution of the audit, but all additional funds in the
segregated account due to interest accumulation will be distributed to us. If
Chieftain's lawsuit is not successfully resolved in the audit process, the
lawsuit will be reopened in the District Court and any of Chieftain's remaining
claims will be litigated, along with our counterclaims against Chieftain for
conducting operations in an imprudent manner.
Arch W. Helton, Helton Properties, Inc., and Linda Barnhill
On May 28, 1997, Arch W. Helton and Helton Properties, Inc., filed suit
against us in the 80th Judicial District Court of Harris County, Texas.
Subsequently, Linda Barnhill joined as a plaintiff. The suit alleges that we owe
additional royalties on oil and natural gas produced from February 1987 to date
as to certain completions in oil and natural gas properties located in Alvin,
Texas, that oil and natural gas was drained from approximately 18 acres in which
they claim interests and seeks the recovery of attorneys' fees. As to certain of
the plaintiffs' claims, we have obtained a favorable decision from the Texas
Railroad Commission. An appeal of the decision by the plaintiffs is currently
pending. We believe the decision will be affirmed and that, if affirmed, it
could result in the full avoidance of all of the plaintiffs' claims. Even if the
decision is not affirmed, we believe we have other defenses that could result in
the full avoidance of the claims. We have filed a partial summary judgment on
limitations and other defenses that is currently pending. We intend to continue
to vigorously defend this suit. Funds in the amount of approximately $1.0
million have been segregated in accordance with our plan pending the resolution
of this dispute by the bankruptcy court. We believe these funds are sufficient
to cover our net interest in the full proof of claim filed in the amount of $3.0
million.
ITEM 2. CHANGES IN SECURITIES
On July 3, 2002, the Company issued 76,667 shares of its class A common
stock, par value $0.01 per share to the holders of its 12.5% senior secured
notes. The issuance of the additional shares of class A common stock resulted in
a change of control with respect to beneficial ownership of our common stock. An
aggregate of 510,000 shares of our common stock were issued and outstanding at
July 3, 2002 consisting of 445,000 shares of class A common stock and 65,000
shares of class B common stock. Of these shares, Richard Bowman, our former
President and Chief Executive Officer, owns 238,333 shares of class A common
stock and no shares of class B common stock, or 47% of our common stock. The
holders of the senior secured notes hold an aggregate of 206,667 shares of class
A common stock and Jefferies & Company, Inc. holds an aggregate of 65,000 shares
of class B common stock, or 53% of our common stock. Prior to the July 3, 2002
issuance of an additional 76,667 shares of class A common stock, Richard Bowman
owned 55% of the issued and outstanding shares of common stock. As a result of
the aforementioned changes in securities and the resulting change in control,
federal tax laws may restrict the Company's ability to utilize its net operating
loss carryforward's.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
The Company issued 130,000 units including $130,000,000 in aggregate
principal amount of its 12.5% Series A Senior Secured Notes due 2006 on June 18,
2001, and it subsequently exchanged the units for an equal principal amount of
notes in an exchange registered with the Securities and Exchange Commission, as
defined in the Indenture. On June 3, 2002, the Company timely made a $20,000,000
aggregate principal payment due under the terms of the notes but did not make a
$8,125,000 aggregate accrued cash interest payment due on the notes, which was
also due on June 3, 2002. The Company had advised the noteholders that it had
insufficient funds to make the June 3, 2002 interest payment, which would result
in an event of default under the Indenture on July 3, 2002. As a result, the
Company
26
requested that the noteholders agree to permit the Company to make the June 1,
2003 interest payment due on the notes, plus the interest due on such interest,
through the issuance of additional promissory notes (the "New Notes") with terms
identical to the terms of the Series A Notes. The New Notes will not immediately
be registered under the Securities Act of 1933 and will not be freely tradable
until such time as a registration statement with respect to the exchange of the
New Notes has been declared effective by the Securities and Exchange Commission.
In August, 2002, the Company notified the holders of its senior secured
notes that it did not obtain clear title to the Champion #1-H well in the 30 day
period required pursuant to the Waiver. The failure to obtain clear title to the
Champion #1-H well constitutes an event of default pursuant to the terms of the
Waiver and the Indenture. Additionally, in September 2002, the Company notified
the holders of its senior secured notes that EBITDA, as adjusted to exclude the
non-cash effects of oil and gas hedging contract, as of the end of the third
quarter of 2002 was less than $4.0 million and average daily production had
fallen below 28.5 Mmcfe per day.
If any event of default occurs and not cured, the noteholders may by
notice to the Company, declare all the notes then outstanding to be due and
payable upon demand. Although no such declaration or demand has been made upon
the Company, the senior secured notes have been classified as current in the
accompanying consolidated balance sheet at September 30, 2002.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company held an annual meeting of its shareholders on September 10,
2002. At the meeting, the shareholders voted on the election of five directors
and a proposal to approve an amendment of the Company's Articles of
Incorporation to increase the number of authorized shares of common stock from
510,000 to 2,510,000. An amendment to the Articles of Incorporation requires the
affirmative vote of two-thirds of the outstanding class A common stock and class
B common stock voting together as a single class and the affirmative vote of
two-thirds of the outstanding class B common stock voting as a separate class.
The Company received proxies covering 510,000 shares of its outstanding common
stock, representing 100% of such shares. There were no abstentions or non-votes
on any proposals voted on at the meeting. Directors are elected by a plurality
vote of the class A common stock and the class B common stock present at the
meeting, voting together as a single class.
Five directors, constituting the entire board of directors, were elected at the
meeting to serve until the next annual meeting of shareholders. The voting was
as follows:
Votes
-----------------------------------------------------
Nominee For Against Withheld
------- -------------- -------------- --------------
G. Bryan Dutt (Chairman) 271,667 238,333 none
Donald W. Riegle 271,667 238,333 none
Oliver G. Richard 271,667 238,333 none
David L. Ducote 271,667 238,333 none
James M. Trimble 271,667 238,333 none
Messrs. Dutt, Riegle and Richard have served as directors since June 2001. Mr.
Ducote joined the board in July 2002 following the resignation of Michel T.
Halbouty. On June 13, 2002, our Chief Executive Officer and President, Richard
Bowman, resigned his positions and was replaced by James M. Trimble, effective
July 19, 2002. Mr. Bowman, who is no longer a board member, retains
approximately 47% of the Company's outstanding common stock.
The vote on the amendment of the Company's Articles of Incorporation to
increase the number of authorized share of common stock was not approved. Of the
510,000 shares voting on this matter, 271,667 shares, or approximately 53% voted
for approval and 238,333 shares, or approximately 47% for against. No votes were
withheld.
27
ITEM 5. FORWARD LOOKING STATEMENTS
Certain information included in this report, other materials filed or
to be filed by the Company with the Securities and Exchange Commission, as well
as information included in oral statements or written statements made or to be
made by the Company contain or incorporate by reference certain statements
(other than statements of historical fact) that constitute forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Statements that are not
historical facts contained in this report are forward-looking statements that
involve risks and uncertainties that could cause actual results to differ from
projected results. Such statements may include activities, events or
developments that the Company expects, believes, projects, intends or
anticipates will or may occur, including such matters as future capital,
development and exploration opportunities, reserve estimates (including
estimates of future net revenues associated with such reserves and the present
value of such future net revenues), future production of oil and natural gas,
business strategies, property acquisition and sales, and anticipated liquidity.
Factors that could cause actual results to differ materially ("Cautionary
Disclosures") are described, among other places, in the Company's Form 10-K.
Without limiting the Cautionary Disclosures so described, Cautionary Disclosures
include, among others: general economic conditions, the market price of oil and
natural gas, the risks associated with exploration, the Company's ability to
find, acquire, market, develop and produce new properties, operating hazards
attendant to the oil and gas business, uncertainties in the estimation of proved
reserves and in the projection of future rates of production and timing of
development expenditures, the strength and financial resources of the Company's
competitors, the Company's ability to find and retain skilled personnel,
climatic conditions, labor relations, availability and cost of material and
equipment, environmental risks, the results of financing efforts and regulatory
developments. All written and oral forward-looking statements attributable to
the Company or persons acting on its behalf are expressly qualified in their
entirety by the Cautionary Disclosures. The Company disclaims any obligation to
update or revise any forward-looking statement to reflect events or
circumstances occurring hereafter or to reflect the occurrence of anticipated or
unanticipated events.
28
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
2.1 Debtor's First Amended Plan of Reorganization approved on May 23, 2001 by the United States Bankruptcy Court for
the Southern District of Texas, Houston Division(1)
2.2 Agreement and Plan of Merger between Tribo Petroleum Corporation and Tri-Union Development Corporation, dated July
27, 2001(1)
3.1 Restated Articles of Incorporation for Tri-Union Development Corporation, as amended through July 2001.(1)
3.2 By-laws of Tri-Union Development Corporation as amended and restated through June 18, 2001.(1)
3.3 Certificate of Incorporation for Tri-Union Operating Company dated as of November 1, 1974, as amended through May
30, 1996.(1)
3.4 By-laws of Tri-Union Operating Company as amended and restated through June 18, 2001.(1)
4.1 Indenture Agreement by and between Tri-Union Development Corporation, as Issuer, Tribo Petroleum Corporation, as
Parent Guarantor, and Firstar Bank, National Association, as Trustee, dated June 18, 2001.(1)
4.2 Purchase Agreement between Tribo Petroleum Corporation, Tri-Union Development Corporation, Tri-Union Operating
Company and Jefferies & Company, Inc., dated June 18, 2001.(1)
4.3 Registration Rights Agreement by and among Tri-Union Development Corporation, Tri-Union Operating Company, Tribo
Petroleum Corporation and Jefferies & Company, Inc., dated June 18, 2001.(1)
4.4 Equity Registration Rights Agreement by and between Tribo Petroleum Corporation and Jefferies & Company, Inc.,
dated June 18, 2001.(1)
4.5 Intercreditor and Collateral Agency Agreement among Tri-Union Development Corporation, Tribo Petroleum Corporation,
Tri-Union Operating Company and Wells Fargo Bank Minnesota, National Association, as Collateral Agent, and Firstar
Bank, National Association, as Trustee, dated June 18, 2001.(1)
4.6 Pledge and Collateral Account Agreement among Wells Fargo Bank Minnesota, National Association, as Collateral
Agent, Tribo Petroleum Corporation, Tri-Union Development Corporation and Tri-Union Operating Company, as Obligors,
dated June 18, 2001.(1)
4.7 Mortgage, Deed of Trust, assignment of Production, Security Agreement and Financing Statement of Tri-Union
Development Corporation, dated June 18, 2001.(1)
4.8 Waiver, Agreement and Supplemental Agreement dated as of July 3, 2002 by and among Tri-Union Development
Corporation, each of the Guarantors party thereto, U.S. Bank National Association, formerly known as Firstar Bank
National Association, Jefferies & Company, Inc. and each of the noteholders party thereto, filed as a comparably
numbered Exhibit to the June 30, 2002 Report on Form 10-Q.
10.1 Amended and Restated Lease Agreement between Tribo Production Company, Ltd. and Tri-Union Development Corporation
dated June 18, 2001.(1)
10.2 ISDA Master Agreement by and between Bank of America, N.A. and Tri-Union Development Corporation, dated June 18,
2001.(1)
16.1 Letter of Hidalgo, Banfill, Zlotnik & Kermali, P.C.(1)
21.1 Subsidiaries of Registrant.(1)
99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
(1) Incorporation by reference to the comparably numbered Exhibit to the
Registration Statement on Form S-4 filed by the Issuer November 2, 2001.
29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TRI-UNION DEVELOPMENT CORPORATION
November 19, 2002 By: /s/ James M. Trimble
- ----------------- -----------------------------------------
James M. Trimble, Chief Executive Officer
and President
By: /s/ Suzanne R. Ambrose
-----------------------------------------
Suzanne R. Ambrose, Vice President
and Chief Financial Officer
30
Certification of Chief Executive Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350)
I, James M. Trimble, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Tri-Union
Development Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions and about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls, which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 19, 2002
---------------------------------------
/s/ James M. Trimble
- ------------------------------------------------
James M. Trimble
President and Chief Executive Officer
31
Certification of Chief Financial Officer
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350)
I, Suzanne R. Ambrose, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Tri-Union
Development Corporation;
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions and about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls, which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 19, 2002
-----------------------------------------------
/s/ Suzanne R. Ambrose
- ------------------------------------------------
Suzanne R. Ambrose
Vice President and Chief Financial Officer
32
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
2.1 Debtor's First Amended Plan of Reorganization approved on May 23, 2001 by the United States Bankruptcy Court for
the Southern District of Texas, Houston Division(1)
2.2 Agreement and Plan of Merger between Tribo Petroleum Corporation and Tri-Union Development Corporation, dated July
27, 2001(1)
3.1 Restated Articles of Incorporation for Tri-Union Development Corporation, as amended through July 2001.(1)
3.2 By-laws of Tri-Union Development Corporation as amended and restated through June 18, 2001.(1)
3.3 Certificate of Incorporation for Tri-Union Operating Company dated as of November 1, 1974, as amended through May
30, 1996.(1)
3.4 By-laws of Tri-Union Operating Company as amended and restated through June 18, 2001.(1)
4.1 Indenture Agreement by and between Tri-Union Development Corporation, as Issuer, Tribo Petroleum Corporation, as
Parent Guarantor, and Firstar Bank, National Association, as Trustee, dated June 18, 2001.(1)
4.2 Purchase Agreement between Tribo Petroleum Corporation, Tri-Union Development Corporation, Tri-Union Operating
Company and Jefferies & Company, Inc., dated June 18, 2001.(1)
4.3 Registration Rights Agreement by and among Tri-Union Development Corporation, Tri-Union Operating Company, Tribo
Petroleum Corporation and Jefferies & Company, Inc., dated June 18, 2001.(1)
4.4 Equity Registration Rights Agreement by and between Tribo Petroleum Corporation and Jefferies & Company, Inc.,
dated June 18, 2001.(1)
4.5 Intercreditor and Collateral Agency Agreement among Tri-Union Development Corporation, Tribo Petroleum Corporation,
Tri-Union Operating Company and Wells Fargo Bank Minnesota, National Association, as Collateral Agent, and Firstar
Bank, National Association, as Trustee, dated June 18, 2001.(1)
4.6 Pledge and Collateral Account Agreement among Wells Fargo Bank Minnesota, National Association, as Collateral
Agent, Tribo Petroleum Corporation, Tri-Union Development Corporation and Tri-Union Operating Company, as Obligors,
dated June 18, 2001.(1)
4.7 Mortgage, Deed of Trust, assignment of Production, Security Agreement and Financing Statement of Tri-Union
Development Corporation, dated June 18, 2001.(1)
4.8 Waiver, Agreement and Supplemental Agreement dated as of July 3, 2002 by and among Tri-Union Development
Corporation, each of the Guarantors party thereto, U.S. Bank National Association, formerly known as Firstar Bank
National Association, Jefferies & Company, Inc. and each of the noteholders party thereto, filed as a comparably
numbered Exhibit to the June 30, 2002 Report on Form 10-Q.
10.1 Amended and Restated Lease Agreement between Tribo Production Company, Ltd. and Tri-Union Development Corporation
dated June 18, 2001.(1)
10.2 ISDA Master Agreement by and between Bank of America, N.A. and Tri-Union Development Corporation, dated June 18,
2001.(1)
16.1 Letter of Hidalgo, Banfill, Zlotnik & Kermali, P.C.(1)
21.1 Subsidiaries of Registrant.(1)
99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
(1) Incorporation by reference to the comparably numbered Exhibit to the
Registration Statement on Form S-4 filed by the Issuer November 2, 2001.