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U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 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
HOUSTON, TEXAS 77006
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(713) 533-4000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
INDICATE BY CHECK MARK WHETHER THE REGISTRANT: (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS.
yes x no
--- ----
AS OF AUGUST 14, 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 Six Months Ended
June 30, 2002 and 2001 (unaudited)......................................... 3
Consolidated Balance Sheets at June 30, 2002 (unaudited) and
December 31, 2001 (audited)................................................ 4
Consolidated Statements of Cash Flows for the Six Months Ended
June 30, 2002 and 2001 (unaudited)......................................... 5
Notes to Consolidated Financial Statements (unaudited)..................... 6
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 10
Item 3.Quantitative and Qualitative Disclosure about Market Risk.................... 21
Part II. Other Information
Item 1. Legal Proceedings.......................................................... 22
Item 2. Changes in Securities...................................................... 23
Item 3. Defaults Upon Senior Securities............................................ 23
Item 4. Submission of Matters to a Vote of Security Holders........................ 23
Item 5. Forward Looking Statements................................................. 24
Item 6. Exhibits and Reports on Form 8-K........................................... 25
Signatures ................................................................................. 26
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 Six Months Ended
June 30, June 30,
---------------------------- ----------------------------
2002 2001 2002 2001
------------ ------------ ------------ ------------
Revenues and other:
Oil and natural gas revenues $ 10,372,102 $ 22,259,265 $ 21,682,755 $ 54,666,487
Loss on marketable securities -- (90,817) -- (417,180)
Gain (loss) on derivative contracts (2,285,898) 3,586,626 (14,233,590) 3,586,626
Other 1,486,944 839,155 2,456,329 896,922
------------ ------------ ------------ ------------
Total revenues and other 9,573,148 26,594,229 9,905,494 58,732,855
------------ ------------ ------------ ------------
Expenses:
Lease operating expense 5,204,035 5,027,990 9,956,609 10,480,429
Workover expense 504,706 1,719,295 2,456,602 3,340,129
Production taxes 248,333 572,679 477,855 1,341,576
Depreciation, depletion and amortization 2,069,418 3,523,930 4,564,682 7,262,043
General and administrative expenses 1,401,154 1,506,985 2,600,687 3,149,231
Interest expense 6,790,577 3,164,275 13,944,506 6,276,250
------------ ------------ ------------ ------------
Total expenses 16,218,223 15,515,154 34,000,941 31,849,658
------------ ------------ ------------ ------------
Income (loss) before reorganization costs and
income taxes (6,645,075) 11,079,075 (24,095,447) 26,883,197
Reorganization costs 48,298 6,587,700 139,161 7,311,108
------------ ------------ ------------ ------------
Income (loss) before income taxes (6,693,373) 4,491,375 (24,234,608) 19,572,089
Provision for income taxes -- 91,442 -- 391,442
------------ ------------ ------------ ------------
Net income (loss) $ (6,693,373) $ 4,399,933 $(24,234,608) $ 19,180,647
============ ============ ============ ============
Net income (loss) per share - basic and diluted $ (15.45) $ 16.53 $ (55.93) $ 76.01
============ ============ ============ ============
Weighted average shares outstanding - basic
and diluted 433,333 266,190 433,333 252,339
============ ============ ============ ============
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
June 30, December 31,
2002 2001
(unaudited) (audited)
------------- -------------
ASSETS
Current assets:
Cash and cash equivalents $ 2,212,558 $ 4,764,545
Restricted cash 1,566,654 8,929,566
Accounts receivable, net of allowance for doubtful accounts of
$1,430,538 and $1,376,970 11,554,369 13,860,164
Prepaid expenses and other 1,290,108 1,960,104
Derivative contracts -- 9,525,317
Deferred loan costs, net 14,396,784 --
------------- -------------
Total current assets 31,020,473 39,039,696
------------- -------------
Oil and natural gas properties - full cost method, net 77,599,651 85,524,756
------------- -------------
Other assets:
Restricted cash and bonds 5,255,764 5,225,832
Furniture, fixtures and equipment, net 1,108,129 1,147,611
Receivables from affiliate, net -- 206,116
Deferred loan costs, net -- 17,034,817
Derivative contracts -- 2,973,627
Other assets 2,396,470 --
------------- -------------
Total other assets 8,760,363 26,588,003
------------- -------------
Total assets $ 117,380,487 $ 151,152,455
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY (CAPITAL DEFICIT)
Current liabilities
Accounts payable and accrued liabilities $ 21,784,698 $ 22,904,154
Accounts payable subject to renegotiation 2,174,070 5,133,667
Accrued interest 9,338,613 1,399,306
Payable to affiliate 15,748 --
Notes payable 139,327 965,875
Derivative contracts 405,262 --
Senior secured notes-in default (Notes 2 and 7) 92,418,034 20,000,000
------------- -------------
Total current liabilities 126,275,752 50,403,002
Senior Secured notes -- 89,172,434
Derivative contracts 1,968,265 --
Other liabilities 1,797,942 --
------------- -------------
Total liabilities 130,041,959 139,575,436
------------- -------------
Stockholders' equity (capital deficit):
Class A common stock, $0.01 par value, 445,000 shares authorized;
368,333 shares issued and outstanding 3,683 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 25,216,402 25,220,285
Deficit (37,882,207) (13,647,599)
------------- -------------
Total stockholders' equity (capital deficit) (12,661,472) 11,577,019
------------- -------------
Total liabilities and stockholders' equity (capital deficit) $ 117,380,487 $ 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)
Six Months Ended June 30,
-------------------------------
2002 2001
------------- -------------
Cash flows from operating activities:
Net income (loss) $ (24,234,608) $ 19,180,647
Adjustments to reconcile net income (loss) to net cash provided
by (used in) operating activities:
Depreciation, depletion and amortization 4,564,682 7,262,042
Amortization of bond discount 3,245,600 262,472
Amortization of debt issuance costs 2,661,312 206,291
Loss on sale of marketable securities -- 417,180
Accretion of bond interest (29,932) (45,606)
Loss on sale of equipment -- 7,042
Reorganization costs 139,161 7,311,108
Cash settlements on derivative contracts (2,445,829) 37,637
Loss on derivative floor contracts recognized in revenues 183,852 --
(Gain) loss on derivative contracts 14,233,590 (3,586,626)
Changes in assets and liabilities:
Restricted cash 7,362,912 (13,566,895)
Accounts receivable 4,055,796 2,649,245
Prepaid expenses and other 669,995 278,518
Receivables (payables) from affiliates 221,864 (420,711)
Other assets (2,396,470) --
Accounts payable and accrued liabilities 6,742,031 (49,814,158)
Accounts payable subject to renegotiation (2,959,597) 10,119,904
------------- -------------
Net cash provided by (used in) operating activities before
reorganization items 12,014,359 (19,701,910)
------------- -------------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid (61,341) (5,819,922)
Interest earned during bankruptcy -- 945,722
------------- -------------
Net cash used in reorganization items (61,341) (4,874,200)
------------- -------------
Net cash provided by (used in) operating activities 11,953,018 (24,576,110)
------------- -------------
Cash flows from investing activities:
Purchase of marketable securities -- (159,897)
Proceeds from sale of marketable securities -- 236
Additions to oil and natural gas properties (4,188,017) (3,339,202)
Purchase of furniture, fixtures and equipment (112,119) (336,016)
Proceeds from disposal of equipment -- 6,500
Proceeds from sales of oil and natural gas properties 5,950,040 2,225,529
Cash settlements on derivative contracts 2,445,829 (37,637)
Proceeds from sale of derivative contracts 2,252,971 --
Purchase of restricted cash and bonds -- (375,000)
------------- -------------
Net cash provided by (used in) investing activities 6,348,704 (2,015,487)
------------- -------------
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) (2,303,149)
Payments on notes payable (826,548) (251,237)
------------- -------------
Net cash provided by (used in) financing activities (20,853,709) 6,566,408
Net decrease in cash and cash equivalents (2,551,987) (20,025,189)
Cash and cash equivalents - beginning of period 4,764,545 32,989,939
------------- -------------
Cash and cash equivalents - end of period $ 2,212,558 $ 12,964,750
============= =============
Supplemental Disclosures of Cash Flow Information:
Interest paid $ 18,546 $ 19,182,654
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 1,750,000 --
The accompanying notes are an integral part of these
consolidated financial statements.
5
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. In July 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, 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") (see
Note 7). 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. As the Company was unable to obtain clear title by
that date, 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 June 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 considerably impact 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 considering marketing certain of its oil and gas
properties in order to meet these 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 August 1, 2002 of approximately $1.0 million, would
provide the Company with sufficient capital to meet its upcoming December 1,
2002 scheduled debt obligation. However, to date, no definitive agreement to
sell these properties has been secured.
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 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 six months ended June 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. In the opinion of
management, all
6
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 six months
ended June 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 six months ended June 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 six months ended June 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 non-current liability in the
accompanying consolidated balance sheet at June 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 six months ended June 30, 2002, the
Company recognized approximately $184,000 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 FAS 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 June 30, 2002, the
estimated fair value of the Company's derivative contracts held represents a net
current liability of $405,262 and a net non-current liability of $1,968,265.
During the three and six months ended June 30, 2002, net cash settlements
realized from the Company's derivative contracts amounted to approximately
($128,000) and $2,446,000, respectively.
NOTE 5 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board finalized
FASB Statements No. 141, Business Combinations (SFAS 141), and No. 142, Goodwill
and Other Intangible Assets (SFAS 142). SFAS 141 requires the use of the
purchase method of accounting and prohibits the use of the pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001.
SFAS 141 also required that the Company recognize acquired intangible assets
apart from goodwill if the acquired intangible assets meet certain criteria.
SFAS 141 applies to all business combinations initiated after June 30, 2001, and
for purchase business combinations completed on or after July 1, 2001. It also
requires upon adoption of SFAS 142 that the Company reclassify the carrying
amounts of intangible assets and goodwill based on the criteria in SFAS 141.
SFAS 142 requires, among other things, that companies no longer amortize
goodwill, but instead test goodwill for impairment at least annually. In
addition, SFAS 142 requires that the Company identify reporting units for the
purposes of assessing potential future impairments of goodwill and to reassess
the amortization of intangible assets with an indefinite useful life. An
intangible asset with an indefinite useful life should be tested for impairment
in accordance with SFAS 142. SFAS 142 is required to be applied in fiscal years
beginning after December 15, 2001 to all goodwill and other intangible assets
recognized at that date, regardless of when those assets were initially
recognized. SFAS 142 requires the Company to complete a transitional goodwill
impairment test six months from the date of adoption. The Company is also
required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. The Company does not believe
the adoption of SFAS 141 and SFAS 142 will materially impact its financial
position and results of operations.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations, SFAS No. 143, which amends SFAS No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies, is applicable to
all companies. SFAS No. 143, which is effective for fiscal years
7
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, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-lived Assets. 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 ARB 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, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the current requirement that gains and
losses on debt extinguishment must be classified as extraordinary items in the
income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS 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, the FASBs 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 Issues 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. Also, 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, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities, which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3. The
Company 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 was
recognized at the date of a companys 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.
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 Field in Louisiana for $6,450,000.
Subject to the terms of the
8
sale, the Company entered into a Holdback Agreement whereby $1,750,000 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 June 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 June 2002 for a net cost to the Company
of approximately $2,400,000. Currently, the title to this well is in dispute. As
a result, the net cost to the Company is shown on the accompanying balance sheet
as other assets at June 30, 2002, pending resolution of the title dispute.
Effective May 20, 2002, the Company had received and accepted an Indication of
Interest to sell certain of its Texas and Louisiana oil and natural gas
properties. The Company subsequently determined that the terms were no longer
acceptable and the offer was refused.
NOTE 7 - SUBSEQUENT EVENTS
On July 3, 2002, (the "Effective Date") the Company entered into a Waiver,
Agreement and Supplemental Indenture (the "Waiver") in which the holders of its
senior secured notes agreed to permit the Company to make the June 1, 2002,
accrued cash interest payment due on the Notes, plus interest due on such
interest, through the issuance of additional promissory notes (the "New Notes")
with terms identical to the terms of the original notes except with respect to
the issuance date and the aggregate principal amount. In addition, the New Notes
have not immediately been registered under the Securities Act of 1933 and will
not be freely tradable until such time as a registration statement with respect
to the New Notes has been declared effective by the Securities and Exchange
Commission. The New Notes have been issued under the Indenture as Series A Notes
and as Tack-on Senior Secured Notes, and have an accreted value of $1,000 per
Note. The Company further agreed to issue to the noteholders pro rata in
accordance with their respective principal amounts of notes held, an aggregate
of 76,667 class A common shares. The value of the additional shares, which has
yet to be determined, will be recorded as debt issuance costs and amortized
using the interest method over the remaining life of the notes. Additionally,
the Company agreed to certain covenants including the following:
a) The Company will not permit EBITDA, as adjusted to exclude the
non-cash effects of any oil and natural gas hedge contracts, for
the third fiscal quarter of 2002, to be less than $4.0 million
("Base EBITDA") and, as of the end of each fiscal quarter
thereafter, to be less than Base EBITDA compounded by an additional
5%. The Company will not permit volumes of average daily production
of oil and natural gas (reported for each fiscal month) from the
oil and gas assets of the Company subject to the lien of the
Indenture to be less that 28.5 Mmcfe per day.
b) The Company will subject its entire interest in certain oil and gas
assets located in Grimes County, Texas (see Note 6), to the lien of
the Indenture and the Security Documents no later than 30 days
after the Effective Date of the Agreement.
c) On or before the Effective Date, the Company will take any or all
actions required to sever its business relationships with certain
related parties to the extent such severance can be accomplished in
a manner that is not detrimental to the Company or its subsidiary.
d) With respect to the Company's previous Chief Executive Officer and
President, the Company and its subsidiary will not enter into any
severance agreement, or allow the former to serve as an agent,
independent contractor, employee or consultant without the approval
of at least 66-2/3% in principal amount of the then outstanding
notes.
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. 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 June 30, 2002.
9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion of our results of operations and
financial condition includes the results of operations and financial condition
of our 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.
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 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 six months of 2002, our
capital expenditures on oil and gas activities totaled approximately $13.6
million, $10.9 million, $13.6 million and $4.2 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
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 six months of 2002, our development
10
capital investments of $13.6 million and $4.2 million were expended on a large
offshore recompletion, the plugging and abandonment of four offshore facilities
and the recompletion or drilling of approximately 50 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 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 June 30, 2002 Compared to Three Months Ended June 30, 2001
For the three months ended June 30, 2002, consolidated net loss
was $6,693,373 as compared to consolidated net income of $4,399,933 for the
three months ended June 30, 2001.
OIL AND GAS REVENUES. Oil and natural gas revenues decreased
$11,887,163, or 53%, to $10,372,102 for the three months ended June 30, 2002,
from $22,259,265 for the three months ended June 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. The decline in production is partially
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, the Company curtailed its workover
expenditure program during the second quarter of 2002, which further contributed
to the decline in production volumes. The following table summarizes the
consolidated results of oil and natural gas production and related pricing for
the three months ended June 30, 2002 and 2001:
For the Three Months Ended June 30,
--------------------------------------------
2002 2001 % Change
--------- ---------- ----------
Oil production volumes (Mbbls) 232 339 -32%
Gas production volumes (Mmcf) 1,477 2,264 -35
Total (Mmcfe) 2,867 4,269 -33
Average oil price (per Bbl) $24.36 $25.16 -3%
Average gas price (per Mcf) 3.20 6.07 -47
Average price (per Mcfe) 3.62 5.18 -30
LOSS ON MARKETABLE SECURITIES. We recognized $90,817 in losses on
marketable securities for the three months ended June 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. For the six months ended June
30, 2002, we held no marketable securities.
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 and 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,
11
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
estimated fair value of these contracts as of the three months ended June 30,
2002 resulted in a net non-cash loss on derivative contracts of $2,285,898 when
compared to net non-cash income on derivative contracts of $3,586,626 as of the
three months ended June 30, 2001.
OTHER. Other income increased $647,789 or 77% to $1,486,944 for
the three months ended June 30, 2002 when compared to $839,155 for the three
months ended June 30, 2001. The increase was primarily the result of the sale of
emission reduction credits from our Hastings Field in the approximate amount of
$1,457,600 during the three months ended June 30, 2002 when compared to $681,690
during the three months ended June 30, 2001. This increase was partially offset
by a decrease in interest income of $72,023 from $2,582 for the three months
ended June 30, 2002 when compared to $74,605 for the three months ended June 30,
2001.
LEASE OPERATING EXPENSE. Lease operating expense increased
$176,045, or 4%, to $5,204,035 for the three months ended June 30, 2002 from
$5,027,990 for the three months ended June 30, 2001. Lease operating expense was
$1.81 per Mcfe for the three months ended June 30, 2002, an increase of 55% from
$1.17 per Mcfe for the three months ended June 30, 2001. In addition, the
Company had a $249,305 increase in ad valorem taxes, which are expensed as lease
operating expense during the second quarter of 2002. During the three months
ended June 30, 2002, lease operating expense, calculated on a unit of production
basis increased by $0.64 per mcfe. This increase is attributable to the 33%
decline in oil and natural gas production volumes when compared to the three
months ended June 30, 2001.
WORKOVER EXPENSE. Workover expense decreased $1,214,589, or 71%,
to $504,706 for the three months ended June 30, 2002 from $1,719,295 for the
three months ended June 30, 2001. Workover expense was $0.18 per Mcfe for the
three months ended June 30, 2002, a decrease of 56% from $0.40 per Mcfe for the
three months ended June 30, 2001. The decrease is primarily the result of the
Company's decision to restrict the use of cash during the second quarter of 2002
in anticipation of the required principal and interest payment, which was due on
its 12.5% senior secured debt on June 1, 2002. The reduction in the amount of
workover expense incurred during the second quarter contributed to the general
decline in production volumes.
PRODUCTION TAXES. Production taxes decreased by $324,346 or 57%
to $248,333 for the three months ended June 30, 2002 from $572,679 for the three
months ended June 30, 2001. Production taxes were $0.09 per Mcfe for the three
months ended June 30, 2002, a decrease of 35% from $0.13 per Mcfe for the three
months ended June 30, 2001. Decreases in oil and natural gas production and
revenues during the three months ended June 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 $1,454,512, or 41%, to $2,069,418 for the three months
ended June 30, 2002 from $3,523,930 for the three months ended June 30, 2001.
DD&A was $0.72 per Mcfe for the three months ended June 30, 2002, a decrease of
12% from $0.82 per Mcfe for the three months ended June 30, 2001. The decrease
in DD&A is the result of the decrease in production volumes during the three
months ended June 30, 2002.
GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A decreased
$105,831, or 7%, to $1,401,154 for the three months ended June 30, 2002 from
$1,506,985 for the three months ended June 30, 2001. G&A was $0.49 per Mcfe for
the three months ended June 30, 2002, an increase of 39% from $0.35 per Mcfe for
the three months ended June 30, 2001. The decrease was primarily the result of a
decrease in salary, bonus and related overhead expense of $187,588, a decrease
in contract labor of $89,678, a decrease in office rental and relocation expense
of $75,140. This decrease was offset by increases in legal and professional fees
of $177,885 and an increase in directors fees and related expenses in the amount
of $75,000 during the three months ended June 30, 2002.
INTEREST EXPENSE. Interest expense increased $3,626,302 or 115%,
to $6,790,577 for the three months ended June 30, 2002 from $3,164,275 for the
three months ended June 30, 2001. The increase is
12
primarily the result of non-cash amortization of bond discount and deferred loan
costs to interest expense of $1,588,233 and $1,301,550, respectively during
three months ended June 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 totaling $48,298 for the three months ended June
30, 2002, a 99% decrease from $6,587,700 for the three months ended June 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
$11,489 and $2,281,404 for the three months ended June 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 June 30, 2002 and 2001, $36,809 and $2,547,948,
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 three months ended June 30, 2001. No retention bonuses were
incurred during the three months ended June 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 three months ended June 30, 2002 and 2001, none and $426,381 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 to an
affiliate, Atasca Resources, Inc., at their net book value of approximately
$1,098,000. 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
$1,882,989 during the three months ended June 30, 2001. No amounts were recorded
as a result of this transaction during the three months ended June 30, 2002.
PROVISION FOR INCOME TAXES. A $91,442 provision for income tax
was made for the three months ended June 30, 2001, primarily as a result of
alternative minimum tax requirements. No provision for federal income tax was
required for the three months ended June 30, 2002.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001
For the six months ended June 30, 2002, consolidated net loss was
$24,234,608 as compared to consolidated net income of $19,180,647 for the six
months ended June 30, 2001.
OIL AND GAS REVENUES. Oil and natural gas revenues decreased
$32,983,732, or 60%, to $21,682,755 for the six months ended June 30, 2002, from
$54,666,487 for the six months ended June 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. The decline in production is partially
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, the Company curtailed its workover
expenditure program during the second quarter of 2002, which further contributed
to the decline in production volumes. The following table summarizes the
consolidated results of oil and natural gas production and related pricing for
the six months ended June 30, 2002 and 2001:
13
For the Six Months Ended June 30,
---------------------------------------
2002 2001 % Change
-------- -------- ----------
Oil production volumes (Mbbls) 484 692 -30%
Gas production volumes (Mmcf) 3,027 4,615 -34
Total (Mmcfe) 5,932 8,766 -32
Average oil price (per Bbl) $23.76 $27.12 -12%
Average gas price (per Mcf) 3.36 7.78 -57
Average price (per Mcfe) 3.66 6.24 -41
LOSS ON MARKETABLE SECURITIES. We recognized $417,180 in losses
on marketable securities for the six months ended June 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 June 30, 2002, we held no
marketable securities.
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 and 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 estimated fair
value of these contracts as of the six months ended June 30, 2002 and 2001
resulted in a net non-cash loss on derivative contracts of $14,233,590 and net
non-cash income on derivative contracts of $3,586,626, respectively.
OTHER. Other income increased $1,559,407 or 174% to $2,456,329
for the six months ended June 30, 2002 when compared to $896,922 for the six
months ended June 30, 2001. The increase was the result of the sale of emission
reduction credits from our Hastings Field in the approximate amount of
$1,457,600 during the second quarter of 2002.
LEASE OPERATING EXPENSE. Lease operating expense decreased
$523,820, or 5%, to $9,956,609 for the six months ended June 30, 2002 from
$10,480,429 for the six months ended June 30, 2001. Lease operating expense was
$1.68 per Mcfe for the six months ended June 30, 2002, an increase of 40% from
$1.20 per Mcfe for the six months ended June 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. The ceasing of operations in these fields
resulted in a reduction of lease operating expense for the last half of 2001
through 2002. The decrease is partially offset by a $249,305 increase in ad
valorem taxes, which are expensed during the second quarter of 2002. During the
six months ended June 30, 2002, lease operating expense, calculated on a unit of
production basis increased by $0.48 per mcfe. This increase is attributable to
the 32% decline in oil and natural gas production volumes when compared to the
six months ended June 30, 2001.
WORKOVER EXPENSE. Workover expense decreased $883,527, or 26%, to
$2,456,602 for the six months ended June 30, 2002 from $3,340,129 for the six
months ended June 30, 2001. Workover expense was $0.41 per Mcfe for the six
months ended June 30, 2002, a decrease of 9% from $0.38 per Mcfe for the six
months ended June 30, 2001. The decrease is primarily the result of the
Company's decision to restrict the use of cash during the second quarter of 2002
in anticipation of the required principal and interest payment which was due on
its 12.5% Senior Secured Debt on June 1, 2002. The reduction in the amount of
workover expense incurred during the second quarter contributed to the general
decline in its production volumes.
14
PRODUCTION TAXES. Production taxes decreased by $863,721 or 64%
to $477,855 for the six months ended June 30, 2002 from $1,341,576 for the six
months ended June 30, 2001. Production taxes were $0.08 per Mcfe for the six
months ended June 30, 2002, a decrease of 47% from $0.15 per Mcfe for the six
months ended June 30, 2001. Decreases in oil and natural gas production and
revenues during the six months ended June 30, 2002 resulted in a decrease in the
amount of production taxes paid during the period.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE ("DD&A"). DD&A
expense decreased by $2,697,361, or 37%, to $4,564,682 for the six months ended
June 30, 2002 from $7,262,043 for the six months ended June 30, 2001. DD&A was
$0.77 per Mcfe for the six months ended June 30, 2002, a decrease of 7% from
$0.83 per Mcfe for the six months ended June 30, 2001. The decrease in DD&A is
the result of the decrease in production volumes during the six months ended
June 30, 2002.
GENERAL AND ADMINISTRATIVE EXPENSE ("G&A"). G&A decreased
$548,544, or 17%, to $2,600,687 for the six months ended June 30, 2002 from
$3,149,231 for the six months ended June 30, 2001. G&A was $0.44 per Mcfe for
the six months ended June 30, 2001, an increase of 22% from $0.36 per Mcfe for
the six months ended June 30, 2001. The decrease was primarily the result of a
decrease in salary, bonus and related overhead expense of $496,909, a decrease
in contract labor of $163,973, a decrease in office rental and relocation
expense of $107,633 and a decrease in bad debt expense of $53,568. This decrease
was offset by increases in legal and professional fees of $87,396 and an
increase in directors fees and related expenses in the amount of $225,000 during
the six months ended June 30, 2002.
INTEREST EXPENSE. Interest expense increased $7,668,256 or 122%,
to $13,944,506 for the six months ended June 30, 2002 from $6,276,250 for the
six months ended June 30, 2001. The increase is primarily the result of non-cash
amortization of bond discount and deferred loan costs to interest expense of
$3,245,600 and $2,661,312, respectively, during the six months ended June 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 totaling $139,161 for the six months ended June 30,
2002, a 98% decrease from $7,311,108 for the six months ended June 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
$90,955 and $3,524,152 for the six months ended June 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 June 30, 2002 and 2001, $48,206 and $2,547,948,
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 six months ended June 30, 2001. No retention bonuses were
incurred during the six months ended June 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 six months ended June 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 to an
affiliate, Atasca Resources, Inc., at their net book values of approximately
$1,098,000. 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
$1,882,989 during the six months ended June 30, 2001. No amounts were recorded
as a result of this transaction during the six months ended June 30, 2002.
15
PROVISION FOR INCOME TAXES. A $391,442 provision for income tax
was made for the six months ended June 30, 2001, primarily as a result of
alternative minimum tax requirements. No provision for federal income tax was
required for the six months ended June 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 June 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 six month period ended June 30,
2002, the average prices we received for natural gas and oil were $3.36 per Mcf
and $23.76 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.
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. 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 June 30, 2002, we had $110.0 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. Subsequently, 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 no later than August 2, 2002. As the Company was
unable to obtain clear title by that date, 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 June 30, 2002.
At June 30, 2002, our cash balance was $2.2 million, a $2.6
million decrease from our cash balance at December 31, 2001.
16
Net cash provided by operating activities after reorganization
items increased $36.5 million to $12.0 million for the six months ended June 30,
2002 compared to net cash used by operating activities after reorganization
items of $24.6 for the six months ended June 30, 2001. The increase is the
result of a $41.3 million decrease in net cash used in operating activities for
accounts payable subject to renegotiation of $44.2 million at June 30, 2001
compared to $3.0 million at June 30, 2002. The Company reported a net loss of
$24.2 million for the six months ended June 30, 2002 when compared to net income
of $19.2 million for the six months ended June 30, 2002. During the six months
ended June 30, 2002, we recorded a loss on the mark-to-market value of our
derivative contracts of $14.2 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 June 30, 2002, $11.9 million of cash deposited into
this restricted account was disbursed to us or to claimants of pre-petition
claims. At June 30, 2002, the balance in the restricted account was $1.6
million.
Net cash provided by investing activities was $6.3 million during
the six months ended June 30, 2002 compared to net cash used in investing
activities of $2.0 million during the six months ended June 30, 2001. The
increase in net cash provided by investing activities is primarily the result of
the sale of certain oil and natural gas properties and net realized proceeds in
the amount of $6.0 million. Additionally, the company recognized $2.3 million of
proceeds from the sale of derivative contracts and $2.4 million of cash
settlements on derivative contracts during the six months ended June 30, 2002.
Net cash used in financing activities was $20.9 million for the
six months ended June 30, 2002 when compared to net cash provided by financing
activities of $6.6 million during the six months ended June 30, 2001. The
increase in net cash used in financing activities is the result of our payment
of $20.0 million of principal on the outstanding balance of our Senior Secured
Debt 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") (see
Note 7). 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. As the Company was unable to obtain clear title by
that date, 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 June 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 considerably impact 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 considering 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 August 1, 2002 of approximately $1.0 million, would
provide the Company with sufficient capital to meet its upcoming December 1,
2002 scheduled debt obligation. However, to date, no definitive agreement to
sell these properties has been secured.
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.
17
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Revenues from our operations are highly dependent on the price of
oil and natural gas. The markets for oil and natural gas are volatile and prices
for oil and natural gas are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for oil and natural gas and
a variety of additional factors that are beyond our control, including the level
of consumer demand, weather conditions, domestic and foreign governmental
regulations, market uncertainty, the price and availability of alternative
fuels, political conditions in the Middle East, foreign imports and overall
economic conditions. It is impossible to predict future oil and natural gas
prices with any certainty. To reduce our exposure to oil and natural gas price
risks, from time to time we may enter into commodity price derivative contracts
to hedge commodity price risks.
In connection with the issuance of the senior secured notes, we
agreed to maintain, on a monthly basis, a rolling two-year hedge program until
the maturity of the notes, subject to certain conditions. In March 2002, we
terminated certain of our price swap derivatives contracts and replaced them
with contracts providing for price floors at the prices specified under the
terms of the senior secured notes of $2.75 per MMBtu of natural gas and $18.50
per barrel of crude oil.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board finalized
FASB Statements No. 141, Business Combinations (SFAS 141), and No. 142, Goodwill
and Other Intangible Assets (SFAS 142). SFAS 141 requires the use of the
purchase method of accounting and prohibits the use of the pooling-of-interests
method of accounting for business combinations initiated after June 30, 2001.
SFAS 141 also required that the Company recognize acquired intangible assets
apart from goodwill if the acquired intangible assets meet certain criteria.
SFAS 141 applies to all business combinations initiated after June 30, 2001 and
for purchase business combinations completed on or after July 1, 2001. It also
requires, upon adoption of SFAS 142 that the Company reclassify the carrying
amounts of intangible assets and goodwill based on the criteria in SFAS 141.
SFAS 142 requires, among other things, that companies no longer amortize
goodwill, but instead test goodwill for impairment at least annually. In
addition, SFAS 142 requires that the Company identify reporting units for the
purposes of assessing potential future impairments of goodwill, reassess the
amortization of intangible assets with an indefinite useful life. An intangible
asset with an indefinite useful life should be tested for impairment in
accordance with SFAS 142. SFAS 142 is required to be applied in fiscal years
beginning after December 15, 2001 to all goodwill and other intangible assets
recognized at that date, regardless of when those assets were initially
recognized. SFAS 142 requires the Company to complete a transitional goodwill
impairment test six months from the date of adoption. The Company is also
required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. Currently, the Company is
assessing but has not yet determined how the adoption of SFAS 141 and SFAS 142
will impact its financial position and results of operations.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations, SFAS No. 143, which amends SFAS No. 19, Financial
Accounting and Reporting by Oil and Gas Producing Companies, 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 we
are not yet required to adopt SFAS No. 143, we do not believe the adoption will
have a material effect on our financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the
Impairment or Disposal of Long-lived Assets. 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 ARB 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.
18
144 are generally to be applied prospectively. We do not believe the adoption of
SFAS No. 144 will have a material effect on our financial condition or results
of operations.
In April 2002, the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the current requirement that gains and
losses on debt extinguishment must be classified as extraordinary items in the
income statement. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent, in
accordance with the current GAAP criteria for extraordinary classification. In
addition, SFAS 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, the 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 Issues 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. Also, 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, the FASB issued SFAS No. 146, Accounting for Costs
Associated with Exit or Disposal Activities, which addresses accounting for
restructuring and similar costs. SFAS No. 146 supersedes previous accounting
guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3. The
Company 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 was
recognized at the date of a companys 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.
CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES
The Securities and Exchange Commission recently issued disclosure
guidance for "critical accounting policies." The SEC defines critical accounting
policies as those that require application of management's most difficult,
subjective or complex judgments, often as a result of the need to make estimates
about the effect of matters that are inherently uncertain and may change in
subsequent periods.
Our significant accounting policies are described in Note 3 in
the Notes to Consolidated Financial Statements. Not all of these significant
accounting policies require management to make difficult, subjective or complex
judgments or estimates. However, the following policies could be deemed to be
critical within the SEC definition.
Oil and Natural Gas Interests
Full Cost Method - The Company uses the full cost method of
accounting for exploration and development activities as defined by the SEC.
Under this method of accounting, the costs for unsuccessful, as well as
successful, exploration and development activities are capitalized as properties
and equipment. This includes any internal costs that are directly related to
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities. The sum of net
capitalized costs and estimated future development and abandonment costs of oil
and gas properties and mineral investments are amortized using the
unit-of-production method.
19
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 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 a hedge, depending on the
nature of the hedge, changes in the fair value of derivatives will either be
offset against the change in fair value of the hedged assets, liabilities, or
firm commitments through earnings or recognized in other comprehensive income
until the hedged item is recognized in earnings. The ineffective portion of a
derivative's change in fair value will be immediately recognized in earnings.
Use of Estimates
The financial statements have been prepared in conformity with
generally accepted accounting principles appropriate in the circumstances. In
preparing financial statements, management makes informed judgments and
estimates that affect the reported amounts of assets and liabilities as of the
date of the financial statements and affect the reported amounts of revenues and
expenses during the reporting period. Actual results may differ from these
estimates.
20
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 June 30, 2002:
--------------------------------------------------------------------------------------------------
NYMEX SWAPS
----------------------------------------------------
QUARTER ENDING VOLUME NYMEX PRICE
-------------------- -------------------------
MMcf MBbl $/MMBTU $/Bbl
--------------------------------------------------------------------------------------------------
Sep. 30, 2002 - 208 $ - $ 25.30
Dec. 31, 2002 - 70 - 25.30
Mar. 31, 2003 - - - -
Jun. 30, 2003 - - - -
Sep. 30, 2003 708 177 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
--------------------------------------------------------------------------------------------------
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 June 30, 2002:
---------------------------------------------------------
NYMEX FLOORS
---------------------
QUARTER ENDING VOLUME
---------------------
MMcf MBbl
---------------------------------------------------------
Sep. 30, 2002 1,320 -
Dec. 31, 2002 1,320 146
Mar. 31, 2003 909 173
Jun. 30, 2003 909 173
Mar. 31, 2004 242 52
---------------------------------------------------------
21
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are party to litigation or other legal
proceedings that we consider to be a part of the ordinary course of our
business. Other than as set forth below, we are not involved in any legal
proceedings nor are we party to any pending or threatened claims that could
reasonably be expected to have a materially adverse effect on our financial
condition, cash flow or results of operations.
Richard Bowman
On August 9, 2002, shareholder and former Chief Executive Officer
Richard 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
certain members of the board of directors and Jefferies violated fiduciary
duties by entering into the Waiver (see Note 7 to the consolidated financial
statements) to the Indenture. The lawsuit seeks to rescind the Waiver. The
Company intends to vigorously defend the actions of the board members subject
to this lawsuit.
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 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.
22
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. hold 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 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. 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 June 30,
2002.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
23
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.
24
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.(2)
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)
(1) Incorporation by reference to the comparably numbered Exhibit to the
Registration Statement on Form S-4 filed by the Issuer November 2, 2001.
(2) Attached hereto.
25
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
August 14, 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
26
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.(2)
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)
(1) Incorporation by reference to the comparably numbered Exhibit to the
Registration Statement on Form S-4 filed by the Issuer November 2, 2001.
(2) Attached hereto.