AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON OCTOBER 11, 2001
REGISTRATION NO. 333-66282
333-66282-01
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
(Amendment No. 2)
---------------------
<Table>
TRI-UNION DEVELOPMENT CORPORATION TRI-UNION OPERATING COMPANY
(Exact name of registrant as specified in its (Exact name of registrant as specified in its
charter) charter)
TEXAS DELAWARE
(State or other jurisdiction of incorporation or (State or other jurisdiction of incorporation or
organization) organization)
1311 1311
(Primary Standard Industrial Classification No. (Primary Standard Industrial Classification No.
76-0503660 94-2285498
(I.R.S. Employer Identification No.) (I.R.S. Employer Identification No.)
</Table>
530 LOVETT BOULEVARD
HOUSTON, TEXAS 77006
(713) 533-4000
(Address, including zip code, and telephone number, including area code, or
registrants' principal executive offices)
---------------------
copies to:
BARRY DAVIS
WILLIAM T. HELLER IV
THOMPSON & KNIGHT LLP
1200 SMITH, SUITE 3600
HOUSTON, TEXAS 77002
---------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon
as practicable after this Registration Statement becomes effective.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
---------------------
THE REGISTRANTS HEREBY AMEND THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANTS
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SUCH SECTION 8(a),
MAY DETERMINE.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
The information in this prospectus is not complete and may be changed. We may
not sell the new notes until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell the new notes and it is not soliciting an offer to buy the new notes in
any state where the offer or sale is not permitted.
PROSPECTUS SUBJECT TO COMPLETION, DATED OCTOBER 11, 2001
[TRI-UNION DEVELOPMENT CORPORATION LOGO]
TRI-UNION DEVELOPMENT CORPORATION
OFFER TO EXCHANGE
$130,000,000 REGISTERED 12.5% SENIOR SECURED NOTES DUE 2006 FOR
ALL OUTSTANDING UNREGISTERED 12.5% SENIOR SECURED NOTES DUE 2006
PAYMENT UNCONDITIONALLY GUARANTEED ON A SENIOR SECURED BASIS BY
TRI-UNION OPERATING COMPANY
---------------------
TERMS OF THE EXCHANGE OFFER
- We are offering to exchange all validly tendered old notes, which we
originally sold in a private offering, for an equal principal amount of
new notes that have been registered under the Securities Act of 1933.
- THIS EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON
, 2001, UNLESS EXTENDED.
- Tenders of outstanding old notes may be withdrawn at any time prior to
the expiration of the exchange offer.
- We believe that the exchange of old notes for new notes should not be a
taxable exchange for federal income tax purposes, but you should
read -- "Material United States Federal Income Tax Considerations -- The
Exchange Offer" on page 121 for more information.
- We will not receive any proceeds from the exchange offer.
- The terms of the new notes are substantially identical to the terms of
the old notes, except that the new notes will not generally be subject to
the transfer restrictions nor have the registration rights applicable to
the old notes.
- No public market currently exists for the new notes. We do not intend to
apply for listing of the new notes on any securities exchange or to
arrange for them to be quoted on any quotation system.
- The old notes and the new notes are senior in right of payment to all of
our unsecured senior indebtedness, to the extent of the value of the
pledged collateral, and all of our subordinated indebtedness. We do not
currently have any senior or subordinated indebtedness for borrowed money
other than the old notes.
YOU SHOULD CONSIDER CAREFULLY THE "RISK FACTORS" BEGINNING ON PAGE 11
BEFORE PARTICIPATING IN THE EXCHANGE OFFER.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
The date of this Prospectus is , 2001.
OUR PRINCIPAL OIL AND GAS FIELDS IN OUR CORE OPERATING AREAS
[MAP]
[This page includes a map of the United States with breakout segments
identifying oil fields located in the Sacramento Basin and the Onshore and
Offshore Gulf Coast. The Sacramento Basin segment identifies the following oil
fields: Rancho Capay; West Ord Bend; Willows-Beehive Bend; Afton/Main; South
Afton; Moon Bend; Sycamore; West Grimes; Sutter Buttes; Sutter City Grimes and
Tisdale. The Onshore and Offshore Gulf Coast segment identifies the following
oil fields: AWP; Alamo; Matagorda Island; Powderhorn; Weesatche; McFaddin;
Brazos; East Placedo; Heinzeville; Word; Danbury; Sublime; Galveston; High
Island West; High Island East; North Alvin; Hastings; Gillock; Giddings; Kurten;
South Liberty; Madisonville; Hull; High Island; Constitution; Barbers Hill; Sour
Lake; Spindletop; Winnie SE; West Cameron; South Marsh Island; Eugene Island;
Rayne; Scott; Clear Branch; Ship Shoal; South Timbalier and South Pass.]
SUMMARY
This summary contains basic information about us and this exchange offer.
Because it is a summary, it does not contain all the information that you should
consider before making a decision as to whether to tender your old notes in this
exchange offer. You should read this entire prospectus carefully before making a
decision. Unless the context requires otherwise, references in this prospectus
to "Tri-Union," "we," "us" and "our" refer to Tri-Union Development Corporation
and Tri-Union Operating Company, our wholly-owned subsidiary. The consolidated
historical financial, reserve, operating and pro forma data set forth in this
prospectus include information for our subsidiary and us on a consolidated
basis. The information in this prospectus gives effect to our merger with our
former parent corporation, Tribo Petroleum Corporation, on July 27, 2001. If you
are not familiar with some of the oil and natural gas terms used in this
prospectus, please read "Glossary of Oil and Natural Gas Terms" beginning on
page 127.
OUR COMPANY
We are an independent oil and natural gas company engaged in the
acquisition, development, exploration and production of oil and natural gas
properties in three core areas. Our core areas are located onshore Gulf Coast,
primarily in Texas and Louisiana, offshore Gulf Coast in the shallow waters of
the Gulf of Mexico and in the Sacramento Basin of northern California. We have
established significant operating expertise in our core areas which we believe
allows us to better anticipate and manage operating expenses, produce our
properties more efficiently and improve recovery from our reservoirs.
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. This interest is the only oil and natural gas property of
Tri-Union Operating and represents less than 5% of our consolidated proved
reserves.
At December 31, 2000, we had net proved reserves of 180.1 Bcfe,
approximately one-half of which were natural gas, with a reserve life of 11.0
years. Our reserve base is diversified across our three core areas, with 64% of
our proved reserves located onshore Gulf Coast, 12% offshore Gulf Coast and 24%
in California. Each of these core areas is characterized by years of stable,
historical production and numerous producing wells. We operate approximately 92%
of our proved reserves.
We have a large inventory of development projects that we have only
recently begun to exploit. Because we operate in older, more mature fields with
long production histories and many producing wells, we believe these projects
represent low-risk opportunities to add to our reserves. We completed 28 of
these projects during 1999 and 2000 for $10.6 million in development capital
expenditures for drilling and recompletions, resulting in a 42% increase in our
daily production. We experienced a 75% drilling success rate over that period.
We have identified another 175 similar projects on our existing fields to pursue
through 2003. Of these projects, 116 are proved behind pipe and proved
undeveloped projects and two are 3-D seismic surveys in California. We have
allocated $14.9 million of our capital budget for the second half of 2001, $19.3
million for 2002 and $3.5 million for 2003 for these projects. The balance of 57
projects are behind pipe opportunities in the Sacramento Basin that were not
classified as proved at December 31, 2000. Of these projects, 24 and 33 may be
added to our budgeted projects during 2001 and 2002, respectively, depending on
our capital resources. We anticipate that we may expend an additional $720,000
during the remainder of 2001 and $990,000 in 2002 should we decide to fund these
projects. Further, depending on our capital resources, we may substitute some of
these projects for currently budgeted projects as these behind pipe
opportunities are less expensive than many of our budgeted development projects.
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) is hedged through June 30, 2003 at
swap prices of $4.19 per Mcf and $25.30 per Bbl, or a weighted-average natural
1
gas-equivalent price of approximately $4.20 per Mcfe. In connection with the
original offering, we agreed to maintain, on a monthly basis, a rolling two-year
hedge program until the maturity of the old notes and the new notes, subject to
certain conditions. We believe this hedging program will provide us with the
financial capacity to successfully execute our development plans and profitably
grow production from current levels.
Our principal executive offices are located at 530 Lovett Boulevard,
Houston, Texas 77006-4021, and our telephone number is (713) 533-4000.
OUR BANKRUPTCY AND RECAPITALIZATION
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35 million in debt outstanding. We incurred approximately another
$63 million in debt in connection with the acquisition of these properties from
Apache. A portion of this debt was in the form of a short-term, amortizing bank
loan.
In August 1998, before we were able to refinance our bank loan, commodity
prices began falling, with oil prices ultimately reaching a 12-year low in
December 1998. The resultant negative effect on our cash flow from the
deterioration of commodity prices, coupled with the required amortization
payments on our bank loan, severely restricted the amount of capital we were
able to dedicate to development drilling. Consequently, our oil and natural gas
production declined, further negatively affecting our cash flow. In October
1998, our short-term loan matured and we arranged a forbearance agreement
providing for interest payments to be partially capitalized and providing us
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 expense to approximately $105 million. In February 2000, the bank
declared a default on the loan, demanded payment of all principle and interest
and posted the shares of Tribo Petroleum Corporation, our parent corporation and
a guarantor of the loan, for foreclosure. As a consequence of the banks's
foreclosure action, on March 14, 2000, we chose to seek protection under Chapter
11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern
District of Texas, Houston Division. Tri-Union Operating continued to operate
outside of bankruptcy.
As a result of the redeployment of funds formerly utilized for amortization
payments, we have conducted a limited but highly successful, low-risk
development drilling program, which has resulted in an increase of approximately
42% in our average daily production over the last two years. This production
increase, coupled with improved commodity prices, allowed us to increase our
cash position to approximately $66.7 million immediately prior to closing of the
original offering on June 18, 2001, from approximately $1.4 million on March 14,
2000. The original offering was a private unit offering, with each unit
consisting of one old note in the principal amount of $1,000 and one share of
class A common stock of our former parent corporation, Tribo Petroleum
Corporation, with which we merged on July 27, 2001. The units were sold to
Jefferies & Company, Inc., as initial purchaser, which then resold the units to
qualified institutional buyers in reliance on Rule 144A under the Securities
Act. The proceeds of the original offering and our available cash balances at
closing 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.
The old notes are our only material long-term indebtedness. Our level of
indebtedness as of June 30, 2001, was $130.0 million as compared to adjusted
EBITDA on a pro forma basis for the six months then ended of $36.8 million and
for the year ended December 31, 2000, of $42.0 million. Our significant leverage
creates risks for holders of the notes, including the risk that we will be
unable to satisfy the amortization payments due on the notes on June 1, 2002,
2003 and 2004.
2
THE EXCHANGE OFFER
Securities Offered.................. We are offering to exchange old notes
for new notes in the aggregate
principal amount of up to $130,000,000.
The new notes will evidence the same
debt as the old notes and will be
entitled to the benefits of the same
indenture as the old notes. The terms
of the new notes and the old notes are
substantially identical, except that
the new notes will not generally be
subject to the transfer restrictions
nor have the registration rights
applicable to the old notes.
The Exchange Offer.................. The new notes are being offered in
exchange for a like principal amount of
the old notes. The old notes may be
exchanged only in integral multiples of
$1,000.
Expiration Date..................... The exchange offer expires at 5:00
p.m., New York City time, on
, 2001, or such later date
and time to which it is extended by us
in our sole discretion.
Withdrawal Rights................... Tenders may be withdrawn at any time
prior to the expiration date. Any old
notes not accepted for any reason will
be returned without expense to the
tendering holder thereof as promptly as
practicable after the expiration or
termination of the exchange offer.
Effect of Exchange on Holder of New
Notes............................... Based on interpretations by the staff
of the SEC as set forth in no-action
letters issued to third parties we
believe that the new notes issued in
exchange for old notes may be offered
for resale, resold or otherwise
transferred by holders (other than any
holder which is an "affiliate" of ours
within the meaning of Rule 405 under
the Securities Act) without compliance
with the registration and prospectus
delivery provisions of the Securities
Act, provided that such new notes are
acquired in the ordinary course of the
holder's business and the holder has no
arrangement with any person to
participate in the distribution of such
new notes. In addition, holders of new
notes will have no further registration
rights under the registration rights
agreement.
Effect of Failure to Exchange on
Holders of Old Notes................ All untendered, and tendered but
unaccepted, old notes will continue to
be subject to the restrictions on
transfer provided for in the old notes
and the indenture. To the extent old
notes are tendered and accepted in the
exchange offer, the trading market, if
any, for the old notes could be
adversely affected. Holders of the old
notes that do not exchange their old
notes for new notes will, after
3
the exchange is consummated, have no
further registration or other rights
under the registration rights
agreement. Holders of the old notes
will continue to be entitled to all the
rights and limitations under the
indenture.
Procedure for Tendering Old Notes... For you to validly tender old notes in
the exchange offer, either:
- a properly completed and duly
executed letter of transmittal, or a
manually executed facsimile of that
document, along with any required
signature guarantees, or an agent's
message in connection with a
book-entry transfer, and any other
required documents, must be
transmitted to and received by the
exchange agent at its address set
forth on page 29 of this prospectus
under the heading "The Exchange
Offer -- Exchange Agent" and
certificates for tendered old notes
must be received by the exchange
agent at one of those addresses, or
those old notes must be tendered in
accordance with the procedure for
book-entry tender (and a confirmation
of receipt of the tender received),
in each case before the expiration
date. See "The Exchange
Offer -- Exchange Offer
Procedures -- General",
"-- Book-Entry Transfer" and
"-- Certificated Old Notes" beginning
on page 24 for more details; or
- you must comply with the guaranteed
delivery procedures set forth in "The
Exchange Offer -- Guaranteed Delivery
Procedures" beginning on page 26.
Use of Proceeds..................... We will not receive any cash proceeds
from the issuance of new notes.
Exchange Agent...................... Firstar Bank, National Association is
serving as the exchange agent in
connection with the exchange offer.
United States Federal Income Tax
Consequences...................... The exchange of old notes should not be
a taxable event for United States
federal income tax purposes.
4
THE TERMS OF THE OLD NOTES AND THE NEW NOTES
Issuer.............................. Tri-Union Development Corporation.
Maturity Date....................... June 1, 2006.
Amortization Payments............... On June 1, 2002, 2003 and 2004, we will
make amortization payments of the
greater of $20.0 million and 15.3%,
$20.0 million and 15.3%, and $15.0
million and 11.5%, respectively, of the
aggregate principal amount of the
notes, reduced by any amortization
payments made prior to the payment
date, together with accrued and unpaid
interest to the date of payment.
Interest Rate and Payment Dates..... The notes bear interest at a rate of
12.5% per annum. Interest on the new
notes will accrue from the last date on
which interest was paid on the old
notes surrendered in exchange for the
new notes or, if no interest has been
paid, from the date of original
issuance of the old notes. Interest
will be payable semi-annually in cash
in arrears on June 1 and December 1 of
each year, commencing December 1, 2001.
Collateral and Intercreditor
Rights.............................. The notes and the guarantees by our
subsidiary and any future subsidiaries
will be secured by a first lien on
substantially all existing and future
oil and natural gas properties owned by
us and our subsidiary. The notes are
subject to certain payment priorities
in connection with commodity hedge
agreements we entered into in
connection with the issuance of the old
notes, and the collateral securing the
notes will be subject to certain
permitted liens.
Guarantees.......................... The notes will be unconditionally
guaranteed on a senior secured basis by
Tri-Union Operating Company, as well as
all of our future subsidiaries. The
guarantees will rank senior in right of
payment to all unsecured senior
indebtedness of the guarantors, to the
extent of the value of the pledged
collateral. The guarantees will be
subject to certain payment priorities
in connection with commodity hedge
agreements that we entered into in
connection with the issuance of the
notes and that we will be required to
enter into the future under the terms
of the indenture, and the collateral
securing the guarantees will be subject
to certain permitted liens.
Ranking............................. The notes will rank senior in right of
payment to all of our unsecured senior
indebtedness, to the extent of the
value of the pledged collateral.
Original Issue Discount............. The old notes were issued with, and the
new notes will be deemed to have been
issued with,
5
original issue discount for federal
income tax purposes. You should be
aware that accrued original issue
discount will be included periodically
in your gross income for federal income
tax purposes. See "Material United
States Federal Tax
Considerations -- Notes" beginning on
page 121 for more details.
Optional Redemption................. The notes will be redeemable at our
option, in whole or in part, at any
time on or after June 1, 2004, at
redemption prices equal to 104% of the
aggregate principal amount of the notes
to be redeemed, or 100% of the
aggregate principal amount of the notes
to be redeemed on or after June 1,
2005, in each case together with
accrued and unpaid interest to the date
of redemption.
In addition, in the event we consummate
a public equity offering prior to June
1, 2003, we may use all or a portion of
the net proceeds from that offering to
redeem up to 30% of the aggregate
principal amount of the notes at a
redemption price equal to 112.5% of the
principal amount of the notes to be
redeemed, together with accrued and
unpaid interest to the date of
redemption. The redemptions from a
public equity offering will be limited
so that no less than 70% of the
aggregate principal amount of the notes
will remain outstanding.
Repurchase Obligations Upon Change
of Control.......................... Upon a change of control, each holder
of notes will have the right to require
us to repurchase all or a portion of
such holder's notes at a repurchase
price equal to 101% of the principal
amount of the notes, together with
accrued and unpaid interest to the date
of repurchase.
Certain Covenants................... The new notes will be issued under the
same indenture as the old notes. The
indenture contains certain covenants
including, but not limited to,
covenants that limit our ability to:
- incur additional indebtedness and
issue disqualified capital stock;
- pay dividends;
- make certain restricted payments;
- consummate certain asset sales and
asset sale offers;
- enter into certain transactions with
affiliates;
- incur liens;
6
- merge or consolidate with any other
person or sell or otherwise dispose
of all of our assets;
- sell or issue capital stock of a
restricted subsidiary;
- enter into new lines of business; and
- enter into synthetic lease
transactions.
The indenture also contains covenants
regarding the designation of
unrestricted subsidiaries, ownership of
restricted subsidiaries, issuance of
reports, liens on additional collateral
and the independence of our board of
directors.
Hedge Covenant...................... 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) is hedged through June 30,
2003 at swap prices of $4.19 per Mcf
and $25.30 per Bbl, or a
weighted-average natural gas-equivalent
price of approximately $4.20 per Mcfe.
In connection with the original
offering, we agreed to maintain, on a
monthly basis, a rolling two-year hedge
program until the maturity of the old
notes and the new notes, subject to
certain conditions.
Excess Cash Flow Offer.............. If we have excess cash flow of at least
$1.0 million during any fiscal quarter
beginning with the quarter ended June
30, 2004, we will be obligated to
purchase notes at 100% of the principal
amount thereof, plus accrued and unpaid
interest, provided that the amount
required to be paid to repurchase notes
will be limited to the amount of 50% of
such excess cash flow.
RISK FACTORS
Before deciding to invest in the notes or to tender your old notes in
exchange for the new notes, you should carefully consider the information
included in "Risk Factors" beginning on page 11, as well as all other
information set forth in this prospectus.
7
SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL DATA
The following table sets forth some of our historical and pro forma
consolidated financial data. You should read the following data in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations," the pro forma financial data and the consolidated financial
statements and related notes included in this prospectus. The summary financial
and other data as of, and for the years ended December 31, 1998, 1999 and 2000,
have been derived from the audited consolidated financial statements included in
this prospectus. The summary financial data as of June 30, 2001 and for the six
months ended June 30, 2000 and 2001 are derived from our unaudited consolidated
financial statements and include all adjustments, consisting only of normal
recurring adjustments, that management considers necessary to fairly present
such data. The results for the six months ended June 30, 2001 are not
necessarily indicative of the results to be expected for the year ending
December 31, 2001. The summary unaudited pro forma statement of operations data
and other financial data illustrates the impact that the original offering and
our amended plan of reorganization would have had if they had been consummated
as of January 1, 2000. The summary unaudited pro forma financial data is not
necessarily indicative of the results that would have occurred had the original
offering and our plan been consummated as of the beginning of the periods
presented.
<Table>
<Caption>
YEARS ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
---------------------------------------- -----------------------------
PRO FORMA PRO FORMA
1998 1999 2000 2000 2000 2001 2001
-------- ------- ------- --------- ------- ------- ---------
(IN THOUSANDS, EXCEPT RATIO DATA)
CONSOLIDATED STATEMENT OF
OPERATIONS DATA:
Total revenues................. $ 26,352 $37,766 $74,476 $ 74,476 $27,509 $58,733 $58,733
Expenses:
Lease operating.............. 17,450 15,542 19,485 19,485 6,804 10,480 10,480
Workover..................... 600 2,410 6,649 6,649 1,697 3,340 3,340
Production taxes............. 639 705 1,968 1,968 712 1,342 1,342
Depreciation, depletion and
amortization.............. 12,398 11,040 13,506 13,506 5,394 7,262 7,262
General and administrative... 3,327 5,237 4,328 4,328 2,447 3,149 3,149
Interest..................... 7,734 11,981 12,758 27,876 6,733 6,276 13,066
-------- ------- ------- -------- ------- ------- -------
Total expenses....... 42,147 46,916 58,695 73,814 23,788 31,850 38,639
Income (loss) before
reorganization costs and
income taxes................. (15,795) (9,150) 15,780 662 3,721 26,883 20,093
Reorganization costs........... -- -- 21,487 21,487 915 7,311 7,311
-------- ------- ------- -------- ------- ------- -------
Income (loss) before income
taxes........................ (15,795) (9,150) (5,707) (20,826) 2,807 19,572 12,782
Provision for income taxes..... -- -- 79 -- -- 391 256
-------- ------- ------- -------- ------- ------- -------
Net income (loss).............. $(15,795) $(9,150) $(5,786) $(20,826) $ 2,807 $19,181 $12,527
======== ======= ======= ======== ======= ======= =======
OTHER FINANCIAL DATA:
Capital expenditures -- oil and
natural gas properties....... $ 71,992 $13,572 $10,878 $ 10,878 $ 3,609 $ 3,339 $ 3,339
Earnings to fixed charges(1)... NM 0.31x 0.60x 0.28x 1.40x 4.03x 1.97x
Adjusted EBITDA(2)............. 4,337 13,871 42,045 42,045 15,849 36,835 36,835
Adjusted EBITDA to cash
interest(3).................. 0.56x 1.16x 3.30x 2.59x 2.35x 6.34 4.57x
</Table>
8
<Table>
<Caption>
AT JUNE 30,
2001
--------------
(IN THOUSANDS,
EXCEPT
RATIO DATA)
CONSOLIDATED BALANCE SHEET DATA:
Net property and equipment.................................. $ 80,484
Total assets................................................ 158,954
Stockholders' equity (capital deficit)...................... 14,423
ACNTA(4).................................................... 626,650
Notes payable, including current maturities and net of bond
discounts................................................. 105,512
ACNTA to indebtedness....................................... 5.93x
</Table>
---------------
(1) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income after reorganization costs and before income taxes
plus interest expense, including amortization of premiums, discounts, and
capitalized expenses related to indebtedness. Fixed charges represent
interest expense and capitalized interest (including amortization of
deferred finance charges and an estimated portion of rentals representing
interest costs). Earnings to fixed charges were 2.18x and 1.44x for the
years ended December 31, 1996 and 1997, respectively. Earnings were
insufficient to cover fixed charges by $15.8 million, $9.2 million, $5.7 and
$20.8 million for the years ended December 31, 1998, 1999, 2000 and on a pro
forma basis for the year ended December 31, 2000, respectively. NM means
"not measured."
(2) EBITDA means earnings before interest expense, income taxes, depreciation,
depletion and amortization. Adjusted EBITDA means EBITDA before impairment
of oil and natural gas properties, reorganization costs, and gains or losses
on derivative contracts. EBITDA is commonly used by debt holders and
financial statement users as a measurement to determine the ability of an
entity to meet its interest obligations. EBITDA is not a measurement
presented in accordance with generally accepted accounting principles
("GAAP") and is not intended to be used in lieu of GAAP presentation of
results of operations and cash provided by operating activities. Our
definition of adjusted EBITDA may not be identical to similarly entitled
measures used by other companies.
(3) Cash interest excludes non-cash interest for amortization of bond discount
and bond issuance costs, which are included in determining interest expense
in accordance with GAAP.
(4) ACNTA means Adjusted Consolidated Net Tangible Assets, as defined in
"Description of the Senior Secured Notes -- Certain Definitions" beginning
on page 96. ACNTA is calculated using oil and natural gas prices utilized in
our year end reserve report.
9
SUMMARY HISTORICAL RESERVE DATA
The following table sets forth summary information with respect to our
estimated net proved oil and natural gas reserves as of the periods shown.
Please read "Risk Factors -- Our estimates of oil and natural gas reserves and
future net revenue are uncertain and inherently imprecise", beginning on page
15, regarding the risks of relying upon the information in the table.
<Table>
<Caption>
AT DECEMBER 31,
------------------------------
1998 1999 2000
-------- -------- --------
Proved reserves:
Oil and condensate (MBbls)............................... 11,319 15,851 15,073
Natural gas (MMcf)....................................... 111,149 110,092 89,699
Total (MMcfe).................................... 179,063 205,198 180,137
Proved developed reserves:
Oil and condensate (MBbls)............................... 9,124 12,957 12,290
Natural gas (MMcf)....................................... 58,088 58,265 45,575
Total (MMcfe).................................... 112,832 136,007 119,315
PV-10 Value (in thousands)(1).............................. $118,151 $292,495 $630,002
Standardized Measure (in thousands)(2)..................... $105,403 $231,564 $472,279
Reserve life (in years).................................... 13.9 14.8 11.0
</Table>
---------------
(1) The average prices used in calculating PV-10 Value as of December 31, 2000
were $10.31 per Mcf and $25.90 per Bbl. Assuming benchmark prices of $4.25
per Mcf and $25.00 per Bbl (or net realized prices of $4.82 per Mcf and
$24.10 per Bbl), our PV-10 Value would have been $309.3 million at December
31, 2000.
(2) Represents PV-10 Value adjusted for the effects of future estimated income
tax expense.
SUMMARY HISTORICAL OPERATING DATA
The following table sets forth summary information with respect to our
consolidated operations for the periods shown.
<Table>
<Caption>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------- -----------------
1998 1999 2000 2000 2001
------- ------- ------- ------- -------
Production volumes:
Oil and condensate (MBbls).............. 1,030 1,145 1,333 540 692
Natural gas (MMcf)...................... 6,711 7,007 8,314 3,413 4,615
Total (MMcfe)................... 12,890 13,874 16,313 6,653 8,767
Average daily production:
Oil and condensate (Bbls)............... 2,821 3,136 3,643 2,983 3,823
Natural gas (Mcf)....................... 18,387 19,196 22,716 18,856 25,497
Total (Mcfe).................... 35,314 38,011 44,574 36,757 48,436
Average realized prices:(1)
Oil and condensate (per Bbl)............ $ 12.43 $ 17.27 $ 28.95 $ 29.27 $ 27.12
Natural gas (per Mcf)................... 1.94 2.36 4.19 2.93 7.78
Per Mcfe........................ 2.00 2.61 4.50 3.94 6.24
Expenses (per Mcfe):
Lease operating (excluding workover
expense and production taxes)........ $ 1.35 $ 1.12 $ 1.19 $ 1.02 $ 1.20
Workover................................ 0.05 0.17 0.41 0.26 0.38
Production taxes........................ 0.05 0.05 0.12 0.11 0.15
Depreciation, depletion and
amortization......................... 0.96 0.80 0.83 0.81 0.83
General and administrative, net......... 0.26 0.38 0.27 0.37 0.36
</Table>
---------------
(1) Reflects the actual realized prices received, including the results of
hedging activities. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations" beginning on page 38.
10
RISK FACTORS
The exchange and ownership of notes involves a high degree of risk. You
should carefully consider the risks described below and the other information in
this prospectus before deciding to invest in the notes or to exchange old notes
for new notes.
RISKS RELATING TO THE EXCHANGE OFFER
Broker-dealers or certain holders may become subject to the registration and
prospectus delivery requirements of the Securities Act.
Holders that are our "affiliates" within the meaning of Rule 405 under the
Securities Act and holders that have not acquired new notes in the ordinary
course of such holder's business or who have an arrangement with any person to
participate in the distribution of new notes will not be able to offer for
resale, resell or otherwise transfer new notes without first complying with the
registration and prospectus delivery provisions of the Securities Act. Further,
while we believe other holders may be able to offer for resale, resell or
otherwise transfer new notes without complying with the provisions of the
Securities Act, our belief is based upon interpretations of no-action letters
issued to third parties and we have not requested the SEC to issue, and the SEC
has not issued, a no-action letter with regard to the exchange offer. Each
broker-dealer that receives new notes for its own account pursuant to the
exchange offer must deliver a prospectus in connection with any resale of such
new notes.
In addition, to comply with the securities laws of certain jurisdictions,
the new notes may not be offered or sold unless they have been registered or
qualified for sale in such jurisdiction or an exemption from registration or
qualification is available and is complied with. We have agreed to register or
qualify the new notes for offer or sale under the securities or blue sky laws of
such states as any holder of the new notes reasonably requests in writing but
our obligation to do so is limited to jurisdictions within the United States and
where we are not required to qualify generally to do business or subject
ourselves to taxation in any jurisdiction where we are not otherwise qualified
or subject to taxation.
RISKS RELATING TO THE OLD NOTES AND THE NEW NOTES
The value of the pledged collateral securing the notes may be inadequate, and
there are risks that may reduce your ability to conduct a successful
foreclosure.
We have granted a first lien on, and have pledged to the holders of the
notes, substantially all of our proved oil and natural gas properties and our
hedge contracts. However, you may be unable to foreclose on or dispose of any of
the collateral without substantial delays and other risks. For example, the
ability of the trustee for the holders of the notes to realize upon the
collateral will be subject to certain procedural limitations as further
described in this prospectus under "Description of the Senior Secured
Notes -- Defaults," beginning on page 88, and "Possession, Use and Release of
Collateral -- Release" beginning on page 91. In addition, if we become a debtor
in a new case under the Bankruptcy Code, the automatic stay imposed by the
Bankruptcy Code would prevent the trustee from selling or otherwise disposing of
the collateral without the bankruptcy court's authorization. In that case, the
foreclosure might be delayed indefinitely. Further, the proceeds obtained from a
foreclosure may be insufficient to pay all amounts owing to holders of the notes
and the approved hedge counterparties, others who have a payment priority under
the intercreditor agreement and amounts due to holders of permitted liens. At
December 31, 2000, we had oil and natural gas properties with a PV-10 Value of
$630.0 million. The average prices used in calculating PV-10 Value as of
December 31, 2000 were $10.31 per Mcf and $25.90 per Bbl. Assuming benchmark
prices of $4.25 per Mcf and $25.00 per Bbl (or net realized prices of $4.82 per
Mcf and $24.10 per Bbl), our PV-10 Value would have been $309.3 million at
December 31, 2000. The reserve data with respect to such interests, however,
represent estimates only and should not be construed as exact. Moreover, the
estimated PV-10 Value should not be construed as the current
11
market value of the estimated proved reserves attributable to our oil and
natural gas properties. Please read "-- Our estimates of oil and natural gas
reserves and future net revenue are uncertain and inherently imprecise"
beginning on page 15.
In addition, the terms of the indenture allow us to issue additional notes
provided that we meet certain financial tests. Please read "Description of the
Senior Secured Notes -- Certain Covenants -- Limitation on Indebtedness"
beginning on page 76. The indenture does not require that we maintain the
current level of collateral or maintain a specific ratio of indebtedness to
asset values. Any additional notes issued pursuant to the indenture will rank
equal to the notes and will be entitled to the same rights and priority with
respect to the collateral. Thus, the issuance of additional notes pursuant to
the indenture may have the effect of significantly diluting the trustee's
ability to recover payment in full from the then existing pool of collateral.
Please read "Description of the Senior Secured Notes" beginning on page 71.
You will be required to include original issue discount in ordinary income for
federal income tax purposes.
The notes have original issue discount. You will be required to include
original issue discount in ordinary income for federal income tax purposes as it
accrues before you receive cash payments attributable to such income, regardless
of your method of accounting. If a bankruptcy case is commenced by or against us
after the issuance of the notes, the claim of a holder of the notes may be
limited to an amount equal to the sum of:
- the initial offering price allocable to the notes; plus
- stated interest and original issue discount that has accrued on the notes
as of the date of any bankruptcy filing; less
- any payments made on the notes before the bankruptcy filing.
Our principal stockholder owns approximately 65% of our class A common stock,
representing 55% of our total common stock outstanding, which may prevent new
investors from influencing corporate decisions.
Richard Bowman, our principal stockholder and Chief Executive Officer, owns
approximately 65% of our class A common stock, which represents 55% of our total
common stock outstanding. As a consequence, Mr. Bowman is able to affect the
outcome of all matters requiring stockholder approval, including the approval of
significant corporate transactions, such as transactions involving a change of
control. The interests of Mr. Bowman may differ from yours, and Mr. Bowman may
vote his class A common stock in a manner that may adversely affect you.
Jefferies & Company, Inc. owns all of our class B common stock, representing
approximately 15% of our total common stock outstanding, and will have special
class voting and other rights in connection with such ownership.
Jefferies & Company, Inc. owns all of the outstanding shares of our class B
common stock, which votes as a separate class on all matters subject to a
stockholder vote. By voting as a separate class, Jefferies is able to affect the
outcome of all matters submitted to a stockholder approval. Additionally,
Jefferies will be entitled to elect one member to serve as a non-voting advisory
director to our board of directors and to cause us, at any time, to increase the
size of our board of directors and to immediately elect a majority of the
directors. These additional rights will allow Jefferies to exercise control over
our management and operations at any time. The interests of Jefferies may differ
from yours, and Jefferies may exercise its voting and other special rights in a
manner that may adversely affect you. The class voting and other special rights
of Jefferies will terminate under certain circumstances, including at the
election of Jefferies.
12
There is currently no public market for the notes, and there may never be a
public market for the notes.
There is currently no public market for the old notes or the new notes. We
do not intend to list the old notes or the new notes on any national securities
exchange or to seek the admission thereof to trading over the National
Association of Securities Dealers Automated Quotation System. The old notes
currently are eligible for trading by qualified institutional buyers in the
PORTAL market.
Trading in the notes may not develop or may be sporadic, limiting the
ability of holders of the notes to sell their notes. To the extent trading does
occur, volumes may be limited and prices may be volatile as a consequence of
this and other factors, many of which are beyond our control, including:
- changes in oil and natural gas prices;
- actual or anticipated variations in quarterly operating results; and,
- additions or departures of key personnel.
Debt covenants may limit our future flexibility in obtaining additional
financing and in pursuing business opportunities.
Covenants in the notes will require us to meet certain financial tests in
order to incur additional indebtedness. Failing to comply with such tests and
incurring additional indebtedness could cause an event of default under the
terms of the indenture. If we are unable to borrow additional money or obtain
additional financing, our ability to successfully operate and service our debt
obligations could be hindered and we may not be able to make scheduled debt
payments of principal and interest to the holders of the notes. Please read
"-- Our significant leverage and lack of capital resources may affect our
ability to successfully operate and service our debt obligations" beginning on
page 14.
The guarantee by our subsidiary and any guarantees by future subsidiaries
could be deemed fraudulent conveyances under certain circumstances, and a
court may subordinate or void the subsidiary guarantees.
Various fraudulent conveyance laws could be utilized by a court to
subordinate or avoid the guarantee by our subsidiary and any guarantees by
future subsidiaries. It is also possible that under certain circumstances a
court could hold that the direct obligations of the guarantor could be superior
to the obligations under the guarantee of the notes.
Generally, to the extent that a court were to find that at the time a
guarantee was entered into either:
- the guarantee was incurred with the intent to hinder, delay or defraud
any present or future creditor or that our subsidiary contemplated
insolvency and intended to favor one or more creditors to the exclusion
in whole or in part of others;
- our subsidiary did not receive fair consideration or reasonably
equivalent value for issuing the guarantee;
- our subsidiary was insolvent or rendered insolvent by reason of the
issuance of the guarantee;
- our subsidiary was engaged or about to engage in a business or
transaction for which its remaining assets constituted unreasonably small
capital; or
- our subsidiary intended to incur, or believed that it would incur, debts
beyond its ability to pay such debts as they matured;
13
then the court could, among other things, avoid all or a portion of the
guarantee, or subordinate the guarantee to other existing and future debt of our
subsidiary. The result would be to entitle other creditors to be paid in full
before any payment could be made on the guarantee.
Among other things, a legal challenge to the guarantee might focus on the
benefits, if any, realized by our subsidiary as a result of the issuance by us
of the notes. To the extent the guarantee is avoided as a fraudulent conveyance
or held unenforceable for any other reason, you would cease to have any claim
against our subsidiary and would be a creditor solely of us.
RISKS RELATING TO OUR BUSINESS, FINANCES AND OPERATIONS
Our bankruptcy may adversely affect our ability to conduct our future
operations.
On June 18, 2001, we exited bankruptcy under Chapter 11 of the U.S.
Bankruptcy Code. Our prior bankruptcy may adversely affect the conduct of our
future operations by causing vendors and others from whom we purchase goods or
services to be reluctant to do business with us. These vendors may request
payment in advance, refuse to extend us credit, or give us terms less favorable
than our competitors. We currently do business with certain vendors that require
us to pay in advance for goods or services. These limitations make us more
susceptible to timing differences between our receipt of payment and our
expenditures, which requires us to carefully manage our collections and
disbursements, and may hinder our ability to adjust rapidly to changing market
conditions. In addition, our recourse to bankruptcy protection were we to
require it is limited for the 6 years following the date we filed bankruptcy,
March 14, 2000, unless we waive the benefits of our past discharge.
Our significant leverage and lack of capital resources may affect our ability
to successfully operate and service our debt obligations.
Our level of indebtedness as of June 30, 2001, was $130.0 million, as
compared to adjusted EBITDA on a pro forma basis for the year ended December 31,
2000 of $42.0 million and for the six months ended June 30, 2001 of $36.8
million. Under the indenture we are permitted to incur, subject to certain
conditions, up to $20.0 million of additional secured debt through the issuance
of additional notes and additional amounts by other means.
Our level of indebtedness and lack of capital resources could have several
important effects on our future operations, which in turn could have important
consequences to you as a holder of the notes, including, without limitation:
- impairing our ability to obtain additional financing for working capital,
capital expenditures or general corporate or other purposes in the
future;
- placing us at a competitive disadvantage relative to competitors that
have less indebtedness, by requiring us to dedicate a substantial portion
of our cash flow from operations to payments on our indebtedness and
thereby reducing the availability of our cash flow to fund working
capital, capital expenditures, general corporate expenditures and other
purposes;
- causing us to be unable to satisfy our amortization payments due on the
notes on June 1, 2002, 2003 and 2004;
- causing us to be unable to repurchase, upon a change of control, all of
the outstanding notes, together with any accrued and unpaid interest to
the date of repurchase;
- causing us to be unable to repurchase notes pursuant to an asset sale
offer or an excess cash flow offer; and
- limiting or hindering our ability to adjust rapidly to changing market
conditions, making us more vulnerable in the event of a downturn in
general economic conditions or our business.
Our ability to make scheduled payments of principal and interest with
respect to our indebtedness, including the notes, or to refinance such
obligations will depend on our financial and
14
operating performance, which, in turn, will be subject to prevailing economic
conditions and to certain financial, business and other factors beyond our
control. If our near-term cash flow is consumed by our debt service, we may be
forced to reduce or delay planned capital expenditures, sell assets, obtain
additional equity capital or attempt to restructure our indebtedness.
Historically, we have financed acquisition, exploration and development
activities primarily through various credit facilities and with internally
generated funds. We currently intend to continue our development and exploration
activities. However, our ability to expend the capital necessary to undertake or
complete future activities may be limited and we may not have adequate funds
available to us to carry out our growth strategy. Please read "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources," beginning on page 45, and our
consolidated financial statements and the related notes included in this
prospectus.
Our estimates of oil and natural gas reserves and future net revenue are
uncertain and inherently imprecise.
This prospectus contains estimates of our proved reserves and the estimated
future net revenues from our proved reserves. Estimating oil and natural gas
reserves and their values involves numerous uncertainties, including many
factors beyond our control. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas, which cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net revenues necessarily depend upon a number
of variable factors and assumptions, including the following:
- historical production from the area compared with production from other
producing areas;
- the assumed effects of regulation by governmental agencies; and
- assumptions concerning future oil and natural gas prices, future
operating costs, severance and excise taxes, development costs and
workover and remedial costs.
Because of the variable factors and assumptions involved in the estimation
of reserves, different engineers or the same engineers at different times may
reach substantially different results in their estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, their classification of reserves based on risk recovery and
their estimates of the future net revenues expected from reserves. In addition,
reserve estimates may be adjusted downward or upward because of changes in such
factors and assumptions.
Because all reserve estimates are subjective to some degree, each of the
following items may differ materially from those assumed in the estimated
reserves:
- the quantities of oil and natural gas that are ultimately recovered;
- the production and operating costs incurred;
- the amount and timing of future development expenditures; and
- future oil and natural gas prices.
The present values of estimated future net revenues referred to in this
prospectus should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to our properties. In accordance with
applicable requirements of the SEC, the estimated discounted future net revenues
from proved reserves are generally based on prices and costs as of the date of
15
the estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net revenues also will be affected by factors such as:
- the amount and timing of actual production;
- supply and demand for oil and natural gas;
- curtailments or increases in consumption by natural gas purchasers; and
- changes in governmental regulations or taxation.
The timing of actual future net revenues from proved reserves, and their
actual present value, will be affected by both the timing of the production and
the incurrence of expenses in connection with development and production of oil
and natural gas properties. In addition, the calculation of the present value of
the future net revenues using a 10% discount, as required by the SEC, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with our reserves or the oil and
natural gas industry in general.
Oil and natural gas prices are volatile. A decline in prices could adversely
affect our financial results, cash flows, access to capital and ability to pay
debt.
The price we receive for our oil and natural gas production has a
significant effect on our financial results, profitability, future rate of
growth and the carrying value of our oil and natural gas properties. Prices also
affect the amount of cash flow available to pay debt, to make capital
expenditures and our ability to borrow money or obtain other forms of financing.
Historically, prices for oil and natural gas have been volatile and may continue
to be volatile in the future. Additionally, oil and natural gas prices may vary
significantly by geographic region and have been particularly volatile in
California where much of our natural gas is produced and sold. The prices we are
currently receiving for our production are near historic highs in all our areas.
Wide fluctuations in oil and natural gas prices may result from relatively minor
changes in the supply of and demand for oil and natural gas, market uncertainty
and other factors beyond our control including:
- worldwide and domestic supplies of oil and natural gas;
- weather conditions;
- the level of consumer demand;
- the price and availability of alternative fuels;
- the availability of pipeline capacity;
- the price and level of foreign imports;
- domestic and foreign governmental regulations and taxes;
- the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
- political instability or armed conflict in oil producing regions; and
- the overall economic environment.
These factors and the volatility of the energy markets generally make it
extremely difficult to predict future oil and natural gas price movements with
any certainty. Declines in oil and natural gas prices would not only reduce
revenue, but could reduce the amount of oil and natural gas that we can produce
economically and, as a result, could adversely effect both our financial
condition and our oil and natural gas reserves.
16
Drilling involves numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be encountered.
Our success is significantly affected by risks associated with drilling and
other operational activities. We do not ourselves conduct the actual drilling
operations, but hire drilling companies at standard industry rates. Perhaps the
most significant drilling risk is the risk that no oil or natural gas will be
found that can be produced at a profit. New wells we drill may be unproductive
or we may not be able to recover all or any portion of our investment in wells
drilled. The seismic data and other technologies we may use do not allow us to
know conclusively prior to drilling a well that oil or natural gas is present or
may be produced economically. The cost of drilling, completing and operating a
well is often uncertain, and cost factors can adversely affect the economics of
a project. Our efforts will be unprofitable if we drill dry holes or wells that
are productive but do not produce enough reserves to return a profit after
drilling, operating and other costs. If we are not successful in finding
productive oil and natural gas reservoirs or drilling productive oil and natural
gas wells, or if drilling costs are significantly higher than projected, our
financial results may suffer. Further, drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, including the
following:
- unexpected drilling conditions;
- pressure or irregularities in formations;
- equipment failures or accidents;
- adverse weather conditions;
- compliance with environmental and other governmental requirements;
- title problems; and
- costs of, shortages of or delays in the availability or delivery of
equipment or qualified operating personnel.
Hedging transactions may limit our potential profits from operations.
To manage our exposure to price risks in the marketing of our oil and
natural gas production, we have in the past and will be required in the future
under the terms of the indenture, subject to certain conditions, to enter into
oil and natural gas price hedging arrangements with respect to a portion of our
expected production. Our hedging arrangements may include futures contracts on
the NYMEX. Our hedging transactions may limit our potential profits if oil and
natural gas prices were to rise substantially over the price established by the
hedge.
Hedging transactions may expose us to the risk of loss in certain
circumstances, including instances in which:
- our production is materially less than expected;
- there is volatility of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement or
the sales prices for the quality of our oil and natural gas and the sales
price of the quality assumed in the hedge; or
- the counterparties to our future contracts fail to perform the contracts.
In connection with the original offering, we agreed to maintain, on a
monthly basis, a rolling two-year hedge program until the maturity of the old
notes and the new notes, subject to certain conditions. 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) is hedged through June 30, 2003 at swap prices $4.19 per Mcf and
$25.30 per Bbl, or a weighted-average natural gas-equivalent price of
approximately $4.20 per Mcfe.
17
If we are unable to adequately replace our reserves, our ability to sustain
production and our long-term financial performance will be adversely impacted.
The volume of production from oil or natural gas properties generally
decreases as more oil and natural gas is produced from a property and reserves
are depleted. The rate at which the decrease occurs depends upon the geologic
characteristics of a particular property. If we do not find new oil and natural
gas production either by our exploration and development efforts or acquisition,
then our proved reserves will decrease as we produce oil and natural gas. Our
future oil and natural gas production rates are therefore highly dependent upon
our level of success in finding, developing or acquiring additional reserves.
Finding, developing or acquiring additional reserves requires significant
capital expenditures. In addition, at December 31, 2000, approximately 34% of
our total estimated proved reserves were undeveloped. By their nature,
undeveloped reserves are less certain than developed reserves and recovery of
such reserves will require greater capital expenditures and successful drilling
operations. If we do not make significant capital expenditures, we may not be
able to replace produced reserves.
Historically, we have funded our capital expenditures primarily through
various credit facilities and with internally generated funds. Future cash flows
are subject to a number of variables, such as the level of production from
existing wells, prices of oil and natural gas and our success in developing and
producing new reserves. If revenue were to decrease as a result of lower oil and
natural gas prices or decreased production, and our access to capital were
limited, we would have a reduced ability to replace our reserves. Due to our
limited capital resources and required debt repayment as discussed beginning on
page 14 under the heading "-- Our significant leverage and lack of capital
resources may affect our ability to successfully operate and service our debt
obligations," if revenue were to decrease as a result of lower oil and natural
gas prices or decreased production, we might not be able to make sufficient
capital investments to replace our oil and natural gas reserves. Even if funds
are available, we may not be able to successfully find, develop or acquire
additional oil and natural gas proved reserves that are economically
recoverable.
Our business involves operating hazards and uninsured risks.
Our drilling and production and other operations, and the transportation of
production by others, also involve a number of hazards and risks such as fires,
natural disasters, explosions, blowouts and spills. If any of these risks occur,
we could sustain substantial losses as a result of:
- injury or loss of life;
- severe damage or destruction to property, natural resources and
equipment;
- pollution or other environmental damage;
- clean-up responsibilities;
- regulatory investigations and penalties; and
- suspension of operations.
We are not fully insured against some of these risks, either because the
insurance is not available or because of high premium costs. If a significant
accident or other event happens and is not fully covered by insurance, we could
be required to pay some or all of the costs associated with the accident or
event, which may require us to divest resources needed for other purposes. Also,
we cannot predict the continued availability of insurance at premium levels
that, in our sole discretion, justify its purchase.
Our industry is extremely competitive and many of our competitors have
superior resources.
The energy industry is extremely competitive. This is especially true with
regard to exploration for, and development and production of, new sources of oil
and natural gas. As an independent producer of oil and natural gas, we encounter
substantial competition in acquiring properties suitable for exploration, in
contracting for drilling equipment and other services, in marketing oil and
natural gas and in securing trained personnel. We frequently compete against
companies that have
18
substantially larger financial resources, staffs and facilities. If we directly
compete against one of those larger companies in a desired acquisition of oil
and natural gas properties or in the hiring of experienced and skilled
personnel, we may not have the resources available to obtain the desired result.
We depend heavily on the services of key personnel and the loss of their
services could have an adverse effect on our ability to operate.
We depend to a large extent on the services of Richard Bowman, Jeffrey T.
Janik and Suzanne R. Ambrose. The loss of the services of these key personnel
could impair our ability to manage our business and properties. We do not
currently have employment contracts with these key personnel and do not
currently maintain key man life insurance on their lives. We believe that our
success is also dependent upon our ability to continue to employ and retain
skilled technical personnel.
Higher oil and natural gas prices adversely affect the cost and availability
of drilling and production services.
Higher oil and natural gas prices, such as those we are currently
experiencing, generally stimulate increased demand and result in increased
prices for drilling rigs, crews and associated supplies, equipment and services.
We have recently experienced significantly higher costs and reduced availability
for drilling rigs and other related services and expect such costs to continue
to escalate.
Our operations are subject to significant government regulation that may
change over time.
Our oil and natural gas operations are subject to various federal, state
and local governmental laws and regulations that may change in response to
economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling and abandonment bonds or
other financial responsibility requirements, reports concerning operations, the
spacing of wells, utilization and pooling of properties, taxation and the
environment. From time to time, regulatory agencies have imposed price controls
and production limitations to conserve supplies of oil and natural gas. A
significant portion of our production of natural gas is from our properties in
the Sacramento Basin in California. As a result of the recent energy crises in
California, certain bills are currently being considered by the California
legislature which could impose civil and criminal penalties on producers of
natural gas or electric power who curtail production or sell energy "at prices
above marginal cost." We cannot determine at this time the effect, if any, that
such legislation, were it enacted, would have on our operations. We are not
aware that any similar legislation is currently proposed by any other state in
which we operate.
In addition, the production, handling, storage, transportation and disposal
of oil and natural gas, their by-products and other substances and wastes
generated, produced or used in connection with oil and natural gas operations
are regulated under federal, state and local laws and regulations relating to
the protection of health and the environment. These laws and regulations may
impose increasingly strict requirements for water and air pollution control,
spill cleanups and solid waste management. Our failure to meet any of the
foregoing requirements could result in a suspension of our operations, as well
as administrative, civil, and even criminal, penalties. See "Business and
Properties -- Regulation" beginning on page 60 for more detail.
We may not be able to profitably sell all of the oil and natural gas we
produce.
The marketability of our oil and natural gas production depends upon the
availability and capacity of natural gas gathering systems, pipelines and
processing facilities. If such capacity is not available, we might have to
shut-in producing wells or delay or discontinue development plans for
properties. In addition, federal and state regulation of oil and natural gas
production and transportation, general economic conditions and changes in supply
and demand could adversely affect our ability to produce and market our oil and
natural gas on a profitable basis.
19
Our earnings may not be sufficient to cover fixed charges.
For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income after reorganization costs and before income taxes plus
interest expense, including amortization of premiums, discounts, and capitalized
expenses related to indebtedness. Fixed charges represent interest expense
(including amortization of deferred finance charges and an estimated portion of
rentals representing interest costs). Our earnings were insufficient to cover
fixed charges by $15.8 million, $9.2 million, $5.7 and $20.6 million for the
years ended December 31, 1998, 1999, 2000 and on a pro forma basis for the year
ended December 31, 2000, respectively. If, in the future, our earnings are
insufficient to cover our fixed charges, we may be unable to satisfy our
obligations under the notes and indenture or may be required to dedicate a
substantial portion of our cash reserves and other resources to cover these
charges, reduce or delay planned capital expenditures, sell assets, obtain
additional equity capital or attempt to restructure our indebtedness.
FORWARD-LOOKING STATEMENTS
This prospectus contains statements about future events and expectations
which can be characterized as forward-looking statements, including, in
particular, statements about our plans, strategies and prospects. The use of the
words "anticipate," "estimate," "expect," "may," "project," "believe" and
similar expressions are intended to identify future uncertainties. Although we
believe that the plans, intentions and expectations reflected in or suggested by
such forward-looking statements are reasonable, they do involve certain
assumptions, risks and uncertainties, and we cannot assure you that those
expectations will prove to have been correct. Actual results could differ
materially from those anticipated in these forward-looking statements as a
result of the risk factors set forth in this prospectus under the heading "Risk
Factors" beginning on page 11 and other factors identified elsewhere in this
prospectus. Many of these factors are beyond our ability to control or predict.
We caution you against putting any undue reliance on forward-looking statements
or projecting future results based on such statements. All subsequent written
and oral forward-looking statements attributable to us and persons acting on our
behalf are qualified in their entirety by the cautionary statements contained in
this section and elsewhere in this prospectus. Forward-looking statements
include statements concerning the following matters:
- levels of oil and natural gas production and trends or expectations
concerning oil or natural gas prices;
- oil and natural gas reserve estimates;
- anticipated administrative, operational and other costs;
- development and exploration opportunities and projects;
- potential liabilities or the expected absence thereof;
- changes in the level and timing of future costs and expenses relating to
drilling and operating activities;
- weather conditions, governmental and environmental regulation, third
party pipeline delivery systems, service providers, labor matters,
unanticipated curtailments or disruptions in natural gas production or
transportation; and
- our ongoing creditworthiness.
We do not have any obligation or undertaking to disseminate any updates or
revisions to any forward-looking statement contained in this prospectus to
reflect any change in our expectations about the statement or any change in
events, conditions or circumstances on which the statement is based.
20
THE COMPANY
Tri-Union Development Corporation was formed as a Texas corporation in 1996
in connection with the acquisition of the operations of Reunion Energy Company.
Tri-Union Operating Company, our wholly-owned subsidiary, is a Delaware
corporation that was also formed in 1996 in connection with the Reunion
acquisition.
On July 27, 2001, we were the surviving corporation in a merger with our
parent corporation, Tribo Petroleum Corporation. As a consequence of the merger,
we assumed all of the rights and obligations of Tribo. Tribo was incorporated in
Texas in 1992 by Mr. Bowman to acquire and develop oil and natural gas
properties, typically by serving as operator and retaining a working interest in
its properties while financing its net drilling costs through the sale of a
majority of the working interest. Tribo had only a few properties and no
significant reserves until 1996, when it acquired Reunion.
The acquisition of Reunion was structured so that Tri-Union Development
acquired substantially all of Reunion's operations except a net profit interest
in the Sutter Buttes field, which was acquired by Tri-Union Operating. Tri-Union
Operating's interest in the Sutter Buttes field is its only oil and natural gas
property and represents less than approximately 5% of our consolidated net
proved oil and natural gas reserves.
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation with 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 of that year. The resultant negative effect on our cash flow
from the deterioration of commodity prices, coupled with the required
amortization payments on our bank loan, severely restricted the amount of
capital we were able to dedicate to development drilling. Consequently, our oil
and natural gas production declined, further negatively affecting our cash flow.
In October 1998, our short-term loan matured and we arranged a forbearance
agreement providing for interest payments to be partially capitalized and
providing us with additional time to refinance our obligations. In July 1999,
this 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 debt had increased as a result of
capitalized interest and expenses to approximately $105 million. In February
2000, the bank declared a default on the loan, demanded payment of all principle
and interest and posted the shares of Tribo Petroleum Corporation, our parent
corporation and a guarantor of the loan, for foreclosure. As a consequence of
the bank's foreclosure action, on March 14, 2000, we filed for bankruptcy
protection under Chapter 11 of the U.S. Bankruptcy Code. Tri-Union Operating
continued to operate outside of bankruptcy. We filed our amended plan of
reorganization in the bankruptcy proceeding on May 9, 2001. Our plan was
confirmed by a court order entered as of May 23, 2001, subject to the completion
of the original offering. On June 18, 2001, the original 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.
21
THE EXCHANGE OFFER
PURPOSE OF THE EXCHANGE OFFER
The old notes were issued on June 18, 2001, as part of a unit offering (the
"original offering"), each unit consisting of one old note in the principal
amount of $1,000 and one share of the class A common stock of Tribo Petroleum
Corporation, our former parent corporation. The units were sold to Jefferies &
Company, Inc., in reliance upon the exemption provided by Section 4(2) of the
Securities Act. Jefferies then sold the units to qualified institutional buyers
in reliance on Rule 144A under the Securities Act.
In connection with the sale of the old notes, we entered into a
registration rights agreement with Jefferies. The sole purpose of the exchange
offer is to fulfill our obligations under the registration rights agreement. The
registration rights agreement provides that unless the exchange offer would not
be permitted by applicable law or SEC policy, we will (i) file an exchange offer
registration statement with the SEC on or prior to 60 days after the date of
original issuance of the old notes, (ii) use our best efforts to have the
exchange offer registration statement declared effective by the SEC on or prior
to 120 days after the date of original issuance of the old notes, (iii) commence
the exchange offer and use our best efforts to issue, on or prior to 60 days
after the date on which the exchange offer registration statement was declared
effective by the SEC, publicly registered notes, in exchange for all old notes
tendered prior thereto in the exchange offer; provided that if we have not
consummated the exchange offer within 180 days of the date of original issuance
of the old notes, then we will file the shelf registration statement with the
SEC on or prior to the 181st day after the date of original issuance of the old
notes and use our best efforts to cause the shelf registration statement to be
declared effective within 60 days after such filing. We will be required to use
our best efforts to keep the shelf registration statement continuously
effective, supplemented and amended until the second anniversary of the date of
original issuance of the old notes or such shorter period that will terminate
when all the transfer restricted notes covered by the shelf registration
statement have been sold.
If (i) we fail to file any of the registration statements required by the
registration rights agreement on or before the date specified for such filing,
(ii) any of the registration statements is not declared effective by the SEC or
prior to the date specified for effectiveness, (iii) we fail to consummate the
exchange offer within 60 days of the date specified for effectiveness with
respect to the exchange offer registration statement, or (iv) the shelf
registration statement with respect to the notes or the exchange offer
registration statement is declared effective but thereafter, subject to certain
exceptions, ceases to be effective or usable in connection with the exchange
offer or resales of transfer restricted notes, as the case may be, during the
periods specified in the registration rights agreement, then the interest rate
on the old notes will increase, with respect to the first 90-day period
immediately following the occurrence of any default referred to above by 0.50%
per annum and will increase by an additional 0.50% per annum with respect to
each subsequent 90-day period until all such defaults have been cured, up to a
maximum amount of 2% per annum with respect to all such defaults. Following the
cure of all such defaults, the accrual of all such additional interest will
cease and the interest rate will revert to the original rate.
Each broker-dealer that receives new notes for its own account in exchange
for old notes, where such notes were acquired by the broker-dealer as a result
of market-making activities or other trading activities, must acknowledge that
it will deliver a prospectus in connection with any resale of such new notes.
See "Plan of Distribution" beginning on page 118.
TERMS OF THE EXCHANGE OFFER
We offer to exchange, upon the terms and subject to the conditions set
forth herein and in the letter of transmittal, up to $130,000,000 in principal
amount of new senior secured notes for up to $130,000,000 in principal amount of
old senior secured notes. The terms of the new notes are
22
identical in all material respects to the terms of the old notes, except that
the new notes will not generally be subject to the transfer restrictions
applicable to the old notes and the holders of the new notes (as well as
remaining holders of any old notes) will not be entitled to registration rights
under the registration rights agreement. The new notes will evidence the same
debt as the old notes and will be entitled to the benefits of the indenture
pursuant to which such old notes were issued. See "Description of the Senior
Secured Notes" beginning on page 71.
Based on interpretations by the staff of the SEC, as set forth in no-action
letters issued to third parties, we believe that the new notes issued in the
exchange offer for old notes may be offered for resale, resold or otherwise
transferred by holders thereof (other than any such holder which is an
"affiliate" of us within the meaning of Rule 405 under the Securities Act)
without compliance with the registration and prospectus delivery provisions of
the Securities Act, provided that the new notes are acquired in the ordinary
course of the holder's business and the holder has no arrangement with any
person to participate in the distribution of the new notes. However, we have not
requested the SEC to issue, and the SEC has not issued, a no-action letter with
regard to the exchange offer, and there is no assurance that the staff of the
SEC would make a similar determination with respect to the exchange offer as in
such other circumstances. Each holder, other than a broker-dealer, will be
required to acknowledge that it is not engaged in, and does not intend to engage
in, a distribution of new notes and has no arrangement or understanding to
participate in a distribution of new notes. If any holder is an affiliate of us,
is engaged in or intends to engage in or has any arrangement or understanding
with respect to the distribution of the new notes to be acquired in the exchange
offer, the holder cannot rely on the applicable interpretations of the staff of
the SEC and must comply with registration and prospectus delivery requirements
of the Securities Act in connection with any resale transaction. Each
broker-dealer that receives new notes for its own account in the exchange offer
must acknowledge that it will deliver a prospectus in connection with any resale
of the new notes. The letter of transmittal states that by so acknowledging and
by delivering a prospectus a broker-dealer will not be deemed to admit that it
is an "underwriter" within the meaning of the Securities Act. This prospectus,
as it may be amended or supplemented from time to time, may be used by a
broker-dealer in connection with resales of new notes received in exchange for
old notes where the old notes were acquired by the broker-dealer as a result of
market-making activities or other trading activities (other than old notes
acquired directly from us). We have agreed that for a period of 180 days
following the consummation of the exchange offer we will make this prospectus
available to any broker-dealer for use in connection with any resale. See "Plan
of Distribution" beginning on page 118.
Tendering holders of old notes will not be required to pay brokerage
commissions or fees or, subject to the instructions in the letter of
transmittal, transfer taxes with respect to the exchange of the old notes.
Interest on each new note will accrue from the last date on which interest
was paid on such old notes surrendered in exchange therefor or, if no interest
has been paid, from the date of original issuance of the old notes.
Holders whose old notes are accepted for exchange will receive accrued
interest to, but not including, the date of issuance of the new notes, such
interest to be payable with the first interest payment on the new notes, but
will not receive any payment in respect of interest on the old notes accrued
after the issuance of the new notes.
EXPIRATION DATE; EXTENSIONS; TERMINATION; AMENDMENTS
The exchange offer expires at 5:00 p.m., New York City time on
, 2001, unless we in our sole discretion extend the period during
which the exchange offer is open. We will be entitled to close the exchange
offer 30 days after commencement, provided, however, that we have accepted all
old notes theretofore validly surrendered in accordance with the term of the
exchange offer. We reserve the right to extend the exchange offer at any time
and from time to time prior to the expiration date by giving written notice to
Firstar Bank, National Association (the "Exchange Agent")
23
and by timely public announcement communicated, unless otherwise required by
applicable law or regulation, by making a press release. During any extension of
the exchange offer, all old notes previously tendered will remain subject to the
exchange offer.
We expressly reserve the right to terminate the exchange offer and not
accept for exchange any old notes for any reason, including if any of the events
set forth below under "-- Conditions to the Exchange Offer" shall have occurred
and shall not have been waived by us and to amend the terms of the exchange
offer in any manner, whether before or after any tender of the old notes. Terms
of the exchange offer which affect the note holders only shall not be amended,
modified or supplemented, nor will waivers from such provisions be given unless
we have obtained the written consent of the holders of at least a majority in
aggregate principal amount of the old notes. If any termination or amendment
occurs, we will notify the Exchange Agent in writing and will either issue a
press release or give written notice to the holders of the old notes as promptly
as practicable. Unless we terminate the Exchange Offer prior to 5:00 p.m. New
York City time, on the date set forth above, we will exchange the new notes for
the old notes promptly following the expiration of the exchange offer.
If we waive any material condition to the exchange offer, or amend the
exchange offer in any other material respect, and if the exchange offer is
scheduled to expire less than five business days from and including the date
notice of the waiver or amendment is first published, sent or given to holders
of old notes, then the exchange offer will be extended until the expiration of
such period of five business days.
This prospectus and the related letter of transmittal and other relevant
materials will be mailed by us to record holders of old notes and will be
furnished to brokers, banks and similar persons whose names, or the names of
whose nominees, appear on the lists of holders for subsequent transmittal to
beneficial owners of old notes.
EXCHANGE OFFER PROCEDURES
The tender of old notes to us by a holder pursuant to one of the procedures
set forth below will constitute an agreement between the holder and us in
accordance with the terms and subject to the conditions set forth in this
prospectus and in the letter of transmittal. All references in this prospectus
to the letter of transmittal are deemed to include a facsimile of the letter of
transmittal.
General Procedures. A holder of an old note may tender the same by:
- properly completing and signing the letter of transmittal or a facsimile
thereof;
- properly completing any required signature guarantees;
- properly completing any other documents required by the letter of
transmittal; and
- delivering all of the above, together with the certificate or
certificates representing the old notes being tendered, to the Exchange
Agent at its address set forth below under "-- Exchange Agent" on or
prior to the expiration date; or
- complying with the procedure for book-entry transfer described below; or
- complying with the guaranteed delivery procedures described below.
The signature on the letter of transmittal need not be guaranteed if:
- tendered old notes are registered in the name of the signer of the letter
of transmittal; and
- the new notes are registered in the name of the signer of the letter of
transmittal; and
- any untendered old notes are to be reissued in the name of the holder.
24
In any other case, the tendered old notes must be:
- endorsed or accompanied by written instruments of transfer in form
satisfactory to us;
- the signature on the endorsement or instrument of transfer must be
guaranteed by a bank, broker, dealer, credit union, savings association,
clearing agency or other institution, each an "eligible guarantor
institution" within the meaning of Rule 17Ad-15 under the Exchange Act
and that is a member of a recognized signature guarantee medallion
program (an "Eligible Institution").
If the new notes and/or old notes not exchanged are to be delivered to an
address other than that of the registered holder appearing on the note register
for the old notes, the signature in the letter of transmittal must be guaranteed
by an Eligible Institution.
Any beneficial owner whose old notes are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee and who wishes
to tender old notes should contact the registered holder promptly and instruct
the holder to tender old notes on the beneficial owner's behalf. If the
beneficial owner wishes to tender the old notes himself, the beneficial owner
must, prior to completing and executing the letter of transmittal and delivering
the old notes, either make appropriate arrangements to register ownership of the
old notes in such beneficial owner's name or follow the procedures described in
the immediately preceding paragraph. The transfer of record ownership may take
considerable time.
THE METHOD OF DELIVERY OF OLD NOTES AND ALL OTHER DOCUMENTS IS AT THE
ELECTION AND RISK OF THE HOLDER. IF SENT BY MAIL, IT IS RECOMMENDED THAT
REGISTERED MAIL, RETURN RECEIPT REQUESTED, BE USED, PROPER INSURANCE BE
OBTAINED, AND THE MAILING BE MADE SUFFICIENTLY IN ADVANCE OF THE EXPIRATION DATE
TO PERMIT DELIVERY TO THE EXCHANGE AGENT ON OR BEFORE THE EXPIRATION DATE.
Book-Entry Transfer. The old notes were issued as global securities in
fully registered form without interest coupons. Beneficial interests in the
global securities, held by direct or indirect participants in the DTC, are shown
on, and transfers of these interests are effected only through, records
maintained in book-entry form by the DTC with respect to its participants.
The Exchange Agent will make a request within two business days after
receipt of this prospectus to establish an account with respect to the
book-entry interests at the DTC for purposes of facilitating the exchange offer
unless a suitable account has already been established. You must deliver your
book-entry interest by book-entry transfer to the account maintained by the
Exchange Agent at the DTC. Any financial institution that is a participant in
the DTC's systems may make book-entry delivery of book-entry interests by
causing the DTC to transfer the book-entry interests into the Exchange Agent's
account at the DTC in accordance with the DTC's procedures for transfer.
If you hold your old notes in the form of book-entry interests and you wish
to tender your old notes for exchange, you must transmit to the Exchange Agent
on or prior to the expiration date either: a written or facsimile copy of a
properly completed and duly executed letter of transmittal, including all other
documents required by the letter of transmittal, to the Exchange Agent at the
address set forth below under "-- Exchange Agent"; or a computer-generated
message transmitted by means of the DTC's Automated Tender Offer Program system
and received by the Exchange Agent and forming a part of a confirmation of
book-entry transfer, in which you acknowledge and agree to be bound by the terms
of the letter of transmittal.
In addition, in order to deliver old notes held in the form of book-entry
interests, a timely confirmation of book-entry transfer of those old notes into
the Exchange Agent's account at the DTC must be received by the Exchange Agent
prior to the expiration date or you must comply with the guaranteed delivery
procedures described below.
25
Certificated Old Notes. If your old notes are certificated old notes and
you wish to tender those notes for exchange pursuant to the exchange offer, you
must transmit to the Exchange Agent on or prior to the expiration date a written
or facsimile copy of a properly completed and duly executed letter of
transmittal, including all other required documents, to the address set forth
below under "-- Exchange Agent." In addition, in order to validly tender your
certificated old notes, the certificates representing your old notes must be
received by the Exchange Agent prior to the expiration date or you must comply
with the guaranteed delivery procedures described below.
Guaranteed Delivery Procedures. If a holder desires to accept the exchange
offer and time will not permit a letter of transmittal or old notes to reach the
Exchange Agent before the expiration date, a tender may be effected if the
Exchange Agent has received at the address specified below under "-- Exchange
Agent" on or prior to the expiration date a letter or facsimile transmission
from an Eligible Institution setting forth the name and address of the tendering
holder, the names in which the old notes are registered and, if possible, the
certificate number of the old notes to be tendered, and stating that the tender
is being made thereby and guaranteeing that within three New York Stock Exchange
trading days after the date of execution of such letter or facsimile
transmission by the Eligible Institution, the old notes, in proper form for
transfer, will be delivered by the Eligible Institution together with a properly
completed and duly executed letter of transmittal (and any other required
documents). Unless old notes being tendered by the above-described method (or a
timely Book-Entry Confirmation) are deposited with the Exchange Agent within the
time period set forth above (accompanied or preceded by a properly completed
letter of transmittal and any other required documents), we may, at our option,
reject the tender. Copies of a Notice of Guaranteed Delivery which may be used
by Eligible Institutions for the purposes described in this paragraph are being
delivered with this prospectus and the related letter of transmittal.
A tender will be deemed to have been received as of the date when the
tendering holder's properly completed and duly signed letter of transmittal
accompanied by the old notes or a timely book-entry confirmation is received by
the Exchange Agent. Issuances of new notes in exchange for old notes tendered
pursuant to a Notice of Guaranteed Delivery or letter or facsimile transmission
to similar effect (as provided above) by an Eligible Institution will be made
only against deposit of the letter of transmittal (and any other required
documents) and the tendered old notes or a timely book-entry confirmation.
All questions as to the validity, form, eligibility (including time of
receipt) and acceptance for exchange of any tender of old notes will be
determined by us and shall be final and binding on all parties. We reserve the
absolute right to reject any or all tenders not in proper form or the acceptance
of which, or exchange for which, may, in the opinion of counsel to us, be
unlawful. We also reserve the absolute right, subject to applicable law, to
waive any of the conditions of the exchange offer or any defects or
irregularities in tenders of any particular holder whether or not similar
defects or irregularities are waived in the case of other holders. Our
interpretation of the terms and conditions of the exchange offer (including the
letter of transmittal and the instructions thereto) will be final and binding.
No tender of old notes will be deemed to have been validly made until all
defects and irregularities with respect to such tender have been cured or
waived. Neither we, the Exchange Agent nor any other person shall be under any
duty to give notification of any defects or irregularities in tenders or incur
any liability for failure to give any such notification.
Each broker-dealer that receives new notes for its own account in exchange
for old notes, where the notes were acquired by the broker-dealer as a result of
market-making activities or other trading activities, must acknowledge that it
will deliver a prospectus in connection with any resale of such new notes. See
"Plan of Distribution" beginning on page 118.
TERMS AND CONDITIONS OF THE LETTER OF TRANSMITTAL
The letter of transmittal contains, among other things, the following terms
and conditions, which are part of the exchange offer.
26
The party tendering old notes for exchange exchanges, assigns and transfers
the old notes to us and irrevocably constitutes and appoints the Exchange Agent
as the Transferor's agent and attorney-in-fact to cause the old notes to be
assigned, transferred and exchanged.
The transferor represents and warrants that it has full power and authority
to tender, exchange, sell, assign and transfer the old notes, and that, when the
same are accepted for exchange, we will acquire good, marketable and
unencumbered title to the tendered old notes, free and clear of all liens,
restrictions, changes and encumbrances and not subject to any adverse claim. The
transferor also warrants that it will, upon request, execute and deliver any
additional documents deemed by us or the Exchange Agent to be necessary or
desirable to complete the exchange, assignment and transfer of tendered old
notes. All authority conferred by the transferor will survive the death or
incapacity of the transferor and every obligation of the transferor shall be
binding upon the heirs, legal representatives, successors, assigns, executors
and administrators of such transferor. The transferor certifies that it is not
an "affiliate" of ours within the meaning of Rule 405 under the Securities Act
and that it is acquiring the new notes offered hereby in the ordinary course of
the transferor's business and that the transferor has no arrangement with any
person to participate in the distribution of the new notes.
If the transferor is not a broker-dealer, it represents that it is not
engaged in, and does not intend to engage in, a distribution of new notes. If
the transferor is a broker-dealer that will receive new notes for its own
account in exchange for old notes, it represents that the old notes to be
exchanged for new notes were acquired by it as a result of market-making
activities or other trading activities and acknowledges that it will deliver a
prospectus meeting the requirements of the Securities Act of 1933 in connection
with any resale of new notes acquired in the exchange offer; however, by so
acknowledging and by delivering a prospectus, the transferor will not be deemed
to admit that it is an "underwriter" within the meaning of the Securities Act.
WITHDRAWAL RIGHTS
Old notes tendered in the exchange offer may be withdrawn at any time prior
to the Expiration Date.
For a withdrawal to be effective, a written or facsimile transmission of
notice of withdrawal must be timely received by the Exchange Agent at its
address set forth below under "-- Exchange Agent" on or prior to the expiration
date. Any notice of withdrawal must specify the person named in the letter of
transmittal as having tendered old notes to be withdrawn, the certificate
numbers of old notes to be withdrawn, the aggregate principal amount of old
notes to be withdrawn (which must be an authorized denomination), that the
holder is withdrawing his election to have the old notes exchanged, and the name
of the registered holder of such old notes, if different from that of the person
who tendered the old notes. Additionally, the signature on the notice of
withdrawal must be guaranteed by an Eligible Institution (except in the case of
old notes tendered for the account of an Eligible Institution). The Exchange
Agent will return the properly withdrawn old notes promptly following receipt of
notice of withdrawal. All questions as to the validity of notices of
withdrawals, including time of receipt, will be final and binding on all
parties.
If old notes have been tendered pursuant to the procedures for book entry
transfer, the notice of withdrawal must specify the name and number of the
account at the DTC to be credited with the withdrawal of old notes, in which
case a notice of withdrawal will be effective if delivered to the Exchange Agent
by written or facsimile transmission. Withdrawals of tenders of old notes may
not be rescinded. Old notes properly withdrawn will not be deemed validly
tendered for purposes of the exchange offer, but may be retendered at any
subsequent time on or prior to the Expiration Date by following any of the
procedures described herein.
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ACCEPTANCE OF OLD NOTES FOR EXCHANGE; DELIVERY OF NEW NOTES
Upon the terms and subject to the conditions of the exchange offer, the
acceptance for exchange of old notes validly tendered and not withdrawn and the
issuance of the new notes will be made promptly following the expiration date.
For the purposes of the exchange offer, we shall be deemed to have accepted for
exchange validly tendered old notes when, as and if we had given notice of
acceptance to the Exchange Agent.
The Exchange Agent will act as agent for the tendering holders of old notes
for the purposes of receiving new notes from us and causing the old notes to be
assigned, transferred and exchanged. Upon the terms and subject to the
conditions of the exchange offer, delivery of new notes to be issued in exchange
for accepted old notes will be made by the Exchange Agent promptly after
acceptance of the tendered old notes. Old notes not accepted for exchange by us
will be returned without expense to the tendering holders or in the case of old
notes tendered by book-entry transfer into the Exchange Agent's account at the
DTC promptly following the expiration date or, if we terminate the exchange
offer prior to the expiration date, promptly after the exchange offer is
terminated.
CONDITIONS TO THE EXCHANGE OFFER
Notwithstanding any other provision of the exchange offer, or any extension
of an exchange offer, we will not be required to issue new notes in respect of
any properly tendered old notes not previously accepted and may terminate the
exchange offer (by oral or written notice to the Exchange Agent and by timely
public announcement communicated, unless otherwise required by applicable law or
regulation, by making a press release or, at our option, modify or otherwise
amend the exchange offer, if (i) the exchange offer, or the making of any
exchange by a note holder, would violate applicable law or any applicable
interpretation of the staff of the SEC, (ii) an action or proceeding shall have
been instituted or threatened in any court or by or before any governmental
agency or body with respect to the exchange offer, (iii) there shall have been
adopted or enacted any law, statute, rule or regulation prohibiting or limiting
the exchange offer, (iv) there shall have been declared by United States federal
or New York state authorities a banking moratorium, or (v) trading on the New
York Stock Exchange or generally in the United States over-the-counter market
shall have been suspended by order of the SEC or any other governmental
authority.
The foregoing conditions are for our sole benefit and may be asserted by us
with respect to all or any portion of the exchange offer regardless of the
circumstances (including any action or inaction by us) giving rise to such
condition or may be waived by us in whole or in part at any time or from time to
time in our sole discretion. Our failure at any time to exercise any of the
foregoing rights will not be deemed a waiver of any right, and each right will
be deemed an ongoing right which may be asserted at any time or from time to
time. In addition, we have reserved the right, notwithstanding the satisfaction
of each of the foregoing conditions, to terminate or amend the exchange offer.
Any determination by us concerning the fulfillment or non-fulfillment of
any conditions will be final and binding upon all parties.
In addition, we will not accept for exchange any old notes tendered and no
new notes will be issued in exchange for any old notes, if at such time any stop
order shall be threatened or in effect with respect to the registration
statement of which this prospectus constitutes a part or qualification under the
Trust Indenture Act of 1939 (the "Trust Indenture Act") of the indenture
pursuant to which such old notes were issued.
28
EXCHANGE AGENT
Firstar Bank, National Association has been appointed as the Exchange Agent
of the exchange offer. All executed letters of transmittal should be directed to
the Exchange Agent at its address set forth below. Questions and requests for
assistance, requests for additional copies of this prospectus or of the letter
of transmittal and requests for Notices of Guaranteed Delivery should be
directed to the Exchange Agent addressed as follows:
<Table>
By Mail/Hand Delivery/Overnight Delivery:
Firstar Bank, National Association
MN-SP-12CT 101 Fifth Street
St. Paul, Minnesota 55101-1860
Attn: Frank Leslie
</Table>
Via Facsimile:
(651) 229-6415
Confirm by telephone:
(651) 229-2600
You should direct questions and requests for assistance, requests for
additional copies of this prospectus or of the letter of transmittal and
requests for notices of guaranteed delivery to the exchange agent at the address
and telephone number set forth in the letter of transmittal.
Delivery to an address other than as set forth above, or transmissions of
instructions via facsimile number other than the ones set forth above, will not
constitute a valid delivery.
SOLICITATIONS OF TENDERS; EXPENSES
We have not retained any dealer-manager or similar agent in connection with
the exchange offer and will not make any payments to brokers, dealers or others
for soliciting acceptances of the exchange offer. We will, however, pay the
Exchange Agent reasonable and customary fees for its services and will reimburse
it for reasonable out-of-pocket expenses. We will also pay brokerage houses and
other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses
incurred by them in forwarding tenders for their customers. The expenses to be
incurred in connection with the exchange offer, including the fees and expenses
of the Exchange Agent and printing, accounting and legal fees, will be paid by
us.
No person has been authorized to give any information or to make any
representations in connection with the exchange offer other than those contained
in this prospectus. If given or made, information or representations should not
be relied upon as having been authorized by us. Neither the delivery of this
prospectus nor any exchange made based upon this prospectus shall, under any
circumstances, create any implication that there has been no change in our
affairs since the respective dates as of which information is given. The
exchange offer is not being made to (nor will tenders be accepted from or on
behalf of) holders of old notes in any jurisdiction in which the making of the
exchange offer or the acceptance of the exchange offer would not be in
compliance with the laws of such jurisdiction. However, we may, at our
discretion, take such action as we deem necessary to make the exchange offer in
any such jurisdiction and extend the exchange offer to holders of old notes in
such jurisdiction. In any jurisdiction the securities laws or blue sky laws of
which require the exchange offer to be made by a licensed broker or dealer, the
exchange offer is being made on our behalf by one or more registered brokers or
dealers that are licensed under the laws of such jurisdiction.
ACCOUNTING TREATMENT
The new notes will be recorded at the same carrying value as the old notes,
which is the principal amount as reflected in our accounting records on the
expiration date. Accordingly, no gain
29
or loss for accounting purposes will be recognized. For accounting purposes, the
expenses of the exchange offer will be deferred and amortized as interest
expense over the life of the notes.
APPRAISAL RIGHTS
Holders of old notes will not have dissenters' rights or appraisal rights
in connection with the exchange offer.
OTHER
Participation in the exchange offer is voluntary and holders should
carefully consider whether to accept. Holders of the old notes are urged to
consult their financial and tax advisors in making their own decisions on what
action to take.
As a result of the making of, and upon acceptance for exchange of all
validly tendered old notes pursuant to the terms of this exchange offer, we will
have fulfilled a covenant contained in the registration rights agreement.
Holders of the old notes who do not tender their certificates in the exchange
offer will continue to hold such certificates and will be entitled to all the
rights and limitations under the indenture pursuant to which the old notes were
issued, except for any such rights under the registration rights agreement which
by its terms terminates or ceases to have further effect as a result of the
making of this exchange offer. See "Registration Rights" beginning on page 119.
All untendered old notes will continue to be subject to the restrictions on
transfer set forth in the old notes and the indenture. To the extent that old
notes are tendered and accepted in the exchange offer, the trading market, if
any, for the old notes could be adversely affected.
We may in the future seek to acquire untendered old notes in open market or
privately negotiated transactions, through subsequent exchange offer or
otherwise. We have no present plan to acquire any old notes which are not
tendered in the exchange offer.
30
USE OF PROCEEDS
The exchange offer is intended to satisfy certain of our obligations under
the registration rights agreement. We will not receive any cash proceeds from
the issuance of the new notes pursuant to the exchange offer. The net proceeds
from the original offering, prior to the discount to Jefferies & Company, Inc.,
as initial purchaser, were approximately $122.9 million. We used the net
proceeds of the original offering and approximately $55.5 million of our
available cash balances, to pay or segregate funds for the payment of all claims
in accordance with our plan. We intend to use our remaining funds to pursue our
low-risk development drilling program and for working capital.
SOURCES OF FUNDS
------------------------------------------------------
USES OF FUNDS
------------------------------------------------------
(IN MILLIONS)
<Table>
Proceeds from sale of units......... $122.9
Estimated cash...................... 66.7
------
Total sources............. $189.6
======
</Table>
<Table>
Repayment of note payable(1)........ $104.3
Repayment of other obligations...... 32.6
Payment of accrued interest......... 20.5
Segregated funds for disputed
claims(2)......................... 11.4
Offering fees and expenses.......... 9.6
Development drilling program and
working capital................... 11.2
------
Total uses................ $189.6
======
</Table>
---------------
(1) Represents a bank loan, originally maturing on March 31, 2001, with a
short-term component originally maturing October 31, 1998, and bearing an
effective interest rate of 12.1% per annum immediately prior to repayment on
June 18, 2001.
(2) To the extent claims are resolved for less than the full amount, the balance
will be remitted to us.
31
CAPITALIZATION
The following table sets forth our consolidated indebtedness and
capitalization at June 30, 2001. Please read the following information in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations," "Use of Proceeds" and our consolidated financial
statements and related notes included in this prospectus.
<Table>
<Caption>
AT JUNE 30, 2001
----------------
(IN THOUSANDS)
Long-term debt, including current maturities:
Notes payable, net of bond discounts...................... $105,512
Other debt(1)............................................. 83
--------
Total debt........................................ 105,595
--------
Stockholders' equity (capital deficit)
Class A Common stock, $0.01 par value, 445,000 shares
authorized, 368,333 shares issued and outstanding...... 4
Class B Common stock, $0.01 par value, 65,000 shares
authorized, 65,000 shares issued and outstanding....... 1
Additional paid in capital................................ 25,380
Deficit................................................... (10,961)
--------
Total stockholders' equity........................ 14,424
--------
Total capitalization.............................. $120,019
========
</Table>
---------------
(1) Represents an unsecured financing of well control insurance policy premiums,
scheduled to be repaid by August 31, 2001.
32
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The following tables set forth our selected consolidated historical
financial data for the periods shown. The following information should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations," "Capitalization" and the consolidated financial
statements and related notes included in this prospectus.
<Table>
<Caption>
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
--------------------------------------------------- -------------------
1996 1997 1998 1999 2000 2000 2001
------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AND RATIO DATA)
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Total revenues............................. $ 5,056 $ 13,296 $ 26,352 $ 37,766 $ 74,476 $ 27,509 $ 58,733
Expenses:
Lease operating.......................... 1,829 4,845 17,450 15,542 19,485 6,804 10,480
Workover................................. 136 687 600 2,410 6,649 1,697 3,340
Production taxes......................... 160 305 639 705 1,968 712 1,342
Depreciation, depletion and
amortization........................... 838 3,037 12,398 11,040 13,506 5,394 7,262
General and administrative............... 239 2,276 3,327 5,237 4,328 2,447 3,149
Interest................................. 836 1,410 7,734 11,981 12,758 6,733 6,276
------- -------- -------- -------- -------- -------- --------
Total expenses.................... 4,038 12,560 42,147 46,916 58,695 23,788 31,850
Income (loss) before reorganization costs
and income taxes......................... 1,018 736 (15,795) (9,150) 15,780 3,721 26,883
Reorganization costs....................... -- -- -- -- 21,487 915 7,311
------- -------- -------- -------- -------- -------- --------
Income (loss) before income
taxes.................................... 1,018 736 (15,795) (9,150) (5,707) 2,807 19,572
Provision for income taxes................. 352 925 -- -- 79 -- 391
------- -------- -------- -------- -------- -------- --------
Net income (loss).......................... $ 666 $ (189) $(15,795) $ (9,150) $ (5,786) $ 2,807 $ 19,181
======= ======== ======== ======== ======== ======== ========
Net income (loss) per share -- basic and
diluted.................................. $ 2.79 $ (0.79) $ (66.27) $ (38.39) $ (24.28) $ 11.77 $ 76.01
======= ======== ======== ======== ======== ======== ========
Weighted average shares outstanding........ 238,333 238,333 238,333 238,333 238,333 238,333 252,339
======= ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Capital expenditures -- oil and natural gas
properties............................... $ 1,431 $ 20,457 $ 71,992 $ 13,572 $ 10,878 $ 3,609 $ 3,339
Adjusted EBITDA(1)......................... 2,692 5,183 4,337 13,871 42,045 15,849 36,835
Adjusted EBITDA to cash interest(2)........ 3.22x 3.68x 0.56x 1.16x 3.30x 2.35x 6.34x
Earnings to fixed charges(3)............... 2.18x 1.44x NM 0.31x 0.60x 1.40x 4.03x
Cash flows from operating activities....... $ 1,731 $ 2,516 $ 7,168 $ 12,127 $ 40,695 $ 9,988 $(24,614)
Cash flows from investing activities....... (9,544) (24,196) (71,926) (11,943) (10,118) (2,855) (1,978)
Cash flows from financing activities....... 8,439 23,324 65,153 (42) (401) (669) 6,566
</Table>
<Table>
<Caption>
AT DECEMBER 31,
--------------------------------------------------- AT JUNE 30,
1996 1997 1998 1999 2000 2001
------- -------- -------- -------- -------- ------------
(IN THOUSANDS, EXCEPT RATIO DATA)
CONSOLIDATED BALANCE SHEET DATA:
Net property and equipment.............. $11,062 $ 28,810 $ 89,194 $ 89,897 $ 87,308 $ 80,484
Total assets............................ 14,904 41,831 104,130 108,903 152,594 158,954
Stockholder's equity (capital
deficit).............................. 710 592 (15,203) (24,352) (30,139) 14,423
ACNTA(4)................................ NM 101,050 116,319 283,562 617,387 626,650
Notes payable, including current
maturities............................ 11,300 35,184 101,480 105,058 104,657 105,512
ACNTA to indebtedness................... NM 2.87x 1.15x 2.70x 5.90x 5.93x
(footnotes on following page)
</Table>
33
---------------
(1) EBITDA means earnings before interest expense, income taxes, depreciation,
depletion and amortization. Adjusted EBITDA means EBITDA before impairment
of oil and natural gas properties, reorganization costs and gains or losses
on derivative contracts. EBITDA is commonly used by debt holders and
financial statement users as a measurement to determine the ability of an
entity to meet its interest obligations. EBITDA is not a measurement
presented in accordance with generally accepted accounting principles
("GAAP") and is not intended to be used in lieu of GAAP presentation of
results of operations and cash provided by operating activities. Our
definition of adjusted EBITDA may not be identical to similarly entitled
measures used by other companies.
(2) Cash interest excludes non-cash interest for amortization of bond discount
and bond issuance costs, which are included in determining interest expense
in accordance with GAAP.
(3) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income after reorganization costs and before income taxes
plus interest expense including amortization of premiums, discounts, and
capitalized expenses related to indebtedness. Fixed charges represent
interest expense and capitalized interest (including amortization of
deferred finance charges and an estimated portion of rentals representing
interest costs). Earnings were insufficient to cover fixed charges by $15.8
million, $9.2 million and $5.7 million for the years ended December 31,
1998, 1999 and 2000, respectively. NM means "not measured."
(4) ACNTA means Adjusted Consolidated Net Tangible Assets, as defined in
"Description of the Senior Secured Notes -- Certain Definitions." ACNTA is
calculated using oil and natural gas prices utilized in our year end reserve
report. NM means "not measured."
34
UNAUDITED CONDENSED PRO FORMA FINANCIAL DATA
The following unaudited condensed pro forma financial data consists of our
unaudited condensed pro forma consolidated statement of our operations for the
year ended December 31, 2000 and the six months ended June 30, 2001. Please read
the following data in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and our consolidated financial
statements and related notes included in this prospectus. The unaudited pro
forma data illustrates the impact of the original offering and our amended plan
of reorganization, which was effective June 18, 2001, as if they had been
consummated as of January 1, 2000. The pro forma financial data is not
necessarily indicative of the results that would have occurred had the offering
and our plan been consummated as of the beginning of the periods presented or of
any future results or financial position. Pro forma amounts allocated to the
value of Tri-Union's equity securities are based on estimates which are subject
to change.
UNAUDITED CONDENSED PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS
<Table>
<Caption>
YEAR ENDED DECEMBER 31, 2000 SIX MONTHS ENDED JUNE 30, 2001
------------------------------------- ------------------------------------
HISTORICAL ADJUSTMENTS PRO FORMA HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- --------- ---------- ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AND RATIO DATA)
Total revenues................. $74,476 $ 74,476 $58,733 $58,733
------- -------- ------- -------
Expenses:
Lease operating.............. 19,485 19,485 10,480 10,480
Workover..................... 6,649 6,649 3,340 3,340
Production taxes............. 1,968 1,968 1,342 1,342
Depreciation, depletion and
amortization.............. 13,506 13,506 7,262 7,262
General and administrative... 4,328 4,328 3,149 3,149
Interest..................... 12,758 $ 15,119(1) 27,876 6,276 $ 6,790(1) $13,066
------- -------- -------- ------- ------- -------
Total expenses....... 58,695 15,119 73,814 31,850 6,790 38,639
Income (loss) before
reorganization costs and
income taxes................. 15,780 (15,119) 662 26,883 (6,790) 20,093
Reorganization costs........... 21,487 21,487 7,311 7,311
------- -------- -------- ------- ------- -------
Income (loss) before income
taxes........................ (5,707) (15,119) (20,826) 19,572 (6,790) 12,782
Provision for income taxes..... 79 (79)(2) -- 391 (136)(2) 256
------- -------- -------- ------- ------- -------
Net income (loss).............. $(5,786) $(15,040) $(20,826) $19,181 $(6,654) $12,527
======= ======== ======== ======= ======= =======
Net income (loss) per share --
basic and diluted............ $(24.28) $ (48.06) $ 76.01 $ 28.91
======= ======== ======= =======
Weighted average shares
outstanding.................. 238,333 433,333 252,339 433,333
======= ======== ======= =======
</Table>
---------------
(1) To adjust for additional interest at 12.5% on the notes and record
amortization of bond discounts and bond issuance costs.
(2) To adjust for the estimated current federal income tax liability.
(3) Other Financial Data:
<Table>
<Caption>
YEAR ENDED SIX MONTHS ENDED
DECEMBER 31, 2000 JUNE 30, 2001
PRO FORMA PRO FORMA
----------------- ------------------
Adjusted EBITDA(a).............................. $42,045 $36,814
Adjusted EBITDA to cash interest(c)............. 2.59x 4.57x
Earnings to fixed charges(b).................... 0.28x 1.97x
======= =======
</Table>
35
(a) EBITDA means earnings before interest expense, income taxes,
depreciation, depletion and amortization. Adjusted EBITDA means EBITDA
before impairment of oil and natural gas properties, reorganization
costs and gains or loses on derivative contracts. EBITDA is commonly
used by debt holders and financial statement users as a measurement to
determine the ability of an entity to meet its interest obligations.
EBITDA is not a measurement presented in accordance with generally
accepted accounting principles ("GAAP") and is not intended to be used
in lieu of GAAP presentation of results of operations and cash provided
by operating activities. Our definition of adjusted EBITDA may not be
identical to similarly entitled measures used by other companies.
(b) Earnings were insufficient to cover fixed charges by $20.8 million on a
pro forma basis for the year ended December 31, 2000.
(c) Cash interest excludes non-cash interest for amortization of bond
discount and bond issuance costs, which are included in determining
interest expense in accordance with GAAP.
36
OPERATING DATA
The following table sets forth information with respect to our consolidated
operations for the periods shown.
<Table>
<Caption>
SIX MONTHS
YEARS ENDED DECEMBER 31, ENDED JUNE 30,
--------------------------- -----------------
1998 1999 2000 2000 2001
------- ------- ------- ------- -------
Production volumes:
Oil and condensate (MBbls).............. 1,030 1,145 1,333 540 692
Natural gas (MMcf)...................... 6,711 7,007 8,314 3,413 4,615
Total (MMcfe)................... 12,890 13,874 16,313 6,653 8,767
Average daily production:
Oil and condensate (Bbls)............... 2,821 3,136 3,643 2,983 3,823
Natural gas (Mcf)....................... 18,387 19,196 22,716 18,856 25,497
Total (Mcfe).................... 35,314 38,011 44,574 36,757 48,436
Average realized prices:(1)
Oil and condensate (per Bbl)............ $ 12.43 $ 17.27 $ 28.95 $ 29.27 $ 27.12
Natural gas (per Mcf)................... 1.94 2.36 4.19 2.93 7.78
Per Mcfe........................ 2.00 2.61 4.50 3.94 6.24
Expenses (per Mcfe):
Lease operating (excluding workover
expense and production taxes)........ $ 1.35 $ 1.12 $ 1.19 $ 1.02 $ 1.20
Workover................................ 0.05 0.17 0.41 0.26 0.38
Production taxes........................ 0.05 0.05 0.12 0.11 0.15
Depreciation, depletion and
amortization......................... 0.96 0.80 0.83 0.81 0.83
General and administrative, net......... 0.26 0.38 0.27 0.37 0.36
</Table>
---------------
(1) Reflects the actual realized prices received, including the results of
hedging activities. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
RESERVE DATA
The following table sets forth data with respect to our estimated net
proved oil and natural gas reserves as of the dates shown.
<Table>
<Caption>
AT DECEMBER 31,
------------------------------
1998 1999 2000
-------- -------- --------
Proved reserves:
Oil and condensate (MBbls)............................... 11,319 15,851 15,073
Natural gas (MMcf)....................................... 111,149 110,092 89,699
Total (MMcfe).................................... 179,063 205,198 180,137
Proved developed reserves:
Oil and condensate (MBbls)............................... 9,124 12,957 12,290
Natural gas (MMcf)....................................... 58,088 58,265 45,575
Total (MMcfe).................................... 112,832 136,007 119,315
PV-10 Value (in thousands)(1).............................. $118,151 $292,495 $630,002
Standardized Measure (in thousands)(2)..................... $105,403 $231,564 $472,279
Reserve life (in years).................................... 13.9 14.8 11.0
</Table>
---------------
(1) The average prices used in calculating PV-10 Value as of December 31, 2000
were $10.31 per Mcf and $25.90 per Bbl. Assuming benchmark prices of $4.25
per Mcf and $25.00 per Bbl (or net realized prices of $4.82 per Mcf and
$24.10 per Bbl), our PV-10 Value would have been $309.3 million at December
31, 2000.
(2) Represents PV-10 Value adjusted for the effects of future estimated income
tax expense.
37
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The following discussion of our results of operations and financial
condition includes the results of operations and financial condition of our
subsidiary and us on a consolidated basis. Our consolidated financial statements
and the related notes contain additional detailed information that should be
referred to when reviewing this material.
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. This interest is the only oil and natural gas property of
Tri-Union Operating and represents 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. On 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 old notes,
each unit consisting of one old 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 this 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.
As of June 30, 2001, we had $105.6 million of debt outstanding (net of bond
discounts), as compared to adjusted EBITDA on a pro forma basis for the six
months then ended of $36.8 million and for the year ended December 31, 2000, of
$42.0 million.
At December 31, 2000, our net proved reserves were 180.1 Bcfe with a PV-10
Value of $630.0 million. At December 31, 1999, our net proved reserves were
205.2 Bcfe with a PV-10 Value of $292.5 million. While our total proved reserves
quantities at December 31, 2000 decreased by 12% versus those at December 31,
1999, our proved developed producing reserves actually increased by 3% over the
same period. The decrease in total proved reserves was primarily due to lease
expirations that resulted in the loss of proved undeveloped reserves in our
offshore Gulf Coast area. These leases expired as a consequence of our inability
to obtain approval from the bankruptcy
38
court to make the significant capital investments required to maintain these
leases. Our capital budget has been primarily focused on converting proved
developed non-producing and proved undeveloped reserves to production.
During 1998, 1999, 2000 and the first quarter of 2001, our capital
expenditures on oil and natural gas activities totaled approximately $72.0
million, $13.6 million, $10.9 million and $1.4 million, respectively. These
expenditures related to operations in our three core areas. In 1998, 87% of our
capital expenditures were related to the acquisition 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. With our working capital from the original offering and cash flow
from operations, we plan to significantly increase our capital budget for the
remainder of 2001 through 2003 to $37.7 million, to complete 116 development
drilling, exploitation and recompletion projects and two seismic surveys.
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. The financial information in this prospectus is the
consolidated financial information for Tribo, us and our subsidiary as of the
periods indicated.
We use the full cost method of accounting for oil and natural gas property
acquisition, exploration and development activities. Under this method, all
productive and nonproductive costs incurred in connection with the acquisition
of, exploration for and development of oil and natural gas reserves 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
Six Months Ended June 30, 2001 Compared to Six Months Ended June 30, 2000
For the six months ended June 30, 2001, consolidated net income was
$19,180,648, an improvement over consolidated net income of $2,806,530 for the
six months ended June 30, 2000.
Oil and Gas Revenues. Oil and natural gas revenues increased $28,479,224,
or 109%, to $54,666,487 for the six months ended June 30, 2001, from $26,187,263
for the six months ended June 30, 2000. The increase in oil and natural gas
revenues was primarily the result of an increase in production volumes and a
substantial increase in the average price we received for natural gas during the
period, which may not reflect the prices we receive in future periods. The
following table summarizes the consolidated results of oil and natural gas
production and related pricing for the six months ended June 30, 2001 and 2000:
<Table>
<Caption>
FOR THE SIX MONTHS ENDED
JUNE 30,
--------------------------
2000 2001 % CHANGE
------ ------ --------
Oil production volumes (Mbbls).......................... 540 692 28%
Gas production volumes (Mmcf)........................... 3,413 4,615 35%
Total (Mmcfe)................................. 6,653 8,767 32%
Average oil price (per Bbl)............................. $29.27 $27.12 (7)%
Average gas price (per Mcf)............................. $ 2.93 $ 7.78 166%
Average price (per Mcfe)...................... $ 3.94 $ 6.24 58%
</Table>
39
Gain or Loss on Marketable Securities. We recognized $417,180 in losses on
marketable securities for the six months ended June 30, 2001, as compared to
gains of $902,696 at June 30, 2000. 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.
Other Income. Other income increased $477,616, or 114%, to $896,922 for
the six months ended June 30, 2001 from $419,306 for the six months ended June
30, 2000. The increase was primarily the result of the sale of emission
reduction credits from our Hastings Field.
Lease Operating Expense. Lease operating expense increased $3,676,286, or
54%, to $10,480,429 for the six months ended June 30, 2001 from $6,804,142 for
the six months ended June 30, 2000. Lease operating expense was $1.20 per Mcfe
for the six months ended June 30, 2001, an increase of 17% from $1.02 per Mcfe
for the six months ended June 30, 2000. The increase in lease operating expense
is primarily the result of higher electricity and fuel costs, an increase in the
number of producing wells and MMS compliance work at our Matagorda Island A-4
and Brazos 104 facilities.
Workover Expense. Workover expense increased $1,643,231, or 97%, to
$3,340,129 for the six months ended June 30, 2001 from $1,696,898 for the six
months ended June 30, 2000. Workover expense was $0.38 per Mcfe for the six
months ended June 30, 2001, an increase of 49% from $0.26 per Mcfe for the six
months ended June 30, 2000. During the first half of 2000 and immediately
preceding our bankruptcy filing, workover spending was minimized. During the
remainder of 2000 and the first half of 2001, a workover program was completed
that included normal and recurring workovers and a backlog of workovers from
1998 and 1999. During the first half of 2001, workover repairs were completed on
several wells which will provide long-term cost savings due to a reduced
requirement for minor maintenance work in the future and fewer interruptions
from associated downtime.
Production Taxes. Production taxes increased by $629,136 or 88% to
$1,341,576 for the six months ended June 30, 2001 from $712,441 for the six
months ended June 30, 2000. Production taxes were $0.15 per Mcfe for the six
months ended June 30, 2001, an increase of 43% from $0.11 per Mcfe for the six
months ended June 30, 2000. Increases in oil and natural gas production and
revenues during the six months ended June 30, 2001 resulted in an increase in
the amount of production taxes paid during the period.
Depreciation, Depletion and Amortization Expense ("DD&A"). DD&A expense
increased by $1,867,720, or 35%, to $7,262,042 for the six months ended June 30,
2001 from $5,394,322 for the six months ended June 30, 2000. DD&A was $0.83 per
Mcfe for the six months ended June 30, 2001, an increase of 2% from $0.81 per
Mcfe for the six months ended June 30, 2000. Increased oil and natural gas
production during the six months ended June 30, 2001 resulted in an increase in
the amount of depletion computed on those volumes.
General and Administrative Expense ("G&A"). G&A increased $702,358, or
29%, to $3,149,231 for the six months ended June 30, 2001 from $2,446,873 for
the six months ended June 30, 2000. G&A was $0.36 per Mcfe for the six months
ended June 30, 2001, a decrease of 3% from $0.37 per Mcfe for the six months
ended June 30, 2000. The increase was primarily the result of an increase in
legal fees associated with non-bankruptcy legal matters for which the Company is
primarily the plaintiff incurred during the first six months of 2001.
Interest Expense. Interest expense decreased $457,000, or 7%, to
$6,276,250 for the six months ended June 30, 2001 from $6,733,250 for the six
months ended June 30, 2000. The decrease is primarily the result of the
bankruptcy filing, and our decision during 2000 to accrue interest at 12% per
annum, which was different from the stated rate of prime plus 4%.
Reorganization Costs. Tri-Union Development Corporation filed a voluntary
petition for relief under the U.S. Bankruptcy Code in the U.S. Bankruptcy Court
for the Southern District of Texas,
40
Houston Division on March 14, 2000. As a result, we incurred certain
reorganization costs totaling $7,311,108 for the six months ended June 30, 2001,
a 699% increase from $914,809 for the six months ended June 30, 2000. These
reorganization costs consist of the following:
Professional fees and other - We were required to hire certain legal
and accounting professionals to assist us and certain of our creditors with
the bankruptcy proceedings.
Retention - In an effort to maintain our employees through the
bankruptcy period, we paid a retention bonus to our employees during the
month of June 2001.
Additional bank and refinancing charges - We incurred additional fees
and costs associated with the payoff of our previous bank debt.
Satisfaction of certain related party transactions - We entered into
an agreement whereby we transferred to Atasca certain minor oil and gas
properties owned by Tribo Petroleum Corporation and assigned to Atasca the
net obligations owed to us by Richard Bowman. Additionally, we released
Tribo Production Company, Ltd., BL Production Co., Ltd., and Atasca
Properties, Ltd. from the net obligations they each owe to us. After giving
effect to these transactions, all balances owing to and from us and these
related parties is satisfied.
Interest - Interest income has been recorded as an offset to
reorganization costs as prescribed by SOP 90-7.
The following table summarizes our reorganization costs incurred:
<Table>
<Caption>
SIX MONTHS ENDED JUNE 30,
-------------------------
2000 2001
---------- ------------
Professional fees and other................................. $956,463 $3,524,152
Retention bonus............................................. -- 301,740
Additional bank and refinancing charges..................... -- 1,754,750
Interest and amounts paid to creditors...................... -- 793,198
Satisfaction of certain related party transactions.......... -- 1,882,989
Interest income............................................. (41,654) (945,721)
-------- ----------
Total reorganization costs........................ $914,809 $7,311,108
======== ==========
</Table>
Hedging Contract. Upon the issuance of the senior secured notes,
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, were hedged through May 31, 2003 at
estimated net realized prices that we expect will exceed $4.50 per Mcf and
$25.00 per Bbl, or a weighted natural gas-equivalent price of approximately
$4.30 per Mcfe. In connection with the issuance of the notes, we have agreed to
maintain, on a monthly basis, a rolling two-year hedge program until the
maturity of the notes, subject to certain conditions. The estimated fair value
of these hedge arrangements resulted in a net current asset of approximately
$1,649,000 and a net non-current asset of approximately $1,937,000, with an
offsetting amount of $3,586,000, recorded as other income.
Provision for Income Taxes. A $391,441 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, 2000.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
For the year ended December 31, 2000, consolidated net loss was $5,786,026,
a 37% decrease in the consolidated net loss of $9,150,034 for the year ended
December 31, 1999.
41
Oil and Natural Gas Revenues. Oil and natural gas revenues increased
$37,181,711, or 103%, to $73,452,054 for the year ended December 31, 2000 from
$36,270,343 for the year ended December 31, 1999. The increase in oil and
natural gas revenues was the result of an increase in production volumes as a
consequence of a successful capital expenditure and workover program and an
increase in the average price received for sales of oil and natural gas during
the period. The following table summarizes the consolidated results of oil and
natural gas production and related pricing for the years ended December 31, 2000
and 1999:
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
----------------------------
1999 2000 % CHANGE
------- ------- --------
Oil production volumes (MBbls)........................ 1,145 1,333 16%
Gas production volumes (MMcf)......................... 7,007 8,314 19
Total (MMcfe).................................... 13,874 16,313 18
Average oil price (per Bbl)........................... $ 17.27 $ 28.95 68%
Average gas price (per Mcf)........................... 2.36 4.19 78
Per Mcfe......................................... 2.61 4.50 72
</Table>
Gain on Marketable Securities. Gains on marketable securities were
$995,180 for the year ended December 31, 2000. Certain marketable securities
were bought and held principally for the purpose of selling them in the near
term and 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.
Other Income. Other income decreased $1,466,989, or 98%, to $28,404 for
the year ended December 31, 2000 from $1,495,393 for the year ended December 31,
1999. The decrease was primarily the result of a change in accounting method for
the year ended December 31, 2000, by which interest income was recorded as an
offset to reorganization costs in accordance with SOP 90-7 and the non-recurring
revision of prior year estimated accruals in 1999.
Lease Operating Expenses. Lease operating expenses increased $3,943,082,
or 25%, to $19,485,359 for the year ended December 31, 2000 from $15,542,277 for
the year ended December 31, 1999. Lease operating expense was $1.19 per Mcfe for
the year ended December 31, 2000, an increase of 6% from $1.12 per Mcfe for the
year ended December 31, 1999. The increase was primarily the result of a general
increase in oilfield related service costs, with the increase on a per unit of
production basis partially offset by increases in production. Additionally,
several non-recurring expenditures associated with returning over 50 wells to
production at our Hastings, Sour Lake and AWP fields, the installation of an
Amine unit and compressor at our Word field and regulatory compliance and
compressor installations at several offshore locations contributed to the
increase in lease operating expenses for the year ended December 31, 2000.
Workover Expense. Workover expense increased $4,238,664, or 176%, to
$6,649,074 for the year ended December 31, 2000 from $2,410,410 for the year
ended December 31, 1999. Workover expense was $0.41 per Mcfe for the year ended
December 31, 2000, an increase of 141% from $0.17 per Mcfe for the year ended
December 31, 1999. In 2000, a workover program was completed that included
normal recurring workovers, a backlog of workovers from 1998 and 1999 and
workovers associated with certain of the 50 wells that we returned to production
during the year. Expenses also included artificial lift and saltwater disposal
system installations for certain wells in our Hastings, AWP, Ord Bend and
Powderhorn fields.
Production Taxes. Production taxes increased $1,263,487, or 179%, to
$1,968,342 for the year ended December 31, 2000 from $704,855 for the year ended
December 31, 1999. Production taxes were $0.12 per Mcfe for the year ended
December 31, 2000, an increase of 140% from $0.05 per Mcfe for the year ended
December 31, 1999. Production taxes are computed by multiplying produced volumes
or revenues by a tax rate specified by the taxing authority. The taxing
authorities, upon meeting certain conditional requirements, offered drilling and
development incentives in the
42
form of tax rate reductions over a specified period of time. Certain of these
incentives expired during early 2000, resulting in an increase in tax rates for
the remainder of that year. Increases in oil and natural gas volumes and
revenues during the year ended December 31, 2000 also contributed to the
increase in the amount of production taxes paid during the period.
Depreciation, Depletion and Amortization Expense. DD&A increased
$2,466,442, or 22%, to $13,506,477 for the year ended December 31, 2000 from
$11,040,035 for the year ended December 31, 1999. DD&A was $0.83 per Mcfe for
the year ended December 31, 2000, an increase of 4% from $0.80 per Mcfe for the
year ended December 31, 1999. An increase in oil and natural gas volumes
produced during the year ended December 31, 2000 resulted in an increase in the
amount of depletion computed on those volumes. DD&A per unit of production
remained relatively steady as a result of increased production and reserves from
the successful completion of a relatively low cost development program.
General and Administrative Expense. G&A decreased $908,375, or 17%, to
$4,328,358 for the year ended December 31, 2000 from $5,236,733 for the year
ended December 31, 1999. G&A was $0.27 per Mcfe for the year ended December 31,
2000, a decrease of 29% from $0.38 per Mcfe for the year ended December 31,
1999. The decrease was primarily the result of a reversal of a provision for
doubtful accounts, which had been recorded for a receivable owed by a working
interest owner at December 31, 1999. A settlement agreement with the working
interest owner during 2000 lead to the reversal of the provision for the
account. Certain reorganization efforts and cost saving measures were
implemented which also contributed to the decrease in G&A expenses for the
period.
Interest Expense. Interest expense increased $776,403, or 6%, to
$12,757,863 for the year ended December 31, 2000 from $11,981,460 for the year
ended December 31, 1999. The increase was primarily the result of an increase in
outstanding borrowings.
Reorganization Costs. Tri-Union Development Corporation filed for
bankruptcy protection on March 14, 2000. We incurred reorganization costs of
$21,487,191 for the year ended December 31, 2000. Reorganization costs primarily
included the following:
Rejection of fixed-price physical delivery contract -- The bankruptcy
court approved a motion to reject a fixed-price physical delivery contract.
A claim was filed by the damaged party resulting in a liability of
$17,559,272. The contract was not a financial instrument that would qualify
to be treated as a hedge for financial reporting purposes, accordingly the
full amount of the claim was recorded as an expense for the year ended
December 31, 2000. The full amount of the claim was satisfied in accordance
with our amended plan of reorganization.
Professional fees and other -- We retained certain legal and
accounting professionals to assist with the bankruptcy proceedings and have
incurred or estimated legal and accounting fees associated with these
proceedings totaling $3,611,760 for the year ended December 31, 2000.
Employee retention costs -- In an effort to maintain employees through
the bankruptcy period, we sought approval from creditors and the bankruptcy
court to compensate the employees when certain conditions are met. For the
year ended December 31, 2000, estimated retention expenses of $855,000 were
recorded.
Interest -- Interest income of $538,841 was earned from March 14, 2000
through December 31, 2000. As prescribed by SOP 90-7, interest earned is
off-set against reorganization costs, as described above.
Provision for Income Taxes. A $79,000 provision for income tax was made
for the year ended December 31, 2000, primarily as a result of alternative
minimum tax considerations. No provision for federal income tax was required for
the year ended December 31, 1999.
43
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Effective March 31, 1998, we purchased certain oil and gas properties from
Apache for $63,000,000. The results of operations for the year ended December
31, 1998 include oil and natural gas revenue and related costs associated with
the properties acquired from Apache from the effective date of the acquisition.
For the year ended December 31, 1999, consolidated net loss was $9,150,034,
a 42% decrease in the consolidated net loss of $15,795,085 for the year ended
December 31, 1998.
Oil and Natural Gas Revenues. Oil and natural gas revenues increased
$10,433,447, or 40%, to $36,270,343, for the year ended December 31, 1999, from
$25,836,896 for the year ended December 31, 1998. The increase in oil and
natural gas revenues was primarily the result of the receipt of a full 12 months
of revenue from the properties acquired from Apache on March 31, 1998.
Additionally, the average prices received for oil and natural gas production
during the year ended December 31, 1999 were an average of $0.61 per Mcfe
greater than for the year ended December 31, 1998. The following table
summarizes the consolidated results of oil and natural gas production and
related pricing for the years ended December 31, 1999 and 1998:
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
----------------------------
1998 1999 % CHANGE
------- ------- --------
Oil production volumes (MBbls)....................... 1,030 1,145 11%
Natural gas production volumes (MMcf)................ 6,711 7,007 4
Total (MMcfe)................................... 12,890 13,874 8
Average oil price (per Bbl).......................... $ 12.43 $ 17.27 39%
Average natural gas price (per Mcf).................. 1.94 2.36 22
Per MMcfe....................................... 2.00 2.61 31
</Table>
Other Income. Other income increased $952,749, or 176%, to $1,495,393 for
the year ended December 31, 1999 from $542,644 for the year ended December 31,
1998. The increase is primarily the result of sales of emissions reduction
credits and a revision of estimates of prior year expenses.
Lease Operating Expenses. Lease operating expenses decreased $1,907,811,
or 11%, to $15,542,277 for the year ended December 31, 1999 from $17,450,088 for
the year ended December 31, 1998. Lease operating expense was $1.12 per Mcfe for
the year ended December 31, 1999, a decrease of 17% from $1.35 per Mcfe for the
year ended December 31, 1998. This decrease was primarily the result of efforts
to shut-in production on uneconomical wells during the low commodity price
period that began in 1998 and continued into 1999. Wells that were shut-in
during 1999 were not brought back into production during 1999.
Workover Expense. Workover expenses increased $1,810,720, or 302%, to
$2,410,410 for the year ended December 31, 1999 from $599,690 for the year ended
December 31, 1998. Workover expense was $0.17 per Mcfe for the year ended
December 31, 1999, an increase of 240% from $0.05 per Mcfe for the year ended
December 31, 1998. The increase was primarily the result of a workover program
begun in late 1998 and continued during 1999 that we implemented on properties
we purchased from Apache. Through July 1998, Apache continued to operate the
properties we purchased on March 31, 1998. As a result, we commenced the
workover program in late 1998, with 1999 being the first full year of workover
activity on these properties.
Production Taxes. Production taxes increased by $65,900, or 10%, to
$704,855 for the year ended December 31, 1999 from $638,955 for the year ended
December 31, 1998. Production taxes were $0.05 per Mcfe for the years ended
December 31, 1999 and 1998. Increases in oil and natural gas production during
the year ended December 31, 1999 resulted in an increase in the amount of
production taxes paid, offset on a unit of production basis by the increase.
Depreciation, Depletion and Amortization Expense. DD&A decreased by
$1,357,765, or 11% to $11,040,035 for the year ended December 31, 1999 from
$12,397,800 for the year ended
44
December 31, 1998. DD&A was $0.80 per Mcfe for the year ended December 31, 1999,
a decrease of 17% from $0.96 per Mcfe for the year ended December 31, 1998. The
decrease is attributable to increased reserve volumes apportioned to certain oil
and gas properties at December 31, 1999, decreasing the rate at which those
properties were depleted.
General and Administrative Expense. G&A increased by $1,909,986, or 57%,
to $5,236,733 for the year ended December 31, 1999 from $3,326,747 for the year
ended December 31, 1998. G&A was $0.38 per Mcfe for the year ended December 31,
1999, an increase of 46% from $0.26 per Mcf for the year ended December 31,
1998. The increase is the result of our acquisition of the Apache properties and
the increased overhead and operations expense associated with our assumption of
the operations and administration of those properties on August 31, 1998.
Interest Expense. Interest expense increased $4,247,529, or 55%, to
$11,981,460 for the year ended December 31, 1999 from $7,733,931 for the year
ended December 31, 1998. The increase was the result of our acquisition of the
properties from Apache, which increased our outstanding debt by $63,000,000 in
1998.
LIQUIDITY AND CAPITAL RESOURCES
In March 1998, Tri-Union Development Corporation acquired certain onshore
Texas oil and natural gas properties from Apache Corporation. Prior to the
acquisition, we had approximately $35 million in debt outstanding. We incurred
approximately another $63 million in debt in connection with the acquisition. We
utilized funds from a short-term, amortizing bank loan in connection with the
acquisition of Reunion. 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 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 short-term 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,
this forbearance agreement terminated and we made negotiated interest payments
while attempting to negotiate a restructuring of our obligations. By March 2000,
the aggregate principal balance of our bank debt had increased as a result of
capitalized interest and expenses to approximately $105 million. In February
2000, the bank declared a default on the loan, demanded payment of all principle
and interest and posted the shares of Tribo Petroleum Corporation, our parent
corporation and a guarantor of the loan, for foreclosure. As a consequence of
the bank's foreclosure action, on March 14, 2000, we filed for bankruptcy
protection. After the filing, we operated as a "debtor-in-possession,"
continuing in possession of our estate, the operation of our business and the
management of our properties. Under Chapter 11, certain claims against us in
existence prior to the filing of the petition were stayed from enforcement or
collection. These claims are reflected in full in the consolidated December 31,
2000 and June 30, 2001 balance sheets as "pre-petition liabilities subject to
compromise." We filed our amended plan of reorganization in the bankruptcy court
on May 9, 2001. Our plan was confirmed by a court order entered as of May 23,
2001, subject to the completion of the original offering of the old notes and
class A common stock. On June 18, 2001, the original 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.
At June 30, 2001, we had $130.0 million of debt. Our significant leverage
creates certain risks, as set forth under the heading "Risk Factors -- Our
significant leverage and lack of capital resources may affect our ability to
successfully operate and service our debt obligations."
During the six months ended June 30, 2001, our cash balances decreased by
$20,025,189 to $12,964,750 from $32,989,939 for the year ended December 31,
2001.
45
Net cash used by operating activities before reorganization costs was
$19,739,547 for the six months ended June 30, 2001. The increase is the result
of a decrease in accounts payable, accounts receivables and prepaid expenses for
the six months ended June 30, 2001. Additionally, we deposited $13,566,895 into
restricted cash as required by our plan of reorganization to satisfy the payment
in full of all remaining disputed pre-petition claims. These uses of cash were
partially offset by an increase in net income of $19,180,647 after
reorganization costs of $7,311,108 and income from hedging contract of
$3,586,626 for the six months ended June 30, 2001, when compared to net income
of $2,806,530 after reorganization costs of $914,809 for the six months ended
June 30, 2000.
Net cash used in investing activities was $1,977,850 for the six months
ended June 30, 2001 when compared to $2,854,514 for the six months ended June
30, 2000. The decrease is primarily the result of an increase in proceeds from
the sales of oil and natural gas properties of $1,844,029, to $2,225,529 for the
six months ended June 30, 2001 from $381,500 for the six months ended June 30,
2000. Additionally, proceeds from the sale of marketable securities decreased
$1,181,668 to $236 for the six months ended June 30, 2001 from $1,181,904 for
the six months ended June 30, 2000.
Net cash provided by financing activities was $6,566,408 for the six months
ended June 30, 2001 when compared to net cash used of $668,673 for the six
months ended June 30, 2000. The increase is the result of the completion of the
senior notes offering on June 18, 2001 resulting in our exit from bankruptcy.
The net cash proceeds from the offering provided sufficient available cash,
allowing us to pay or segregate funds for the payment of all claims.
During the years ended December 31, 2000 and 1999, we used $10,117,790 and
$11,943,495, respectively, in investment activities. We deposited $355,000
during the year ended December 31, 2000, as compared to $3,664,957 during the
year ended December 31, 1999, into restricted cash accounts for future plugging
and abandonment liabilities. Additionally, we reduced our investments in
property development by $2,694,787 to $10,877,657 for the year ended December
31, 2000 as compared to $13,572,444 for the year ended December 31, 1999.
However, when we include amounts expensed for workovers during these periods, we
increased amounts expensed for workovers and development costs to $16.7 million
and $15.7 million for the years ended December 31, 2000 and 1999, respectively,
from $10.1 million for the year ended December 31, 1998.
The following table sets forth information concerning our oil and natural
gas property acquisition, exploration and development activities and the related
costs during the year's ended December 31, 1998, 1999 and 2000 and the six
months ended June 30, 2001:
<Table>
<Caption>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED
--------------------------- JUNE 30,
1998 1999 2000 2001
------- ------- ------- ----------
(IN THOUSANDS)
Property acquisition -- proved............ $62,477 $ 250 $ 408 $ --
Development costs......................... 9,515 13,322 10,080 3,339
Exploration costs......................... -- -- 389 --
------- ------- ------- ------
Total costs incurred............ $71,922 $13,572 $10,878 $3,339
======= ======= ======= ======
</Table>
For the years ended December 31, 2000 and 1999, net cash used in financing
activities was $401,047 and $42,314, respectively. The increase was the result
of the financing of certain well control insurance policies in 1999.
46
CAPITAL REQUIREMENTS
Historically, our principal sources of capital have been cash flow from
operations, short-term reserve-based bank loans, private placement units, and
proceeds from asset sales. Our principal uses for capital have been the
acquisition and development of oil and natural gas properties.
At June 30, 2001, our cash balance was $13.0 million. Our budget for 2001
will include capital expenditures of $17.1 million, representing an increase of
57% over our total capital expenditures for 2000. We expect to use approximately
$14.6 million of this amount for development drilling and recompletions,
approximately $1.7 million to conduct two 3-D seismic surveys over certain
leases in California and $0.8 million for other geological and geophysical
expenditures. In addition, we are currently evaluating 24 behind pipe
opportunities in the Sacramento Basin that were not classified as proved at
December 31, 2000. These projects may be added to our budgeted projects during
the remainder of 2001 depending on our capital resources. We anticipate we may
expend an additional $720,000 in 2001 should we decide to fund these 24
projects. Further, depending on our capital resources we may substitute some of
these projects for currently budgeted projects as these behind pipe
opportunities are less expensive than many of our budgeted development projects.
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.
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) are hedged through June 30, 2003 at
swap prices of $4.19 per Mcf and $25.30 per Bbl, or a weighted-average natural
gas-equivalent price of approximately $4.20 per Mcfe. In connection with the
issuance of the old notes, we agreed to maintain, on a monthly basis, a rolling
two-year hedge program until the maturity of the old notes and the new notes,
subject to certain conditions.
Recently Issued Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("FAS 133"), "Accounting for Derivative
Instruments and Hedging Activities." FAS 133, as amended by FAS 137, is
effective for transactions entered into after June 15, 2000. FAS 133 requires
that all derivative instruments be recorded on the balance sheet at fair value.
Changes in the fair value of derivatives are recorded for each period in current
earnings or other comprehensive income, depending on whether a derivative is
designated as part of a hedge transaction and the type of hedge transaction. The
ineffective portion of all hedges will be recognized in earnings. The adoption
of FAS 133 on January 1, 2001 did not have a significant impact on the financial
statements; however it may have a significant impact in the future.
In December 1999, the SEC issued Staff Accounting Bulletin No. 101 ("SAB
101"), "Revenue Recognition in Financial Statements." SAB 101 outlines the basic
criteria that must be met to recognize revenue and provides guidance for
disclosure related to revenue recognition policies. In June 2000, the SEC issued
SAB 101B that delayed the implementation date of SAB 101 until the quarter ended
December 31, 2000, with retroactive application to the beginning of our fiscal
year.
47
The adoption of SAB 101 did not have a material impact on our financial position
or results of operations.
In March 2000, the Financial Accounting Standards Board issued
interpretation No. 44, "Accounting for Certain Transactions Involving Stock
Compensation -- An interpretation of APB No. 25" ("FIN 44"). FIN 44 clarified
the application of Opinion No. 25 in certain respects, including; the definition
of "employee" for purposes of applying Opinion No. 25; the criteria for
determining whether a plan qualifies as a non-compensatory plan; the accounting
consequences of various modifications to the terms of a previously fixed stock
option or award; and the accounting for an exchange of stock compensation awards
in a business combination. In general, FIN 44 became effective July 1, 2000. The
adoption of FIN 44 did not have a material impact on our financial position or
results of operation.
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.
48
BUSINESS AND PROPERTIES
THE COMPANY
We are an independent oil and natural gas company engaged in the
acquisition, development, exploration and production of oil and natural gas
properties in three core areas. Our core areas are located onshore Gulf Coast,
primarily in Texas and Louisiana, offshore Gulf Coast in the shallow waters of
the Gulf of Mexico and in the Sacramento Basin of northern California. We have
established significant operating expertise in our core areas and, since 1999,
have achieved substantial production growth with a limited capital budget.
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. This interest is the only oil and natural gas property of
Tri-Union Operating and represents less than 5% of our consolidated proved
reserves.
At December 31, 2000, we had net proved reserves of 180.1 Bcfe,
approximately one-half of which were natural gas, with a reserve life of 11.0
years. Our reserve base is diversified across our three core areas, with 64% of
our proved reserves located onshore Gulf Coast, 12% offshore Gulf Coast and 24%
in California. Each of these core areas are characterized by years of stable,
historical production and numerous producing wells. We operate approximately 92%
of our proved reserves.
We have a significant presence in the Gulf Coast Basin. As of December 31,
2000, we owned interests in 44 fields located onshore Gulf Coast and owned
interests in 33 producing blocks offshore Gulf Coast, representing over 172,000
gross acres. In the first half of 2001, these fields produced approximately 37
MMcfe per day.
We also have a significant presence in the Sacramento Basin. As of December
31, 2000, we owned interests in 16 fields representing over 65,000 gross acres
in the Sacramento Basin. In the first half of 2001, these fields produced
approximately 10 MMcfe per day.
We have a large inventory of development projects that we have only
recently begun to exploit. Because we operate in older, more mature fields with
long production histories and many producing wells, we believe these projects
represent low-risk opportunities to add to our reserves. We completed 28 of
these projects during 1999 and 2000 for $10.6 million in development capital
expenditures for drilling and recompletions, resulting in a 42% increase in our
daily production. We experienced a 75% drilling success rate over that period.
We have identified another 175 similar projects on our existing fields to pursue
through 2003. Of these projects, 116 are proved behind pipe and proved
undeveloped projects and two are 3-D seismic surveys in California. We have
allocated $14.9 million of our capital budget for the second half of 2001, $19.3
million for 2002 and $3.5 million for 2003 for these projects. The balance of 57
projects are behind pipe opportunities in the Sacramento Basin that were not
classified as proved at December 31, 2000. Of these projects, 24 and 33 may be
added to our budgeted projects during 2001 and 2002, respectively, depending on
our capital resources. We anticipate that we may expend an additional $720,000
during the remainder of 2001 and $990,000 in 2002 should we decide to fund these
projects. Further, depending on our capital resources, we may substitute some of
these projects for currently budgeted projects as these behind pipe
opportunities are less expensive than many of our budgeted development projects.
From June through December 2001, we expect to drill 23 development wells,
conduct 3 sidetrack/deepening and stimulation projects of existing wells and
acquire approximately 28 square miles of 3-D seismic data over certain of our
Sacramento Basin properties. 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) is hedged
through June 30, 2003 at swap prices of $4.19 per Mcf and $25.30 per Bbl, or a
weighted-average natural gas-equivalent price of
49
approximately $4.20 per Mcfe. In connection with the issuance of the old notes,
we agreed to maintain, on a monthly basis, a rolling two-year hedge program
until the maturity of the old notes and the new notes, subject to certain
conditions. We believe this hedging program will provide us with the financial
capacity to successfully execute our development plans and profitably grow
production from current levels.
We acquired our first significant reserves in 1996 with the Reunion
acquisition and have grown substantially since that time. Since January 1997,
our first full year following the Reunion acquisition, our reserves increased
from 46.9 Bcfe to 180.1 Bcfe, representing a compound annual growth rate of 40%
and an annual average reserves replacement rate of over 520%. Similarly, annual
production increased from 2.0 Bcfe in 1996 to 16.3 Bcfe in 2000, representing a
compound annual growth rate of 69%. EBITDA increased from $2.7 million in 1996
to $42.0 million in 2000, representing a compound annual growth rate of 99%.
Since 1996 we have achieved growth profitably, investing $118.0 million in
acquisition and drilling capital expenditures and generating 237.0 Bcfe of
additional proved reserves.
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.
OUR STRATEGY
Our objective is to increase our cash flow and proved reserves through a
balanced growth strategy focused on efforts to:
Develop our large inventory of behind pipe and undeveloped projects. We
plan to pursue 118 development and exploitation projects in our three core areas
through 2003 for approximately $37.7 million in capital expenditures, as
compared to 28 development drilling and recompletion projects completed in 1999
and 2000 for $10.6 million in capital expenditures. Our capital budget through
2003 will be focused on 69 development wells and proved behind pipe objectives
onshore Gulf Coast, 10 proved behind pipe and proved undeveloped objectives
offshore Gulf Coast and 39 proved undeveloped and behind pipe objectives and 3-D
seismic surveys in California. We expect that over 66% of these projects will be
natural gas focused.
<Table>
<Caption>
FOR THE PERIOD JUNE 1, 2001
THROUGH DECEMBER 31, 2003
---------------------------
BUDGETED BUDGETED
DEVELOPMENT COST
AREA OF OPERATION PROJECTS (IN MILLIONS)
----------------- ----------- -------------
Onshore Gulf Coast.......................................... 69 $23.0
Offshore Gulf Coast......................................... 10 3.7
California.................................................. 39 11.0
--- -----
Total............................................. 118 $37.7
=== =====
</Table>
Additionally, we are currently evaluating 57 behind pipe opportunities in
the Sacramento Basin that were not classified as proved at December 31, 2000. Of
these projects, 24 and 33 may be added to our budgeted projects during 2001 and
2002, respectively, depending on our capital resources. We anticipate that we
may expend an additional $720,000 during the remainder of 2001 and $990,000 in
2002 should we decide to fund these projects. Further, depending on our capital
resources we may substitute some of these projects for currently budgeted
projects as these behind pipe opportunities are less expensive than many of our
budgeted development projects.
Maintain our geographic focus and operating control. We will concentrate
our activities in our onshore Gulf Coast, offshore Gulf and California areas,
where 100% of our proved reserves were located at December 31, 2000. We believe
that our region-specific geological, engineering and production experience
allows us to maximize our reserve potential. Our operated properties currently
50
comprise approximately 92% of our proved reserves, allowing us to maintain
control over the planning, incurrence and timing of many capital and operating
expenditures. Our geographic focus and operating control should allow us to
promptly implement our expanded capital budget and increase our core area
development activity, which we expect will lead to additional increases in
production and cash flow.
Pursue selective acquisitions in our core areas. We plan to selectively
acquire producing oil and natural gas properties in our core areas where we have
or will assume operations. We believe there will continue to be attractive
acquisition opportunities as major and large independent oil and natural gas
companies continue to focus their resources away from smaller, lower-risk
development opportunities in favor of higher-risk exploration opportunities
internationally and in the deepwater Gulf of Mexico.
Mitigate volatility in our cash flow through a prudent hedging program. We
believe that current oil and natural gas prices are attractive, providing us
with the opportunity to realize substantial value for our production. In
connection with the issuance of the old notes, we agreed to maintain, on a
monthly basis, a rolling two-year hedge program until the maturity of the old
notes and the new notes, subject to certain conditions. We believe this hedging
program will improve the predictability of our cash flow, add certainty to our
rate of return on drilling activities and, in all but the worst price scenarios,
cover our interest expense and required amortization payments while the notes
are outstanding. Approximately 80% of our projected oil and natural gas
production from proved developed producing reserves is hedged through June 30,
2003 at swap prices of $4.19 per Mcf and $25.30 per Bbl, or a weighted-average
natural gas-equivalent price of approximately $4.20 per Mcfe.
OUR BANKRUPTCY AND RECAPITALIZATION
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35 million in debt outstanding. We incurred approximately another
$63 million in debt in connection with the acquisition. A portion of this debt
was in the form of a short-term, amortizing bank loan. In August 1998, before we
were able to refinance our bank loan, commodity prices began falling, with oil
prices ultimately reaching a 12-year low in December 1998. The resultant
negative effect on our cash flow from the deterioration of commodity prices,
coupled with the required amortization payments on our bank loan, severely
restricted the amount of capital we were able to dedicate to development
drilling. Consequently, our oil and natural gas production declined, further
negatively affecting our cash flow. In October 1998, our short-term loan matured
and we arranged a forbearance agreement providing for interest payments to be
partially capitalized and providing us additional time to refinance our
obligations. In July 1999, the forbearance agreement terminated and we made
negotiated interest payments while attempting to negotiate a restructuring of
our obligations. By March 2000, the aggregate principal balance of our bank debt
had increased as a result of capitalized interest and expenses to approximately
$105 million. In February 2000, the bank declared a default on the loan,
demanded payment of all principle and interest and posted the shares of Tribo
Petroleum Corporation, our parent corporation and a guarantor of the loan, for
foreclosure. As a consequence of the bank's foreclosure action, on March 14,
2000, we chose to seek protection under Chapter 11 of the Bankruptcy Code in
U.S. Bankruptcy Court for the Southern District of Texas, Houston Division.
Tri-Union Operating continued to operate outside of bankruptcy.
As a result of the redeployment of funds formerly utilized for amortization
payments, we have conducted a limited but highly successful development drilling
program, which has resulted in an increase of approximately 42% of our average
daily production over the last two years. This production increase, coupled with
improved commodity prices, allowed us to increase our cash position to
approximately $66.7 million immediately prior to closing of the offering of the
old notes from approximately $1.4 million on March 14, 2000. The old notes were
issued on June 18, 2001 as part of a private unit offering, with each unit
consisting of one old note in the principal amount of $1,000 and one share of
class A common stock of our former parent corporation, Tribo Petroleum
51
Corporation, with which we merged on July 27, 2001. The units were sold to
Jefferies & Company, Inc., as initial purchaser. The initial purchaser sold the
units to qualified institutional buyers in reliance on Rule 144A under the
Securities Act. The proceeds of the offering of the old notes and our available
cash balances allowed us to satisfy all creditor claims in full, including
interest, in accordance with the amended plan of reorganization that we filed on
May 9, 2001 and to exit bankruptcy on June 18, 2001.
The old notes are our only material long-term indebtedness. Our level of
indebtedness as of June 30, 2001, was $130.0 million as compared to adjusted
EBITDA on a pro forma basis for the six months then ended of $36.8 million and
for the year ended December 31, 2000, of $42.0 million. Our significant leverage
creates risks for holders of the notes, including the risk that we will be
unable to satisfy the amortization payments due on the notes on June 1, 2002,
2003 and 2004. See "Risk Factors -- Our significant leverage and lack of capital
resources may affect our ability to successfully operate and service our debt
obligations."
OUR PRINCIPAL OIL AND NATURAL GAS PROPERTIES
Our oil and natural gas properties are primarily located in three core
areas of operation: (1) onshore Gulf Coast, primarily in Texas and Louisiana;
(2) offshore Gulf Coast in the shallow waters of the Gulf of Mexico; and (3) in
the Sacramento Basin of northern California. All of our oil and natural gas
properties are subject to the lien of the indenture that secures the notes, as
well as liens imposed by operation of law, such as mechanic's liens and liens
for property taxes not yet due. None of our properties has an attached payment
or performance obligation.
Our onshore Gulf Coast properties accounted for 64% of our proved reserves
at December 31, 2000 and 64% of our production for the six months ended June 30,
2001. At December 31, 2000, our onshore Gulf Coast proved reserves were
distributed among 44 fields. These reserves are further distributed among
approximately 370 producing wells and a number of undeveloped locations. Most of
our onshore Gulf Coast producing wells have been on production for several years
and their respective production decline rates are relatively slow and well
established. Our working interests in the fields range from 0.16% to 100% with
an average working interest of 70%. We operate 36 of our 44 fields in the
onshore Gulf Coast area and nine of our 14 top value properties are located in
the area. Each of these nine top value properties are operated by us and, in
aggregate, accounted for approximately 82% of the area's production for the six
months ended June 30, 2001 and 86% of our proved reserves in the area at the end
of 2000. Our $8.5 million capital budget for the area during the remainder of
2001 includes 15 low-risk development projects targeting 13.5 Bcfe of proved
undeveloped reserves.
Our offshore Gulf Coast properties accounted for 12% of our proved reserves
at December 31, 2000 and 15% of our production for the six months ended June 30,
2001. At December 31, 2000, our offshore Gulf Coast proved reserves were
distributed among 33 fields. Our working interests in the fields range from
4.23% to 100% with an average working interest of 50%. We operate 22 of our 33
fields in the offshore Gulf Coast area and 61% of the proved reserves are
developed. Additionally, the offshore Gulf Coast properties have 8.5 Bcfe proved
undeveloped reserves which we intend to exploit through farm out and joint
venture arrangements with industry partners. These farm out and joint venture
arrangements will allow us to benefit from the reserve and cash flow potential
of the projects without incurring the associated risks of significant capital
investment. Recently, we have finalized farm out agreements covering two of our
offshore Gulf Coast properties and we expect to have wells completed pursuant to
those farm out agreements during 2001. Two of our 14 top value properties are
located offshore Gulf Coast. These two properties accounted for approximately 4%
of the production from the area for the six months ended June 30, 2001 and 39%
of our proved reserves in the area at the end of 2000.
Our California properties accounted for 24% of our proved reserves at
December 31, 2000 and 21% of our production for the six months ended June 30,
2001. At December 31, 2000, our proved reserves in the area were distributed
among 16 fields. The majority of these reserves are further
52
distributed among 137 producing wells and 22 undeveloped locations. Most of our
producing wells in California benefit from long production histories and well
established decline curves. Additionally, we have recently benefited from a net
sales price for our natural gas production in this area that has exceeded NYMEX
natural gas prices. Our working interests in California range from approximately
2.5% to 100% with an average working interest of 57%. We operate 12 of our 16
fields in the area. Three of our top value properties are located in California.
We operate all three of these properties which account for approximately 32% of
the production from the area for the six months ended June 30, 2001 and 82% of
our proved reserves in the area at the end of 2000. Recently, we identified
approximately 57 behind pipe objectives in existing wellbores that we believe
represent significant reserve potential in addition to our proved reserves. We
plan to conduct 3-D seismic surveys covering approximately 28 square miles of
our leasehold during the last half of 2001. We anticipate that the 3-D seismic
surveys will confirm specific locations for previously identified development
prospects and may additionally yield opportunities to drill exploratory wells in
our Grimes and Sutter City fields. Our $6.4 million capital budget for the area
during the remainder of 2001 includes the 3-D seismic surveys and 11 low-risk
development drilling projects targeting 13.9 Bcfe of proved undeveloped
reserves.
The following table and discussion provides proved reserves, PV-10 Values,
first half production and descriptive information for our three core areas and
the principal properties within each core area. These principal properties
accounted for approximately 80% of our estimated proved reserves at December 31,
2000. These same properties accounted for 60% of our total oil and natural gas
production in the first half of 2001, which averaged 47 MMcfe per day.
<Table>
<Caption>
NET PROVED % OF NET
RESERVES % OF NET PROVED
FIELD (MMCFE) PV-10 VALUE(1) PRODUCTION(2) RESERVES(1)
----- ---------- -------------- ------------- ------------
(IN THOUSANDS)
Onshore Gulf Coast:
Hastings Complex............... 52,873 $ 53,561 25.9% 29.4%
Constitution................... 11,684 60,348 14.2 6.5
Word........................... 7,405 36,140 1.1 4.1
AWP............................ 7,189 32,112 2.0 4.0
Clear Branch................... 5,470 28,324 1.0 3.0
Sour Lake...................... 5,192 8,829 2.4 2.9
Scott.......................... 3,063 22,095 3.1 1.7
North Alvin.................... 3,031 7,984 1.0 1.7
South Liberty.................. 2,708 6,654 2.2 1.5
Other.......................... 15,972 42,928 11.5 8.8
------- -------- ----- -----
Subtotal............... 114,587 298,975 64.4 63.6
Offshore Gulf Coast:
South Pass 27.................. 5,542 14,325 0.4 3.1
Eugene Island 277.............. 3,077 11,543 0.2 1.7
Other.......................... 13,274 75,622 14.2 7.4
------- -------- ----- -----
Subtotal............... 21,893 101,490 14.8 12.2
California:
Sutter Buttes.................. 28,493 153,391 3.1 15.8
Grimes......................... 4,155 21,457 2.9 2.3
Greeley........................ 3,344 7,939 0.6 1.9
Other.......................... 7,665 46,750 14.2 4.2
------- -------- ----- -----
Subtotal............... 43,657 229,537 20.8 24.2
------- -------- ----- -----
Total.................. 180,137 $630,002 100.0% 100.0%
======= ======== ===== =====
</Table>
---------------
(1) Based on our PV-10 Value and proved reserve estimates as of December 31,
2000.
(2) For the six months ended June 30, 2001.
53
Onshore Gulf Coast
Hastings Complex. The Hastings Complex includes three fields, encompasses
approximately 8,800 acres and is located approximately 30 miles south of Houston
in Brazoria County, Texas. In March 1998 we acquired working interests in the
three fields ranging from 68.3% to 100%. The fields produce from multiple
Miocene and Frio reservoirs at depths ranging from 2,000 feet to 7,000 feet. At
the time of our acquisition, the fields had produced in excess of 682 MMBbls and
259 Bcf since discovery in 1934 by Stanolind Oil and Gas Co. Production from the
fields was approximately 11,808 Mcfe per day and net operating cash flow was
approximately $357,000 per month.
Since assuming operations in August 1998, we have increased production and
reduced operating expenses in the field. The increased production and reduced
operating expenses, combined with higher commodity prices, have resulted in a
268% increase in the field's operating cash flow. We were able to achieve this
increase with minimal capital investment by re-engineering the field's
artificial lift system, exploiting behind pipe opportunities and eliminating
uneconomic wells. Net daily production from the Hastings Complex during the
first half of 2001 averaged 12,257 Mcfe and at December 31, 2000 we had proved
reserves of 52,873 MMcfe. During the remainder of 2001 we intend to continue our
production and cost optimization efforts and drill one proved undeveloped
location.
Constitution Field. In March 1998 we acquired our working interests in the
Constitution field, which is located in Jefferson County, Texas. Our working
interests range from 25.0% to 100.0%. The field produces from the Yegua
reservoir at depths ranging from 13,500 feet to 15,011 feet. As of the date we
assumed operations, the net daily production from the field was approximately
339 Mcfe. In the second quarter of 2000 we recompleted our Westbury Farms #1
well to the Yegua Sand and then fracture stimulated the reservoir. Initial net
production after stimulation was approximately 10,013 Mcfe per day. Our success
in the Westbury Farms #1 resulted in reserve additions from four additional
proved undeveloped locations. Net daily production from the Constitution field
during the first half of 2001 was 6,730 Mcfe and at December 31, 2000 we had
proved reserves of 11,684 MMcfe. During the remainder of 2001 we intend to drill
two proved undeveloped locations.
Word Field. The Word field is located in Lavaca County, Texas and produces
from the Lower Wilcox and Edwards Limestone reservoirs at depths from 8,100 feet
to 13,200 feet. In March 1998 we acquired working interests that range from
87.5% to 100.0%. At the time of our acquisition, the field had produced over 47
Bcfe since its discovery in 1944 and was then producing at a net daily rate of
702 Mcfe per day. Net daily production from the field during the first half of
2001 averaged 523 Mcfe per day and at December 31, 2000 we had proved reserves
of 7,405 MMcfe, including reserves from one proved behind pipe objective and
five proved undeveloped Edwards locations. During the remainder of 2001 we
intend to drill one development well targeting proved undeveloped reserves in
the Edwards Limestone. Additionally, we plan to drill one or more of the Edwards
locations horizontally in order to maximize ultimate recoveries.
AWP Field. Our interest in the AWP field is comprised of a working
interest covering 5,144 acres in McMullen County, Texas. The field produces from
the Olmos and Wilcox reservoirs at depths ranging from 5,775 feet to 8,950 feet.
In March 1998 we acquired the working interests in the field, which range from
97.2% to 100.0%. At the time of our acquisition, the field had produced over 430
Bcfe since its discovery in 1981. Net daily production from the field during the
first half of 2001 averaged approximately 963 Mcfe and we had proved reserves of
7,189 MMcfe at December 31, 2000, including reserves attributable to eight
proved undeveloped locations. During recent years, the field has experienced a
resurgence of activity by other operators due to advances in fracture
stimulation technology. Consequently, we believe that significant low-risk
drilling opportunities exist on our acreage that we intend to exploit. We plan
to utilize these fracture stimulation technologies to exploit our existing
inventory of eight proved undeveloped locations and other potential locations on
our acreage. During the remainder of 2001 we intend to drill one such
development well.
54
Clear Branch Field. We acquired our working interests in the Clear Branch
field in July 1997. We operate the two active wells in the field and our working
interests range from 84.4% to 99.0%. The field produces from the Hosston
reservoir at depths ranging from 9,700 to 9,900 feet. Net daily production from
the field during the first half of 2001 averaged approximately 451 Mcfe and we
had proved reserves of 5,470 MMcfe at December 31, 2000, including reserves
attributable to two proved undeveloped locations that we intend to drill in
2001. Additional proved reserves are attributable to one behind pipe objective
that will be completed following depletion of the current producing intervals.
We also plan to fracture stimulate one of the producing wells during 2001.
Sour Lake Field. The Sour Lake field, discovered in 1902, is the second
oldest field in Texas. It is located 15 miles west of Beaumont, Texas in Hardin
County and produces from the Miocene, Frio and Yegua reservoirs at depths
ranging from 800 feet to 7,577 feet. Our acreage was acquired from Apache in
March 1998. Apache had acquired the acreage from Texaco, which discovered the
field. We own 100% of the working interests and mineral estate in fee under 930
acres in the field. Our largest contiguous lease position in the field, 815
acres, is situated over the structural high and is the field's most prolific
area. Net daily production from the field during the first half of 2001 averaged
approximately 1,115 Mcfe and we had proved reserves of 5,192 MMcfe at December
31, 2000, including reserves attributable to five proved behind pipe objectives
and ten proved undeveloped locations. We plan to drill three of the proved
undeveloped locations and recomplete two behind pipe objectives in 2002.
Scott Field. The Scott field is located in Lafayette Parish, Louisiana and
produces from the Stutes and Bol Mex reservoirs at depths ranging from 11,500
feet to 15,200 feet. We acquired our working interests, which range from 13.2%
to 27.4% in June 1997. The field had been on production since the 1980's and
recovered 8.0 Bcfe, but had never been exploited with the benefit of modern 3-D
seismic data and production had declined to 633 Mcfe per day. In the fourth
quarter of 1999, after completing a 3-D seismic evaluation, we drilled the
Falcon #2 and completed the well in the Bol Mex V reservoir. Net daily
production from the field during the first half of 2001 averaged approximately
1,468 Mcfe and we had proved reserves of 3,063 MMcfe at December 31, 2000,
including reserves attributable to one proved behind pipe objective and one
proved undeveloped location. Additional potential exists in two step-out
drilling locations that are based upon 3-D seismic surveys. During 2001, our
capital budget provides $275,000 for deepening the Falcon #1 to recover proved
undeveloped reserves of 1.1 Bcfe.
North Alvin Field. In 1996, as part of the Reunion acquisition, we
acquired working interests ranging from 34.3% to 41.6% in the North Alvin field,
located in Brazoria County, Texas. The field produces from Frio sandstones at
depths ranging from 7,900 feet to 8,600 feet. At the time of our acquisition the
field had produced over 28.4 Bcfe. Net daily production from the field during
the first half of 2001 averaged approximately 465 Mcfe and we had proved
reserves of 3,031 MMcfe at December 31, 2000. The proved reserves in the field
include undeveloped reserves attributable to four reservoirs that we believe can
be accessed by one wellbore, scheduled to be drilled during 2001.
South Liberty Field. The South Liberty field is located 35 miles east of
Houston in Liberty County, Texas. We own a 100% working interest in the field.
We acquired our interest in South Liberty in March 1998 and at the time of the
acquisition the field had produced over 632 Bcfe since its discovery in 1925.
The field produces from Miocene, Frio, Yegua and Cook Mountain reservoirs at
depths ranging from 1,500 feet to 11,000 feet. Net daily production from the
field during the first half of 2001 averaged approximately 1,028 Mcfe and we had
proved reserves of 2,708 MMcfe at December 31, 2000.
Offshore Gulf Coast
South Pass 27 Field. In 1997, we acquired non-operating working interests
ranging from 27% to 41% in the South Pass 27 field from Statoil. The field is
located in federal waters offshore
55
Louisiana in approximately 120 feet of water. Net daily production from the
field during the first half of 2001 averaged approximately 201 Mcfe and we had
proved reserves of 5,542 MMcfe at December 31, 2000. The proved reserves in the
field include undeveloped reserves attributable to six reservoirs.
Eugene Island 277 Field. We acquired a 100% working interest in the Eugene
Island 277 field in 1997. The field is located in federal waters offshore
Louisiana in approximately 300 feet of water. Net daily production from the
field during the first half of 2001 averaged approximately 83 Mcfe and we had
proved reserves of 3,077 MMcfe at December 31, 2000.
California
Sutter Buttes Field. Our largest contiguous operation is in the Sutter
Buttes field in northern California, located approximately 40 miles north of
Sacramento in Sutter and Colusa Counties. Our working interests range from 53.2%
to 85.5%. The Sutter Buttes field is comprised of over 43,000 contiguous gross
acres of leasehold with approximately 62 producing wells, which we operate. At
December 31, 2000 we owned 38,000 net acres in the field. We have extensive
operating expertise in this area and significant experience with the Forbes and
Kione reservoirs. From November 1998 to February 2000, we drilled 10 development
wells targeting the Forbes and Kione reservoirs at depths of 3,100 feet to 7,100
feet. Nine of the wells were successful and resulted in significant increases in
our production and cash flow. Our net daily production during the first half of
2001 averaged 1,469 Mcfe and our proved reserves at December 31, 2000 were
28,493 MMcfe. Our planned capital budget for the remainder of 2001 provides $4.2
million to drill ten development wells targeting the Forbes reservoir and 11.5
Bcf of proved undeveloped reserves. Additionally, we plan to survey six square
miles in the Sutter City leases with 3-D seismic. The Sutter City leases have
produced from the Kione sand, but the Sutter City wells have not tested the
deeper Forbes interval that has been prolific on our adjacent acreage.
Grimes Field. Our Grimes field, also acquired in 1996, is located to the
southwest of Sutter Buttes and also produces from the Forbes sandstone. Our
working interests range from 6.3% to 96.0%. Net daily production during the
first half of 2001 averaged 1,365 Mcfe and we had proved reserves of 4,155 MMcfe
at December 31, 2000. There has been limited development in the field during
recent years, and during 2001 we plan to conduct a 22 square mile 3-D survey
over our acreage in the Grimes field. We believe that the 3-D survey will result
in multiple development and exploitation drilling opportunities similar to those
that we have completed in the Sutter Buttes area since late 1998.
Greeley Field. The Greeley field is located in Kern County, California and
is our only oil producing property in California. We own an 85.4% working
interest in this field. Unlike most California properties, the Greeley field
produces light, sweet crude oil from the Olcese Sand at a depth of approximately
10,500 feet. Net daily production during the first half of 2001 averaged 280
Mcfe and we had proved reserves of 3,344 MMcfe at December 31, 2000. During 2001
we plan to drill one development well targeting 1.5 Bcfe of proved undeveloped
reserves.
56
OIL AND NATURAL GAS RESERVES
The following table sets forth information with respect to our estimated
net proved oil and natural gas reserves and the related present values of such
reserves at the dates shown. The reserve and present value data for our existing
properties as of December 31, 1998, 1999 and 2000 have been prepared by
Huddleston & Co., Inc.
<Table>
<Caption>
AT DECEMBER 31,
------------------------------
1998 1999 2000
-------- -------- --------
Proved Reserves:
Oil and condensate (MBbls)....................... 11,319 15,851 15,073
Natural gas (MMcf)............................... 111,149 110,092 89,699
Total (MMcfe)............................ 179,063 205,198 180,137
Proved Developed Reserves:
Oil and condensate (MBbls)....................... 9,124 12,957 12,290
Natural gas (MMcf)............................... 58,088 58,265 45,575
Total (MMcfe)............................ 112,832 136,007 119,315
PV-10 Value (in thousands)(1)...................... $118,151 $292,495 $630,002
Standardized Measure (in thousands)(2)............. $105,403 $231,564 $472,279
Reserve life (in years)............................ 13.9 14.8 11.0
</Table>
---------------
(1) The average prices used in calculating PV-10 Value as of December 31, 2000
were $10.31 per Mcf and $25.90 per Bbl. Assuming benchmark prices of $4.25
per Mcf and $25.00 per Bbl (or net realized prices of $4.82 per Mcf and
$24.10 per Bbl), our PV-10 Value would have been $309.3 million at December
31, 2000.
(2) Represents PV-10 Value adjusted for the effects of future estimated income
tax expense.
Effective February 1, 2001, we gained an incremental 4.1 Bcfe of proved
reserves, estimated at December 31, 2000, in our Hastings Complex due to the
resolution of certain litigation which resulted in an assignment of additional
interests.
Estimated quantities of proved reserves and future net revenues therefrom
are affected by oil and natural gas prices, which have fluctuated widely in
recent years. There are numerous uncertainties inherent in estimating oil and
natural gas reserves and their values, including many factors beyond the control
of the producer. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers, including those used by us, may
vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities,
prevailing oil and natural gas prices, operating costs and factors, which
revisions may be material. Accordingly, reserve estimates are often different
from the quantities of oil and natural gas that are ultimately recovered and are
highly dependent upon the accuracy of the assumptions upon which they are based.
In general, the volume of production from oil and natural gas properties
declines as reserves are depleted. Except to the extent we acquire properties
containing proved reserves or conduct successful exploration and development
activities, or both, our proved reserves will decline as reserves are produced.
Our future oil and natural gas production is, therefore, highly dependent upon
our level of success in finding or acquiring additional reserves. Exploring for,
developing or acquiring new reserves requires substantial amounts of capital.
We file reports of our estimated oil and natural gas reserves with the
Department of Energy. The reserves reported to this agency are required to be
reported on a gross operated basis and therefore are not comparable to the
reserve data reported herein.
57
NET PRODUCTION, UNIT PRICES AND COSTS
The following table sets forth certain information with respect to oil and
natural gas production, prices and costs attributable to all of our oil and
natural gas property interests for the periods shown:
<Table>
<Caption>
SIX MONTHS ENDED
YEARS ENDED DECEMBER 31, JUNE 30,
--------------------------- -----------------
1998 1999 2000 2000 2001
------- ------- ------- ------- -------
Production Volumes:
Oil and condensate (MBbls)................ 1,030 1,145 1,333 540 692
Natural gas (MMcf)........................ 6,711 7,007 8,314 3,413 4,615
Total (MMcfe)..................... 12,890 13,874 16,313 6,653 8,767
Average Daily Production:
Oil and condensate (Bbls)................. 2,821 3,136 3,643 2,983 3,823
Natural gas (Mcf)......................... 18,387 19,196 22,716 18,856 25,497
Total (Mcfe)...................... 35,314 38,011 44,574 36,757 48,436
Average Realized Prices:(1)
Oil and condensate (per Bbl).............. $ 12.43 $ 17.27 $ 28.95 $ 29.27 $ 27.62
Natural gas (per Mcf)..................... 1.94 2.36 4.19 2.93 7.78
Per Mcfe.......................... 2.00 2.61 4.50 3.94 6.24
Expenses (per Mcfe):
Lease operating (excluding workover
expenses and production taxes)......... $ 1.35 $ 1.12 $ 1.19 $ 1.02 $ 1.20
Workover.................................. 0.05 0.17 0.41 0.26 0.38
Production taxes.......................... 0.05 0.05 0.12 0.11 0.15
Depletion, depreciation and
amortization........................... 0.96 0.80 0.83 0.81 0.83
General and administrative, net........... 0.26 0.38 0.27 0.37 0.36
</Table>
---------------
(1) Reflects the actual realized prices received, including the results of
hedging activities. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
PRODUCING WELLS
The following table sets forth the number of productive wells in which we
owned an interest as of December 31, 2000:
<Table>
<Caption>
GROSS WELLS NET WELLS
----------- ---------
Oil........................................... 449.0 287.4
Natural Gas................................... 183.0 91.4
----- -----
Total............................... 632.0 378.8
===== =====
</Table>
Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections and oil
wells awaiting connection to production facilities. Wells that are completed in
more than one producing horizon are counted as one well.
ACREAGE
The following table sets forth our developed and undeveloped gross and net
leasehold acreage as of December 31, 2000:
<Table>
<Caption>
GROSS NET
------- -------
Developed....................................... 20,122 14,729
Undeveloped..................................... 217,543 91,339
------- -------
Total................................. 237,665 106,068
======= =======
</Table>
58
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves.
DRILLING ACTIVITIES
The table below sets forth our drilling activity on our properties for the
periods ending December 31, 1998, 1999, and 2000:
<Table>
<Caption>
YEARS ENDED DECEMBER 31,
------------------------------------------
1998 1999 2000
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Development wells:
Productive............................. 2.00 1.47 4.00 2.38 5.00 3.95
Non-productive......................... -- -- 3.00 1.70 -- --
---- ---- ---- ---- ---- ----
Total.......................... 2.00 1.47 7.00 4.08 5.00 3.95
==== ==== ==== ==== ==== ====
Exploratory wells:
Productive............................. -- -- -- -- 1.00 0.15
Non-productive......................... -- -- -- -- -- --
---- ---- ---- ---- ---- ----
Total.......................... -- -- -- -- 1.00 0.15
==== ==== ==== ==== ==== ====
</Table>
OIL AND NATURAL GAS MARKETING AND HEDGING
The revenues generated by our operations are highly dependent upon the
prices of and demand for oil and natural gas. The price we receive for our oil
and natural gas production depends on numerous factors beyond our control.
Historically the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. Prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in the
supply and demand for oil and natural gas, market uncertainty and a variety of
additional factors. These factors include the level of consumer product demand,
weather conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions in the Middle East, the
actions of OPEC, the foreign supply of oil and natural gas and overall economic
conditions. It is impossible to predict future oil and natural gas price
movements with any certainty.
We, from time to time, use swap and option contracts to mitigate the
volatility of price changes on commodities we produce and sell, as well as to
lock in prices to protect the economics related to certain capital projects.
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) is hedged through June 30, 2003 at
swap prices of $4.19 per Mcf and $25.30 per Bbl, or a weighted-average natural
gas-equivalent price of approximately $4.20 per Mcfe. In connection with the
issuance of the old notes, we agreed to maintain, on a monthly basis, a rolling
two-year hedge program until the maturity of the old notes and the new notes,
subject to certain conditions.
COMPETITION AND MARKETS
Competition is intense in all areas of the our operations. Major and
independent oil and natural gas companies and oil and natural gas syndicates
actively bid for desirable oil and natural gas properties, as well as for the
equipment and labor required to operate and develop such properties. Many of our
competitors have financial resources and acquisition, exploration and
development budgets that are substantially greater than ours, which may
adversely affect our ability to compete with these companies. Many of our
competitors have been engaged in the energy business for a
59
much longer time than us. Such companies may be able to pay more for productive
oil and natural gas properties and exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties and prospects than
our financial or human resources permit. Our ability to acquire additional
properties and to discover reserves in the future will depend on our ability to
evaluate and select suitable properties and to consummate transactions in a
highly competitive environment.
The market for oil and natural gas produced by us depends on factors beyond
our control, including domestic and foreign political conditions, the overall
level of supply of and demand for oil and natural gas, the price of imports of
oil and natural gas, weather conditions, the price and availability of
alternative fuels, the proximity and capacity of natural gas pipelines and other
transportation facilities and overall economic conditions. The oil and natural
gas industry as a whole also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual consumers.
REGULATION
General. Various aspects of our oil and natural gas operations are subject
to extensive and continually changing regulation, as legislation affecting the
oil and natural gas industry is under constant review for amendment or
expansion. Numerous departments and agencies, both federal and state, are
authorized by statute to issue, and have issued, rules and regulations binding
upon the oil and natural gas industry and its individual members. The Federal
Energy Regulatory Commission ("FERC") regulates the transportation and sale of
natural gas in interstate commerce pursuant to the Natural Gas Act of 1938
("NGA") and the Natural Gas Policy Act of 1978 ("NGPA"). In the past, the
federal government has regulated the prices at which oil and natural gas could
be sold. While sales by producers of natural gas and all sales of crude oil,
condensate and natural gas liquids can currently be made at uncontrolled market
prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA
in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act"). The Decontrol Act removed all remaining NGA and NGPA price and
nonprice controls affecting wellhead sales of natural gas effective January 1,
1993.
Regulation of Sales and Transportation of Natural Gas. Our sales of
natural gas are affected by the availability, terms and cost of transportation.
The price and terms for access to pipeline transportation are subject to
extensive regulation. In recent years, the FERC has undertaken various
initiatives to increase competition within the natural gas industry. As a result
of initiatives like FERC Order No. 636, issued in April 1992, the interstate
natural gas transportation and marketing system has been substantially
restructured to remove various barriers and practices that historically limited
non-pipeline natural gas sellers, including producers, from effectively
competing with interstate pipelines for sales to local distribution companies
and large industrial and commercial customers. The most significant provisions
of Order No. 636 require that interstate pipelines provide firm and
interruptible transportation service on an open access basis that is equal for
all natural gas supplies. In many instances, the results of Order No. 636 and
related initiatives have been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in favor of
providing only storage and transportation services. While the United States
Court of Appeals upheld most of Order No. 636 last year, certain related FERC
orders, including the individual pipeline restructuring proceedings, are still
subject to judicial review and may be reversed or remanded in whole or in part.
While the outcome of these proceedings cannot be predicted with certainty, we do
not believe that we will be affected materially differently than our
competitors.
The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
rate making methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad
60
inquiry into issues facing the natural gas industry to assist the FERC in
establishing regulatory goals and priorities in the post-Order No. 636
environment. Similarly, the Texas Railroad Commission has been reviewing changes
to its regulations governing transportation and gathering services provided by
intrastate pipelines and gatherers. While the changes being considered by these
federal and state regulators would affect us only indirectly, they are intended
to further enhance competition in natural gas markets. We cannot predict what
further action the FERC or state regulators will take on these matters, however,
we do not believe that any action taken will affect us materially differently
than other natural gas producers with which we compete.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
Oil Price Controls and Transportation Rates. Our sales of crude oil,
condensate and natural gas liquids are not currently regulated and are made at
market prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market.
Environmental Matters. Extensive federal, state and local laws regulating
the discharge of materials into the environment or otherwise relating to the
protection of the environment affect our oil and natural gas operations.
Numerous governmental departments issue rules and regulations to implement and
enforce such laws, which are often difficult and costly to comply with and which
carry substantial administrative, civil and even criminal penalties for failure
to comply. These laws, rules and regulations may require the acquisition of
certain permits, restrict or prohibit the types, quantities and concentration of
substances that can be released into the environment in connection with drilling
and production, restrict or prohibit drilling activities that could impact
wetlands, endangered or threatened species or other protected natural resources
and impose substantial liabilities for pollution resulting from our operations.
Some laws, rules and regulations relating to protection of the environment may,
in certain circumstances, impose strict liability for environmental
contamination, rendering a person liable for environmental damages and cleanup
costs without regard to negligence or fault on the part of such person. Other
laws, rules and regulations may restrict the rate of oil and natural gas
production below the rate that would otherwise exist. In addition, state laws
often require various forms of remedial action to prevent pollution, such as
closure of inactive pits and plugging of abandoned wells. The regulatory burden
on the oil and natural gas industry increases our cost of doing business and
consequently affects our profitability. We believe that we are in substantial
compliance with current applicable environmental laws, rules and regulations,
that we have no material commitments for capital expenditures to comply with
existing environmental requirements and that continued compliance with existing
requirements will not have a material adverse impact on our operations. However,
environmental laws, rules and regulations have been subject to frequent changes
over the years, and the imposition of more stringent requirements could have a
material adverse effect upon our capital expenditures, earnings or competitive
position as well as those of the oil and gas industry in general.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund Law," and analogous state laws impose
liability without regard to fault or the legality of the original conduct on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the current or former owner or operator of the site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Under CERCLA, such persons may be
subject to joint and several liability for the costs of investigating and
cleaning up hazardous substances that have been released into the environment,
for damages to natural resources and for the costs of certain health studies. In
addition, companies that incur liability frequently also confront third party
claims because it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment.
61
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and other wastes associated with the
exploration, development or production of oil and natural gas from regulation as
"hazardous waste." Disposal of such non-hazardous oil and natural gas
exploration, development and production wastes usually are regulated by state
law. Other wastes handled at exploration and production sites or generated in
the course of providing well services may not fall within this exclusion.
Moreover, stricter standards for waste handling and disposal may be imposed on
the oil and natural gas industry in the future. From time to time legislation is
proposed in Congress that would revoke or alter the current exclusion of
exploration, development and production wastes from the RCRA definition of
"hazardous wastes" thereby potentially subjecting such wastes to more stringent
handling, disposal and cleanup requirements. State initiatives to further
regulate the disposal of oil and natural gas wastes and naturally occurring
radioactive materials could have a similar impact on us. If such legislation
were enacted it could have a significant impact on our operating costs, as well
as those of the oil and natural gas industry in general. The impact of future
revisions to environmental laws and regulations cannot be predicted.
We own or lease, and have in the past owned or leased, properties that have
been used for the exploration and production of oil and natural gas. Although we
have utilized operating and disposal practices that were standard in the
industry at the time, hydrocarbons or other wastes may have been disposed of or
released on or under these properties or on or under other locations where such
wastes have been taken for storage or disposal. In addition, many of these
properties have been operated by third parties whose treatment and release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously released
wastes or property contamination.
The Oil Pollution Act of 1990 ("OPA") and rules and regulations promulgated
pursuant thereto impose a variety of obligations on "responsible parties" with
respect to the prevention of oil spills and liability for damages resulting from
such spills. A "responsible party" includes the owner or operator of an onshore
facility, vessel, or pipeline or the lessee or permittee of the area in which an
offshore facility is located. Under OPA, a person owning or operating a facility
from which there is a discharge or threat of a discharge of oil into navigable
waters or adjoining shorelines is subject to strict joint and several liability
for all containment and cleanup costs and certain other damages, including
natural resource damages. OPA establishes a liability limit for onshore
facilities of $350 million and for offshore facilities, all removal costs plus
$75 million; however, a party cannot take advantage of this liability limit if
the spill is caused by gross negligence or willful misconduct, resulted from a
violation of a federal safety, construction, or operating regulation, or if a
party fails to report a spill or cooperate in the cleanup. Few defenses exist to
the liability imposed by OPA. OPA also imposes ongoing requirements on a
responsible party, including preparation of an oil spill contingency plan and
proof of financial responsibility to cover a substantial portion of
environmental cleanup and restoration costs that could be incurred by
governmental entities in connection with an oil spill. Under OPA and rules
adopted by the Minerals Management Service ("MMS"), responsible parties of
covered offshore facilities that have a worst case oil spill of more than 1,000
barrels must demonstrate financial responsibility in amounts ranging from at
least $10 million in state waters to at least $35 million in Outer Continental
Shelf ("OCS") waters, with higher amounts of up to $150 million in certain
limited circumstances where the MMS believes such a level is justified by the
risks posed by the operations or if the worst case oil spill discharge volume
possible at the facility may exceed applicable threshold volumes specified in
the MMS's rules. We believe that we are in substantial compliance with OPA,
including having appropriate spill contingency plans and certificates of
financial responsibility in place.
62
We have resolved claims by the MMS relating to civil penalties for
incidences of noncompliance with certain regulatory requirements on certain of
our offshore platforms, as discussed under the heading "Legal
Proceedings -- Minerals Management Service."
The Federal Water Pollution Control Act ("FWPCA") and analogous state laws
impose strict controls regarding the discharge of pollutants, including produced
waters and other oil and natural gas wastes, into state waters or waters of the
United States. The discharge of pollutants into regulated waters is prohibited,
except in accord with the terms of a permit issued by EPA or the state.
Sanctions for unauthorized discharges include administrative, civil and criminal
penalties, as well as injunctive relief. We believe we are in substantial
compliance with applicable FWPCA requirements and that any non-compliance would
not have a material adverse effect on us.
Our operations are also subject to the Clean Air Act ("CAA") and comparable
state and local requirements. Amendments to the CAA were adopted in 1990 and
contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. We may be required to incur certain capital expenditures in the next
several years for air pollution control equipment in connection with obtaining
and maintaining operating permits and approvals for air emissions. However, we
believe our operations will not be materially adversely affected by any such
requirements, and the requirements are not expected to be any more burdensome to
us than to other similarly situated companies involved in oil and natural gas
exploration and production activities.
We maintain insurance against "sudden and accidental" occurrences, which
may cover some, but not all, of the risks described above. The insurance we
maintain may not cover the risks described above. There can be no assurance that
such insurance will continue to be available to cover all such costs or that
such insurance will be available at premium levels that justify its purchase.
The occurrence of a significant event not fully insured or indemnified against
could have a material adverse effect on our financial condition and operations.
Regulation of Oil and Natural Gas Exploration and Production. Our
exploration and production operations are subject to various types of regulation
at the federal, state and local levels. Such regulations include requiring
permits and drilling bonds for the drilling of wells, regulating the location of
wells, the method of drilling and casing wells, and the surface use and
restoration of properties upon which wells are drilled. Many states also have
statutes or regulations addressing conservation matters, including provisions
for the utilization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and natural gas wells and
the regulation of spacing, plugging and abandonment of such wells. Some state
statutes limit the rate at which oil and natural gas can be produced from our
properties.
EMPLOYEES
As of June 30, 2001, we had approximately 54 full time salaried employees
and approximately 16 contract employees. None of our employees are subject to a
collective bargaining agreement. In addition to our employees, we may utilize
the services of independent geological, engineering, land and other consultants
from time to time.
TITLE TO PROPERTIES
We have obtained title reports on substantially all of our producing
properties and believe that we have satisfactory title to such properties in
accordance with standards generally accepted in the oil and natural gas
industry. As is customary in the oil and natural gas industry, we perform a
minimal title investigation before acquiring undeveloped properties. We also
obtain title opinions prior to the commencement of drilling operations on such
properties. Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens
which we believe do not materially interfere with the use of or materially
affect the value of such properties.
63
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.
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.
Credit Lyonnais and Credit Lyonnais Securities
In March 2000, we and Richard Bowman filed suit against Credit Lyonnais,
New York Branch and Credit Lyonnais Securities (USA), Inc. in the 16th Judicial
District Court of Harris County, Texas asserting claims for violations of the
Federal Bank Tying Act, fraud and tortious interference. Credit Lyonnais filed a
counterclaim against us seeking repayment of monies loaned by Credit Lyonnais to
us, interest and attorney's fees. At the time these claims arose, Credit
Lyonnais was our senior secured lender. Specifically, we alleged that we were
wrongfully induced into incurring additional secured indebtedness associated
with the acquisition of certain oil and natural gas properties from Apache
Corporation. This additional indebtedness was to be refinanced on a short term
basis by a debt or equity offering underwritten or privately placed by Credit
Lyonnais and/or its securities affiliate, Credit Lyonnais Securities, Inc. We
alleged that Credit Lyonnais advised us that it would not increase our credit
facility to an amount necessary to consummate the acquisition from Apache unless
we entered into an agreement with Credit Lyonnais Securities to act as our
exclusive financial advisor for such an offering. We agreed to enter into such
an arrangement based upon representations made to us regarding the ability,
experience and expertise of Credit Lyonnais Securities to assist us in such an
offering. We further alleged that no meaningful effort was made on the part of
Credit Lyonnais or Credit Lyonnais Securities to assist us in raising the funds
necessary to refinance our credit facility.
As part of the confirmation of our plan we and Richard Bowman reached a
settlement of this litigation in May 2001. The terms of the settlement included
a reduction in the amount of the secured claim of Credit Lyonnais in the
approximate amount of $3.3 million and our agreement not to dispute, other than
for arithmetic error, the remainder of Credit Lyonnais' secured claim, in the
approximate amount of $127.3 million, including principal, interest, fees and
expenses as of May 31, 2001. Richard Bowman assigned his interest in the
settlement to us.
Chieftain International
On March 31, 1999, Chieftain International (U.S.) Inc. filed suit against
us in the United States District Court for the Eastern District of Louisiana
(the "bankruptcy court") alleging that we owe joint interest expenses in the
amount of approximately $3.0 million, together with accrued interest, attorneys'
fees and costs, in connection with Chieftain's operation of two mineral leases.
No action on this suit was taken during our bankruptcy. The plaintiff has filed
a motion with the United States
64
Bankruptcy Court for the Southern District of Texas, Houston Division,
requesting that the state district court in Louisiana be allowed to liquidate
the claim. The motion is currently pending. We intend to continue to vigorously
defend this suit. Funds in the amount of approximately $5.5 million were
segregated in accordance with our plan, pending the trial or resolution of this
dispute in Louisiana.
Seitel Data, Ltd. and DDD Energy, Inc.
On December 13, 2000, Seitel Data, Ltd., and DDD Energy, Inc., filed suit
against Tribo Petroleum Corporation in the 334th Judicial District of Harris
County, Texas, alleging that Tribo owed approximately $0.8 million in damages,
together with interest and attorney's fees for goods and services delivered for
our benefit. We paid the full amount of this claim, together with interest, in
accordance with our plan.
Minerals Management Service
We have reached a settlement with the MMS that resolves a civil enforcement
action first brought against us in August 2000, with respect to certain alleged
violations of MMS rules relating to the operation of our offshore facilities
prior to the commencement of our bankruptcy proceedings. As part of the
settlement, we have agreed to pay civil penalties in the amount of $506,500,
with $25,325 paid out initially, and the remaining $481,175 paid out in
quarterly installments over a two-year period. We have also agreed to provide
the MMS with approximately $9.8 million in operators bonds. The settlement
between the MMS and us is not an admission of liability with respect to the
violations alleged by the MMS.
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 ("state
court"). 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.
This suit has been dismissed from state court. The plaintiff's proof of claim in
our bankruptcy is all that remains. This claim is currently pending in the
United States Bankruptcy Court for the Southern District of Texas, Houston
Division. 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.
OPERATING HAZARDS AND RISKS
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosions, blow outs, pipe failure, abnormally
pressured formations and environmental hazards such as oil spills, natural gas
leaks, ruptures or discharges of toxic gases. Any of these occurrences could
result in substantial losses to us due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, environmental
damage, clean-up responsibilities, regulatory investigation and penalties and
suspension of operations.
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. We cannot assure you
that new wells drilled by us will be productive or that we will recover all or
any portion of our investment. Drilling for oil and natural gas may involve
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating or other costs. The cost of drilling, completing and
operating wells is often uncertain. Our drilling operations may be curtailed,
delayed or canceled as a result of numerous factors, many of which are beyond
our control, including title problems, weather conditions, mechanical problems,
compliance with governmental requirements
65
and shortages and delays in the delivery of equipment and services. Our future
drilling activities may not be successful and, if unsuccessful, such failure may
have a material adverse effect on our future results of operations and financial
condition.
Although we currently maintain insurance coverage considered to be
customary in each industry in which we participate, we are not fully insured
against certain risks, either because insurance is not available or because of
the high premium costs. We do maintain certain forms of physical damage,
employer's liability, comprehensive commercial general liability and workers'
compensation insurance. We cannot assure you that any insurance obtained by us
will be adequate to cover any losses or liabilities, or that such insurance will
continue to be available or available on terms which are acceptable to us.
66
MANAGEMENT
Our directors and principal executive officers are:
<Table>
<Caption>
NAME AGE POSITION
---- --- --------
Richard Bowman........................ 36 Founder, President, Chief Executive
Officer and Director
Jeffrey T. Janik...................... 48 Vice President, Operations
Suzanne R. Ambrose.................... 41 Vice President, Treasurer and Chief
Accounting Officer
G. Bryan Dutt......................... 42 Director
Michel T. Halbouty.................... 92 Director
Donald W. Riegle, Jr. ................ 63 Director
Oliver G. Richard III................. 48 Director
</Table>
Richard Bowman has served as President, Chief Executive Officer and
Director since our formation in 1996. Mr. Bowman also served as Chairman of the
Board, President and Chief Executive Officer of Tribo Petroleum Corporation, our
former parent corporation, since its formation in 1992. Prior to founding Tribo,
Mr. Bowman was employed as an independent landman, serving Coastal Corporation,
Torch Energy and other independent oil and natural gas companies.
Jeffery T. Janik has served with us since June 1998 when he joined us as
Operations Manager. In June 2001, Mr. Janik became our Vice President,
Operations. Prior to joining us, Mr. Janik served as Vice President of
Operations at Baker-MO Services, Inc., an oil and gas service contractor from
April 1993 to June 1998.
Suzanne R. Ambrose has served with us since November 1998 when she joined
us as an accounting consultant. In February 2000, Ms. Ambrose became our Vice
President, Accounting. In June 2001, Ms. Ambrose became our Vice President,
Treasurer and Chief Accounting Officer. Prior to joining us, Ms. Ambrose
provided accounting advice and services, on a contract basis, to WRT Energy,
Inc., an oil and natural gas exploration and production company, from May 1996
to November 1998, and HLS Offshore, L.L.C., an oil field services company, from
January 1998 through May 1998. Ms. Ambrose served as controller of Offshore
Petroleum Divers, Inc., a wholly-owned subsidiary of Offshore Pipeline, Inc., an
oil field services company, from March 1989 through November 1995.
G. Bryan Dutt founded Ironman Energy Capital, L.P., a private investment
limited partnership, in 1999 and serves as its Managing Partner. Mr. Dutt served
as managing partner of Centennial Energy Partners, a private investment limited
partnership, from 1995 to 1999. From 1985 to 1995, he was an energy analyst at
Howard, Weil, Labouisse, Friedrichs Inc., an energy investment banking firm. He
is a past president of the New Orleans Financial Analyst Society and is a
director of Aurion Technologies, LLC, an energy technology company.
Michel T. Halbouty has been Chairman of the Board and Chief Executive
Officer of Michel T. Halbouty Energy Co., an independent oil and natural gas
producer and operator, for over 20 years. Mr. Halbouty has served as President
of the American Association of Petroleum Geologists and is a member of the
National Academy of Engineering. Mr. Halbouty chaired President Reagan's Energy
Policy Advisory Task Force and later was appointed by President Reagan as leader
of the transition team on energy.
Donald W. Riegle, Jr. served in the U.S. Senate from 1976 through 1994 and
in the U.S. House of Representatives from 1967 through 1975. He served on the
Senate Banking Committee for eighteen years and as its chairman from 1989 to
1994. In March 2001, Mr. Riegle became Chairman of Government Relations for APCO
Worldwide, a global public affairs and strategic communications firm
headquartered in Washington, D.C. In January 1995, following his retirement from
the Senate, Mr. Riegle joined Shandwick International, a public relations and
public affairs firm,
67
and component of the Interpublic Group of Companies, where he served until March
2001 as Chairman of Government Relations.
Oliver G. Richard III served as Chairman, President and Chief Executive
Officer of Columbia Energy Group from April 1995 until its acquisition in
November 2000. From November 2000 to present, Mr. Richard has been engaged in
private investment activities. Mr. Richard has served as Chairman, Chief
Executive Officer and President of New Jersey Resources and President and Chief
Executive Officer of Northern Natural Gas Pipeline, a subsidiary of Enron. Mr.
Richard was appointed to the Federal Energy Regulatory Commission by President
Ronald Reagan and served from 1982 to 1985. While at the FERC, he was
instrumental in forging initiatives to increase competition and efficiencies
among federally regulated energy providers.
In 1997, in connection with an administrative proceeding by the SEC, Mr.
Richard consented, without admitting or denying the issues identified in the
order, to the entry of a cease-and-desist order by which he agreed to settle
issues related to reports filed with the SEC concerning certain gas sale and
purchase contracts executed in 1992 when he was chairman and chief executive
officer of New Jersey Resources Corporation.
MANAGEMENT OF TRI-UNION OPERATING COMPANY
The principal executive officers of Tri-Union Operating Company are the
same as the principal executive officers of Tri-Union Development Corporation.
The sole director of Tri-Union Operating is Richard Bowman.
DIRECTOR COMPENSATION
We intend to compensate our directors for their services and provide them
with equity incentives to allow them to participate in our future growth.
Currently our intention is to pay each director $75,000 per year, offer options
to purchase, subject to certain conditions, up to 0.5% of our common equity at a
nominal exercise price and to reimburse reasonable out of pocket expenses
incurred in connection with attending board meetings.
EXECUTIVE COMPENSATION
The following table sets forth certain information for fiscal years 1998,
1999 and 2000 with respect to the compensation paid to Mr. Bowman, our Chief
Executive Officer and our other executive officers that received annual
compensation (including salary and bonuses earned) that exceeded $100,000 for
those years. Mr. Bowman has historically determined the compensation of our
executive officers.
<Table>
<Caption>
ALL OTHER
NAME AND PRINCIPAL POSITIONS YEAR SALARY BONUS COMPENSATION(1)(3)
---------------------------- ---- -------- ------- ------------------
Richard Bowman........................ 2000 $330,000 $10,000 $ 9,424
President and Chief 1999 382,500 -- 8,305
Executive Officer 1998 787,243 -- 10,463
*R. Kelly Plato(2).................... 2000 110,000 27,500 7,619
Vice President and 1999 100,000 8,000 --
Chief Financial Officer 1998 -- -- --
Jeffrey T. Janik...................... 2000 145,000 18,750 15,271
Vice President, Operations 1999 145,000 25,000 14,171
1998 75,604 -- 3,548
Suzanne Ambrose(2).................... 2000 135,000 21,250 2,501
Vice President, Treasurer and 1999 142,653 10,000 --
Chief Accounting Officer 1998 -- -- --
</Table>
---------------
*Resigned September 2001.
68
(1) Amount includes automobiles furnished by us and premium payments we made for
health, dental, disability and life insurance policies for the referenced
individuals.
(2) Amount includes employment on a contract basis until February 2000.
(3) We had no stock option plans during 1998, 1999 or 2000.
RETENTION BONUSES
To provide an incentive for our executive officers and key employees
through the pendency of our bankruptcy, we have accrued $855,000 at December 31,
2000 for retention bonuses payable following our exit from bankruptcy. Following
the closing of the original offering and our exit from bankruptcy those funds
were distributed to 67 persons, including approximately $100,000 to R. Kelly
Plato, $100,000 to Jeffrey T. Janik and $100,000 to Suzanne Ambrose.
EMPLOYMENT AGREEMENTS WITH EXECUTIVE OFFICERS
We are negotiating but have not yet finalized an employment agreement with
Richard Bowman to serve as our Chairman of the Board, President and Chief
Executive Officer. We anticipate that this agreement will provide for a term
commencing on June 18, 2001 and continuing through April 30, 2006, unless
renewed for additional periods. We anticipate that Mr. Bowman will receive a
base salary of $350,000 annually during the initial calendar year, increasing
annually by the greater of 5% or an amount approved by our Board of Directors.
Mr. Bowman will also be entitled to other benefits including, but not limited
to, paid vacation, an automobile allowance, reimbursement of out-of-pocket
business expenses and a performance bonus which is expected to be equal to the
greater of (i) an amount approved by our Board of Directors or (ii) (A) zero, if
our EBITDA is less than $40 million and (B) if our EBITDA is $40 million or
more, then the sum of (1) .5% of our EBITDA between zero and $59,999,999 and (2)
1% of our EBITDA greater than $60,000,000. The employment agreement is also
expected to contain a severance package and a payment upon a change of control,
the terms of which are currently being negotiated.
We do not currently have employment agreements with our other executive
officers. We intend to enter into employment agreements with each of them on
terms that are reflective of current market conditions and are in the process of
negotiating these terms.
PRINCIPAL STOCKHOLDERS
An aggregate of 433,333 shares of our common stock were issued and
outstanding on June 30, 2001, consisting of 368,333 shares of class A common
stock and 65,000 shares of class B common stock. Of these shares, Richard
Bowman, our President and Chief Executive Officer, owns 238,333 shares of class
A common stock (or 55% of our common stock), the purchasers of units in the
original offering own an aggregate of 130,000 shares of class A common stock (or
30% of our common stock) and Jefferies owns 65,000 shares of class B common
stock (or 15% of our common stock).
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
As a private company, we historically have had a series of informal
relationships with Richard Bowman and his affiliated companies, including
advances to Richard Bowman, our sole shareholder, for travel and other business
expenses.
Under the terms of the indenture, on a prospective basis, all transactions
with affiliates must be on terms as favorable to us as could be obtained from
unaffiliated third parties.
OFFICE LEASE WITH TRIBO PRODUCTION CO. LTD.
Effective April 1, 2001, we relocated our executive offices to 530 Lovett
Boulevard, Houston, Texas, in a building owned by our affiliate, Tribo
Production Co. Ltd., which is beneficially owned by Richard Bowman, our
President, Chief Executive Officer and director. We occupy the entire building,
which has approximately 9,355 square feet of office space. We currently occupy
this space at a
69
base rental of $26,000 per month, which was determined based upon independent
market data. The base rental is subject to adjustment for changes in the
consumer price index during the term of the lease. Pursuant to the lease, we are
responsible for certain expenses associated with the building, including
property taxes, insurance, maintenance and utilities. The lease expires on March
31, 2006. The lease contains five one-year renewal options at the then
prevailing market rental rate which may be exercised upon six months notice to
our landlord. We believe the terms of this lease are as favorable to us as could
be obtained from unaffiliated third parties.
CERTAIN TRANSACTIONS WITH ATASCA RESOURCES, INC.
We have historically provided and intend to continue to provide limited
general and administrative services, such as accounting, landman and engineering
services to Atasca Resources, Inc., an entity owned and controlled by Richard
Bowman ("Atasca"). Annually, we commission an independent peer group analysis of
companies similar to Atasca in order to determine market levels for such
services. Based upon this analysis and the actual services performed, we
allocated certain general and administrative expenses to Atasca. For the year
ended December 31, 2000, we received reimbursements totaling $60,000 from Atasca
for these services. Through June 30, 2001, we allocated $5,000 per month to
Atasca for the rendering of such services. We believe the terms of these
arrangements are as favorable to us as could be obtained from unaffiliated third
parties.
In addition, during 2000 and continuing until Tribo's properties were
assigned to Atasca and we merged with Tribo, a small number of Tribo's oil and
natural gas properties were operated by Atasca. Tribo paid Atasca for ordinary
and customary lease operating expense incurred in connection with the operation
of these properties. During the year ended December 31, 2000, we received oil
and natural gas revenues of $585,692 and incurred production and overhead
expenses of $237,807. For the period from January 1, 2001 through June 18, 2001,
we received oil and natural gas revenues of $146,902 and incurred production and
overhead expenses of $88,745.
CASH ADVANCES WITH AFFILIATED ENTITIES
Historically, we have made cash advances to, and have received cash
advances from, Atasca, Tribo Production Co., Ltd., BL Production Co., Ltd., and
Atasca Properties, Ltd., entities that are beneficially owned or controlled by
Richard Bowman. The advances were made primarily for insurance, oilfield
services and related activities and reimbursement of corporate expenses. Cash
advanced from these affiliates was $488,308 for the year ended December 31,
2000, and $161,265 for the period from January 1, 2001 through June 18, 2001,
reducing the net balance owed to us from these entities to $364,667 at December
31, 2000 and $203,402 at June 18, 2001. On June 18, 2001, all net amounts due
from Mr. Bowman and entities owned by him were forgiven as partial consideration
for the assignment by Mr. Bowman of his interest in a $3.3 million litigation
settlement with Credit Lyonnais as more fully described in the "Satisfaction of
Certain Related Party Obligations" section.
OTHER TRANSACTIONS WITH RICHARD BOWMAN
The total amount owed to us by Mr. Bowman for travel and other business
expenses was $142,165, $354,953 and $625,199 at December 31, 1998, 1999 and
2000, respectively and $581,975 at June 18, 2001. These advances were
non-interest bearing and due on demand. On June 18, 2001, all net amounts due
from Mr. Bowman and entities owned by him were forgiven as partial consideration
for the assignment by Mr. Bowman of his interest in a $3.3 million litigation
settlement with Credit Lyonnais as more fully described in the "Satisfaction of
Certain Related Party Obligations" section.
70
SATISFACTION OF CERTAIN RELATED PARTY OBLIGATIONS
As noted in "Business and Properties -- Legal Proceedings," Richard Bowman
agreed to assign his interest in a $3.3 million litigation settlement with
Credit Lyonnais to us. Mr. Bowman's interest in this settlement has not yet been
determined, however, he agreed to assign this interest to us in return for our
transfer to Atasca of certain oil and natural gas properties (totaling
approximately 1.2 Bcfe, or 0.7% of our proved reserves, as of December 31, 2000)
at their book value of approximately $1.1 million owned by Tribo Petroleum
Corporation and the net obligations owed to us by Richard Bowman. Additionally,
we released Tribo Production Company, Ltd., BL Production Co., Ltd., and Atasca
Properties, Ltd., (all wholly owned by Richard Bowman) from the net obligations
they each owed to us. In July 2001, we merged with Tribo Petroleum Corporation.
After giving effect to these transactions, all balances owing to and from us and
these related parties were satisfied. As a consequence of these transactions, we
recorded a one time non-cash reorganization expense of $1,882,990. The following
table summarizes the oil and gas properties transferred to Atasca, the net
balances owing to us by Richard Bowman, Atasca Resources, Inc., and all other
companies controlled by Richard Bowman that we forgave in this transaction.
<Table>
<Caption>
ASSETS TRANSFERRED AND RECEIVABLES FORGIVEN BY TDC
--------------------------------------------------
Oil and gas properties transferred to Atasca Resources,
Inc....................................................... $1,097,611
Richard Bowman.............................................. 581,975
Due from Tribo Production Co................................ 491,878
Due from Atasca Resources, Inc.............................. 109,796
Due from BL Production, LLC................................. 55,844
----------
TOTAL............................................. $2,337,105
==========
</Table>
<Table>
<Caption>
LIABILITIES OF TDC CANCELLED
----------------------------
Due to Tribo Production Co.................................. $ 2,388
Due to Atasca Resources, Inc................................ 396,742
Due to Atasca Properties, Inc............................... 16,885
Due to BL Production, LLC................................... 23,458
Due to Atasca Properties.................................... 14,643
----------
TOTAL LIABILITIES CANCELLED....................... 454,116
==========
NET ASSETS TRANSFERRED AND RECEIVABLES FORGIVEN... $1,882,990
==========
</Table>
DESCRIPTION OF THE SENIOR SECURED NOTES
The terms and provisions of the old notes and the new notes are identical,
except that the transfer restrictions and registration rights applicable to the
old notes will generally not apply to the new notes, and the following
description is applicable to both the old notes and the new notes.
The old notes have been, and the new notes will be, issued under an
indenture among Tri-Union, as issuer, and Firstar Bank, National Association, as
trustee. You can find some of the definitions of certain terms used in this
description under "-- Certain Definitions" below. Capitalized terms not
otherwise defined in this "Description of the Senior Secured Notes" have the
meanings given to them in the indenture.
The following description is a summary of the material provisions of the
indenture, the Guaranty Agreement and the Security Documents. This summary does
not restate those documents in their entirety. We urge you to read the
indenture, the Guaranty Agreement and the Security Documents because they, and
not this description, define your rights as a Holder. A copy of the form of
indenture, the Guaranty Agreement and the Security Documents may be obtained
from us.
71
BRIEF DESCRIPTION OF THE NOTES AND THE GUARANTEES
The Notes
The Notes:
- are senior secured obligations of Tri-Union;
- are secured by a first priority Lien, subject only to Permitted Liens and
certain payment priorities set forth in the Security Documents, on
substantially all of the oil and gas assets of Tri-Union;
- rank equally in contractual right of payment with all of Tri-Union's
current and future senior Indebtedness;
- rank senior to all of Tri-Union's current and future Subordinated
Obligations; and
- are unconditionally guaranteed by Tri-Union Operating Company and will be
unconditionally guaranteed by any future Subsidiary Guarantors.
The Guarantees
The Notes are guaranteed by Tri-Union Operating Company and any future
Subsidiary Guarantor.
The guarantees of the Notes:
- are and will be senior secured obligations of the Subsidiary Guarantors;
- are and will be secured by a first priority Lien, subject only to
Permitted Liens and certain payment priorities set forth in the Security
Documents, on substantially all of the oil and gas assets of the
Subsidiary Guarantors;
- rank equally in contractual right of payment with all of the current and
future senior Indebtedness of the Subsidiary Guarantors; and
- rank senior to all of the Subsidiary Guarantor's current and future
Subordinated Obligations.
PRINCIPAL, MATURITY AND INTEREST
Tri-Union may issue Notes from time to time with a maximum aggregate
principal amount of $150,000,000, of which $130,000,000 were issued in the
original offering that closed on June 18, 2001 (the "Old Notes"). Any Tack-On
Senior Secured Notes will be subject to the debt incurrence covenant described
in the first paragraph under the heading "-- Certain Covenants -- Limitation on
Indebtedness." Any Tack-On Senior Secured Notes that are actually issued will be
treated as issued and outstanding Notes (as the same class as the Old Notes) for
all purposes of the indenture and this "Description of the Senior Secured
Notes," unless the context indicates otherwise. The indenture also provides for
the issuance of up to $150,000,000 of Notes (the "New Notes") that may be issued
in exchange for either the Old Notes pursuant to the exchange offer described in
this prospectus under "Registration Rights" or any Tack-On Senior Secured Notes
pursuant to a similar exchange offer. Unless the content indicates otherwise,
the Old Notes, the New Notes and any Tack-On Senior Secured Notes are
collectively referred to as the "Notes" in this Description of Senior Secured
Notes.
Any Old Notes that remain outstanding after the completion of the exchange
offer, together with the New Notes and any Tack-On Senior Secured Notes issued
in the future, will be treated as a single class of securities under the
indenture.
Principal on the Notes is payable in installments beginning on June 1,
2002. The Notes will mature on June 1, 2006. The Notes bear interest at the rate
of 12.5% per annum payable
72
semiannually on June 1 and December 1 of each year, respectively, commencing on
December 1, 2001.
Interest will accrue and be payable before and after the filing of a
bankruptcy petition at the rate and on the dates set forth above. Interest on
overdue principal and on overdue installments of interest, to the extent
permitted by law, will accrue at 1% per annum in excess of the rate. Interest on
the Notes will be computed on the basis of a 360-day year of twelve 30-day
months.
The Notes are issued only in fully registered form, without coupons, in
denominations of $1,000 and any integral multiple of $1,000. No service charge
shall be made for any registration of transfer or exchange of the Notes, but
Tri-Union may require payment of a sum sufficient to cover any transfer tax or
other similar governmental charge payable in connection therewith.
AMORTIZATION PAYMENTS
Principal on the Notes is payable in installments beginning on June 1, 2002
as set forth in the table below, together with accrued and unpaid interest to
such date. All amortization payments prior to the stated maturity of the Notes
will be made on a pro rata basis.
<Table>
<Caption>
DATE AMOUNT
---- ------
June 1, 2002 The greater of:
(a) $20,000,000 or (b) 15.3% of the aggregate principal
amount of the Notes originally issued (including any Tack-On
Senior Secured Notes)
June 1, 2003 The greater of:
(a) $20,000,000 or (b) 15.3% of the aggregate principal
amount of the Notes originally issued (including any Tack-On
Senior Secured Notes) reduced by any amortization payments
made prior to the payment date
June 1, 2004 The greater of:
(a) $15,000,000 or (b) 11.5% of the aggregate principal
amount of the Notes originally issued (including any Tack-On
Senior Secured Notes) reduced by any amortization payments
made prior to the payment date
</Table>
OPTIONAL REDEMPTION
At any time prior to June 1, 2003, Tri-Union may redeem in the aggregate up
to 30% of the then outstanding aggregate principal amount of the Notes with the
Net Cash Proceeds of one or more Equity Offerings at a redemption price of
112.5% of the stated principal amount of the Notes, together with accrued and
unpaid interest to the redemption date; provided that:
(1) the redemption occurs within 60 days after the consummation of the
Equity Offering; and
(2) at least 70% of the then outstanding aggregate principal amount of
the Notes remain outstanding after each redemption.
Except pursuant to the preceding paragraph, the Notes will not be
redeemable at Tri-Union's option prior to June 1, 2004.
On or after June 1, 2004, Tri-Union may redeem all or part of the Notes
upon not less than 30 nor more than 60 days' notice, from the date and at the
redemption prices (expressed as percentages of the principal amount) set forth
below plus accrued and unpaid interest, if any, on the Notes redeemed to the
applicable redemption date:
<Table>
<Caption>
DATE PERCENTAGE
---- ----------
On or after June 1, 2004.................................. 104%
On or after June 1, 2005.................................. 100%
</Table>
73
GUARANTEES
Tri-Union's Obligations are guaranteed (all the obligations guaranteed
being herein called the "Guaranteed Obligations" and each guarantee being herein
called a "Guarantee") by the Subsidiary Guarantors, which initially will be
Tri-Union Operating Company, pursuant to the Guaranty Agreement. Substantially
all of the oil and gas assets of the Subsidiary Guarantor will be pledged to
secure its obligations under the Guarantee. The Guarantees will rank equally in
contractual right of payment with all of the current and future senior
Indebtedness of the Subsidiary Guarantors, and senior to all of their respective
current and future Subordinated Obligations.
Each Subsidiary Guarantor will irrevocably and unconditionally guarantee,
on a joint and several basis, the performance and the punctual payment when due,
of all the Obligations of Tri-Union under the indenture and the Notes. Each
Subsidiary Guarantee will be limited as necessary to prevent the Subsidiary
Guarantee from constituting a fraudulent conveyance under applicable law.
The Guarantee is a continuing guarantee and shall:
(1) remain in full force and effect until payment in full in cash of
all the Guaranteed Obligations;
(2) be binding upon the relevant Subsidiary Guarantor; and
(3) inure to the benefit of and be enforceable by the trustee, the
Holders and their successors, transferees and assigns as provided in the
indenture.
Pursuant to the indenture, any Subsidiary Guarantor may consolidate with,
merge with or into, or transfer all or substantially all its assets to any other
Person if:
(1) immediately after giving effect to the transaction, no Default or
Event of Default exists; and
(2) immediately after giving effect to the transaction on a pro forma
basis, Tri-Union would be able to Incur an additional $1.00 of Indebtedness
pursuant to paragraph (1) of the covenant described under the heading
"-- Limitation on Indebtedness";
provided that if the Person is not Tri-Union or a Subsidiary Guarantor, the
guarantor's obligations under the Guaranty Agreement must be expressly assumed
by the other Person.
Upon the sale or disposition, by merger or otherwise, of any Subsidiary
Guarantor to a Person permitted by the indenture, the Subsidiary Guarantor will
be released and relieved from all its obligations under the Guaranty Agreement.
Please read "-- Certain Covenants -- Limitation on Sales of Assets" and
"-- Merger and Consolidation." Any Subsidiary Guarantor that is designated an
Unrestricted Subsidiary in accordance with the indenture will be likewise
released and relieved from all such obligations.
SECURITY; RANKING
All of the Obligations and the Guaranteed Obligations are secured by
(1) a first priority Lien in favor of the Collateral Agent for the
benefit of the Approved Hedge Counterparties or the Hedge Liquidity
Providers, the trustee and the Holders, subject only to Permitted Liens and
certain payment priorities set forth in the Intercreditor Agreement, on
substantially all of the oil and gas assets of Tri-Union and the Subsidiary
Guarantors owned on the Closing Date; and
(2) a first priority Lien, subject only to Permitted Liens, on
substantially all of the oil and gas assets of Tri-Union and the Subsidiary
Guarantors, including any future Subsidiary Guarantor, acquired or
developed thereafter;
74
provided that, with respect to any property securing Acquired Indebtedness,
Tri-Union's and each Subsidiary Guarantor's obligation to provide Liens on the
property will be limited to the extent that granting the Lien is not prohibited
by the terms of the instruments creating the Acquired Indebtedness, including
any Refinancing; and the Lien, if not otherwise prohibited, may be junior to the
Lien securing the Acquired Indebtedness. Please read "-- Certain
Covenants -- Lien on Additional Collateral."
If an Event of Default is continuing under the indenture, the trustee shall
have the right to direct the Collateral Agent to take all actions necessary or
appropriate, in accordance with the indenture, the Security Documents and
applicable law, subject to the Intercreditor Agreement. However, only the
Collateral Agent will be the secured party and entitled to enforce the Liens
granted under the Security Documents. The Collateral Agent will also be
obligated to take instructions from the Approved Hedge Counterparties or the
Hedge Liquidity Providers following an early termination of any Approved Hedge
Agreement pursuant to which Tri-Union owes a termination payment that has not
been paid or following an event of default, however designated, under a Hedge
Liquidity Agreement. The proceeds received from the sale of any Collateral that
is the subject of a foreclosure or collection suit by the Collateral Agent will
be applied in the following priority:
(1) to pay and reimburse all fees, expenses and indemnities owed to
the Collateral Agent;
(2) to pay to:
(a) the Approved Hedge Counterparties under Approved Hedge
Agreements for which an early termination date has been designated of
the net amount due to the Approved Hedge Counterparty and all accrued
and unpaid interest and all fees, expenses, cash collateralization
amounts, indemnities and other amounts owed to the Approved Hedge
Counterparty;
(b) the Approved Hedge Counterparties of regularly scheduled
payments under Approved Hedge Agreements for which no early termination
date has been designated; or
(c) Hedge Liquidity Providers and their agents or representatives,
if any, all cash collateralization amounts, principal, interest, fees,
expenses and indemnities owed under their Hedge Liquidity Agreement;
provided that if the moneys are insufficient to pay the entire amount
then outstanding, then to make pro rata payments, without any preference
or priority, to all Approved Hedge Counterparties or Hedge Liquidity
Providers, as applicable;
(3) to pay and reimburse all fees, expenses and indemnities owed to
the trustee under the indenture;
(4) to pay accrued and unpaid interest on the Notes, and if the moneys
are insufficient to pay the entire amount then outstanding, then to make
pro rata payments, without any preference or priority, to each Holder;
(5) to pay the outstanding principal balance of the Notes, including
any premium then due; and if the moneys are insufficient to pay the entire
amount then outstanding, then to make pro rata payments, without any
preference or priority, to each Holder;
(6) to the Collateral Agent to hold as cash collateral to make
payments or deposits due under the Approved Hedge Agreements, the Hedge
Liquidity Agreement and the indenture until it determines that all such
obligations have been paid in full or pay any other amounts which may be
due and owing thereunder or under any Security Document; and
(7) to the pay the remainder to Tri-Union or as a court of competent
jurisdiction may otherwise direct.
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The Collateral Agent has the power to institute and maintain such suits and
proceedings as it may deem expedient to prevent impairment of, or to preserve or
protect its, the Approved Hedge Counterparties' or Hedge Liquidity Providers',
as applicable, and the Holders' interest in, the Collateral.
Under the terms of the Intercreditor Agreement, following a Triggering
Event, any Approved Hedge Counterparty or the Hedge Liquidity Provider, if
applicable, until such time as all amounts due to it are paid, and thereafter
the trustee may direct the circumstances and manner in which the Collateral will
be disposed of; and, in any event, the Collateral Agent may take any action
permitted under the Intercreditor Agreement or any Security Document or
otherwise permitted or required by law.
Under the terms of the Intercreditor Agreement, the Approved Hedge
Counterparties or Hedge Liquidity Providers, as applicable, will be obligated to
meet with the trustee to reach a consensus on the order and which properties to
foreclose on, provided there is no obligation to reach any consensus and the
failure to reach a consensus will not impair the right of such Person, or their
representative, to proceed to enforce the Liens provided by the Security
Documents. The Intercreditor Agreement will also provide that if, following a
Triggering Event, any amounts are received by any of the Holders or any Approved
Hedge Counterparty or Hedge Liquidity Providers, the trustee or the Collateral
Agent, the amounts shall be distributed in a priority which will result in the
Approved Hedge Counterparty or Hedge Liquidity Providers receiving payment in
full for all amounts due to them under the Approved Hedge Agreements prior to
any distribution being made to repay principal, interest or premium on the
Notes.
There can be no assurance that the Collateral Agent will be able to sell
the Collateral without substantial delays or that the proceeds obtained will be
sufficient to pay all amounts owing to the Approved Hedge Counterparties or
Hedge Liquidity Providers, as applicable, and Holders and owners of Permitted
Liens, if any.
The Collateral release provisions of the indenture and the Security
Documents will permit the release of Collateral without substitution of
collateral of equal value under certain circumstances. Please read
"-- Possession, Use and Release of Collateral."
As senior obligations of Tri-Union and the relevant Subsidiary Guarantors,
the Obligations and the Guaranteed Obligations will be senior to all of
Tri-Union's and the relevant Subsidiary Guarantor's Subordinated Obligations and
pari passu in contractual right of payment to all of Tri-Union's and the
relevant Subsidiary Guarantor's other current and future senior Indebtedness.
The Notes and the Guarantee will effectively, however, be senior as to other
senior Indebtedness not granted a payment priority under the Security Documents
on the basis of the Liens granted under the indenture and the Security Documents
to the extent of the value of the Collateral.
CERTAIN COVENANTS
The indenture contains covenants including, among others, the following:
Limitation on Indebtedness
(1) Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
Incur, directly or indirectly, any Indebtedness; provided that Tri-Union or a
Restricted Subsidiary may Incur Indebtedness if, on the date of the Incurrence
and after giving effect thereto, both:
(a) the Consolidated Coverage Ratio equals or exceeds 2.5 to 1.0; and
(b) Adjusted Consolidated Net Tangible Assets equals or exceeds 150%
of the aggregate consolidated Indebtedness of Tri-Union and the Restricted
Subsidiaries.
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(2) Notwithstanding the preceding paragraph (1), Tri-Union and any
Restricted Subsidiary may Incur the following Indebtedness:
(a) Indebtedness Incurred pursuant to any Working Capital Revolver, so
long as the aggregate principal amount of all Indebtedness outstanding
under all Working Capital Revolvers does not at any one time exceed
$20,000,000;
(b) Indebtedness owed to and held by Tri-Union or a Wholly Owned
Subsidiary; provided that any subsequent issuance or transfer of any
Capital Stock which results in any such Wholly Owned Subsidiary ceasing to
be a Wholly Owned Subsidiary or any subsequent transfer of such
Indebtedness, other than to Tri-Union or another Wholly Owned Subsidiary,
shall be deemed, to constitute the Incurrence of such Indebtedness by the
issuer thereof;
(c) the Notes (other than the Tack-On Senior Secured Notes), the
indenture, the Security Documents and the Subsidiary Guarantees;
(d) Indebtedness outstanding on the Closing Date, to the extent not
discharged in Tri-Union's bankruptcy case;
(e) Refinancing Indebtedness in respect of Indebtedness Incurred
pursuant to paragraph (1) or pursuant to clause (c) or (d) above or clause
(f) below;
(f) Indebtedness of Tri-Union or a Restricted Subsidiary represented
by Capital Lease Obligations, mortgage financings or purchase money
obligations Incurred for the purpose of financing all or any part of the
purchase price or cost of construction or improvement of property used in
the oil and gas business and Incurred no later than 365 days after the date
of such acquisition or the date of completion of such construction or
improvement; provided that the principal amount of all such Indebtedness at
any one time outstanding shall not exceed $5,000,000;
(g) Indebtedness consisting of Interest Rate Agreements directly
related to Indebtedness permitted to be Incurred by Tri-Union and the
Restricted Subsidiaries pursuant to this covenant;
(h) Indebtedness under oil and gas hedging contracts entered into in
the ordinary course of business for the purpose of limiting risks that
arise in the ordinary course of business of Tri-Union and the Restricted
Subsidiaries or required to be entered into by Tri-Union and the Restricted
Subsidiaries as described under the heading "-- Hedging Obligations," and
under certain revolving credit or loan agreements or letters of credit
reimbursement agreements ("Hedge Liquidity Agreements") to permit Tri-Union
or any of the Restricted Subsidiaries to provide letters of credit in lieu
of the collateral to secure excess market exposure and settlement and
related amounts due on early termination under the Approved Hedge Agreement
and Security Documents;
(i) Non-Recourse Indebtedness;
(j) the guarantee by Tri-Union or any of the Restricted Subsidiaries
of Indebtedness that was permitted to be incurred by another provision of
this covenant; and
(k) Indebtedness in an aggregate principal amount which, together with
the principal amount of all other Indebtedness of Tri-Union and the
Restricted Subsidiaries outstanding on the date of the Incurrence (other
than Indebtedness permitted by clauses (a) through (j) above or paragraph
(1)) does not exceed $5,000,000.
(3) Notwithstanding the preceding, Tri-Union and the Restricted
Subsidiaries shall not Incur any Indebtedness pursuant to the preceding
paragraph (2) if the proceeds are used, directly or indirectly, to Refinance any
Subordinated Obligations unless the Indebtedness shall be subordinated to the
Notes to at least the same extent as the Subordinated Obligations.
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(4) For purposes of determining compliance with the preceding covenant:
(a) if an item of Indebtedness meets the criteria of more than one of
the types of Indebtedness described above, Tri-Union, in its sole
discretion, will classify the item of Indebtedness and only be required to
include the amount and type of the Indebtedness in one of the above
clauses; and
(b) an item of Indebtedness may be divided and classified in more than
one of the types of Indebtedness described above.
Limitation on Restricted Payments
(1) Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
directly or indirectly, make a Restricted Payment unless, at the time of the
Restricted Payment:
(a) no Default or Event of Default shall have occurred and be
continuing or would occur as a consequence;
(b) immediately after giving effect to the Restricted Payment on a pro
forma basis, Tri-Union could incur at least $1.00 of additional
Indebtedness under clause (1) of the covenant described under the heading
"-- Limitation on Indebtedness"; and
(c) the Restricted Payment, together with the aggregate amount of all
other Restricted Payments made by Tri-Union and its Restricted Subsidiaries
after the Closing Date, is less than the sum of:
(i) 25% of the Consolidated Net Income of Tri-Union for the period
(taken as one accounting period) from January 1, 2002 to the end of
Tri-Union's most recently ended fiscal quarter for which internal
financial statements are available at the time of the Restricted Payment
(or, if the Consolidated Net Income for the period is a deficit, less
100% of the deficit), plus
(ii) 100% of the aggregate net cash proceeds received by Tri-Union
since the Closing Date from the issue or sale of Capital Stock of
Tri-Union (other than Disqualified Stock) or of Disqualified Stock or
debt securities of Tri-Union that have been converted into, or exchanged
for, the Capital Stock (other than any Capital Stock, Disqualified Stock
or convertible debt securities sold to a Restricted Subsidiary of
Tri-Union and other than Disqualified Stock or convertible debt
securities that have been converted into, or exchanged for, Disqualified
Stock), plus
(iii) to the extent that any Permitted Investment that was made
after the Closing Date is sold for cash or otherwise liquidated or
repaid for cash, the lesser of (A) the cash return of capital with
respect to the Permitted Investment (less the cost of disposition, if
any) (B) and the initial amount of the Permitted Investment, plus
(iv) in the event that any Unrestricted Subsidiary is redesignated
as a Restricted Subsidiary, the lesser of (A) an amount equal to the
fair market value of the Investments in the Subsidiary previously made
by Tri-Union and its Restricted Subsidiaries as of the date of the
redesignation and (B) the amount of the Investments, plus
(v) $1,000,000.
(2) The provisions of the preceding paragraph (1) shall not prohibit:
(a) the payment of any dividend within 60 days after the date of
declaration of the dividend if the dividend would have been permitted on
the date of declaration;
(b) if no Default or Event of Default shall have occurred and be
continuing, the acquisition of any shares of Capital Stock (other than
Disqualified Stock) of Tri-Union or any Restricted
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Subsidiary, either (i) solely in exchange for shares of Capital Stock of
Tri-Union (other than Disqualified Stock) or (ii) through the application
of net cash proceeds of a substantially concurrent sale for cash (other
than to a Restricted Subsidiary) of shares of Capital Stock (other than
Disqualified Stock) of Tri-Union;
(c) if no Default or Event of Default shall have occurred and be
continuing, the acquisition or retirement for value of any Subordinated
Obligations (other than Disqualified Stock) of Tri-Union or a Subsidiary
Guarantor either:
(i) solely in exchange for shares of Capital Stock (other than
Disqualified Stock) of Tri-Union;
(ii) through the application of net cash proceeds of a
substantially concurrent sale for cash (other than to a Restricted
Subsidiary) of shares of Capital Stock (other than Disqualified Stock)
of Tri-Union; or
(iii) through Refinancing Indebtedness that also constitutes
Subordinated Obligations; or
(d) net advances to Richard Bowman and his Affiliates, excluding
Tri-Union and the Restricted Subsidiaries, provided that any net advances
in excess of $150,000 shall not be outstanding for more than 30 consecutive
days.
Limitation on Dividend and Other Payment Restrictions Affecting Restricted
Subsidiaries
Tri-Union will not, and will not cause or permit any of the Restricted
Subsidiaries to, directly or indirectly, create or otherwise cause or permit to
exist or become effective any encumbrance or restriction on the ability of any
Restricted Subsidiary to:
(1) pay dividends or make any other distributions on or in respect of
its Capital Stock;
(2) make loans or advances, or pay any Indebtedness or other
obligation owed, to Tri-Union or any Restricted Subsidiary;
(3) guarantee the Notes, the Approved Hedge Agreements or any Hedge
Liquidity Agreement;
(4) transfer any of its property or assets to Tri-Union or any other
Restricted Subsidiary; or
(5) grant Liens on its property or assets to secure the Obligations,
the Approved Hedge Agreements or any Hedge Liquidity Agreement (each such
encumbrance or restriction, a "Payment Restriction").
The preceding will not apply to encumbrances or restrictions existing under
or by reason of the following:
(1) applicable law;
(2) the indenture or any Security Document;
(3) customary non-assignment provisions of any contract or any lease
governing a leasehold interest of Tri-Union or any Restricted Subsidiary;
(4) any instrument governing Acquired Indebtedness, provided that the
restriction is limited only to the properties or assets the subject of such
Capital Lease, mortgage or purchase money financing;
(5) agreements existing on the Closing Date to the extent and in the
manner such agreements were in effect on the Closing Date;
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(6) customary restrictions with respect to a Restricted Subsidiary
pursuant to an agreement that has been entered into for the sale or
disposition of Capital Stock or assets of the Restricted Subsidiary to be
consummated in accordance with the terms of the indenture solely in respect
of the assets or Capital Stock to be sold or disposed of;
(7) any instrument governing a Permitted Lien, only to the extent the
instrument restricts the transfer or other disposition of assets subject to
the Permitted Lien;
(8) an agreement governing Refinancing Indebtedness incurred to
Refinance the Indebtedness issued, assumed or incurred pursuant to an
agreement referred to in clause (2), (4) or (5) above; provided that the
provisions relating to such encumbrance or restriction contained in any
such Refinancing Indebtedness are no less favorable to the Holders in any
material respect as determined by the Board of Directors of Tri-Union in
its reasonable and good faith judgment than the provisions relating to such
encumbrance or restriction contained in the applicable agreement referred
to in clause (2), (4) or (5); and
(9) any instrument governing a Working Capital Revolver, only to the
extent the instrument restricts the transfer or other disposition of
accounts receivable, related general intangibles and related proceeds of
Tri-Union and the Restricted Subsidiaries securing the Working Capital
Revolver.
Limitation on Sales of Assets
(1) Tri-Union will not, and will not cause or permit any of the Restricted
Subsidiaries to, consummate an Asset Disposition unless:
(a) Tri-Union or the relevant Restricted Subsidiary, as the case may
be, receives consideration at least equal to the fair market value of the
assets sold or otherwise disposed of, as determined in good faith by the
Board of Directors of Tri-Union; and
(b) at least 70% of the consideration received by Tri-Union or the
Restricted Subsidiary shall be in the form of cash or Temporary Cash
Investments and is received at the time of the disposition.
Within 270 days after an Asset Disposition, Tri-Union or the Restricted
Subsidiary shall apply or cause to be applied the Net Available Cash of the
Asset Disposition as follows:
Tri-Union shall make an offer to purchase (the "Excess Proceeds Offer")
from the Holders, on a pro rata basis, an aggregate stated principal amount of
Notes equal to the Excess Proceeds (rounded down to the nearest multiple of
$1,000) at a purchase price equal to the Accreted Value of the Notes, together
with accrued interest (if any) to the date of purchase (the "Excess Proceeds
Payment"); provided that Tri-Union will not be required to apply the Net
Available Cash from any Asset Disposition pursuant to this clause if, and only
to the extent that the Net Available Cash is applied to, within 270 days of the
Asset Disposition:
(a) an Investment or Investments in Additional Assets;
(b) an Investment or Investments in properties or assets that replace
the properties or assets that were the subject of the Asset Disposition
(the "Replacement Assets"), and the assets constituting the Additional
Assets or Replacement Assets and any non-cash consideration received are
made subject to the Lien of the indenture and the Security Documents in
accordance with the covenant described under the heading "-- Lien on
Additional Collateral"; or
(c) to the extent the Net Available Cash is received from an Asset
Disposition not involving the sale, transfer or disposition of Collateral,
to repay any Indebtedness secured by the assets involved in the Asset
Disposition together with a concomitant permanent reduction in the amount
of the Indebtedness so repaid;
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provided that the use of Net Available Cash shall not exceed $7,000,000 in any
one year. For purposes of this paragraph, "Excess Proceeds" means any Net
Available Cash from Asset Dispositions remaining after investments in any
Additional Assets or Replacement Assets as provided for in the preceding
sentence.
Tri-Union may defer the Excess Proceeds Offer until there are aggregate
unutilized Excess Proceeds equal to or in excess of $5,000,000 resulting from
one or more Asset Dispositions, at which time the entire unutilized Excess
Proceeds, and not just the amounts in excess of $5,000,000, shall be applied as
required pursuant to the preceding paragraph.
Notwithstanding the foregoing, in the event that Tri-Union or any of the
Restricted Subsidiaries consummates or causes to be consummated a single or a
series of related Asset Dispositions representing more than 20% of the
consolidated proved reserves of Tri-Union and the Restricted Subsidiaries (a
"Major Asset Sale"), Tri-Union shall make an offer to purchase (the "Major Asset
Sale Offer") from the Holders on a pro rata basis an aggregate stated principal
amount of Notes equal to 50% of the gross proceeds from the Major Asset Sale at
a purchase price equal to 100% of the stated principal amount of the Notes,
together with accrued interest to the date of purchase. Any Net Available Cash
remaining following the completion of the Major Asset Sale Offer shall be
applied to, within 270 days of the date of completion of the Major Asset Sale
Offer, an Investment or Investments in Additional Assets or Replacement Assets.
Notice of an Excess Proceeds Offer or Major Asset Sale Offer shall comply
with the procedures set forth in the indenture. Upon receiving notice of the
Excess Proceeds Offer or Major Asset Sale Offer, Holders may elect to tender
their Notes in whole or in part in integral multiples of $1,000 principal amount
in exchange for cash. To the extent Holders properly tender Notes in an amount
exceeding the Net Available Cash, Notes of tendering Holders will be repurchased
on a pro rata basis (based on amounts tendered).
(2) In the event of the transfer of substantially all, but not all, the
property and assets of Tri-Union as an entirety to a Person in a transaction not
constituting a Change of Control, the Successor Company shall be deemed to have
sold the properties and assets of Tri-Union not so transferred, and shall comply
with the provisions of this covenant with respect to the deemed sale as if it
were an Asset Disposition and the Successor Company shall be deemed to have
received Net Available Cash in an amount equal to the fair market value, as
determined in good faith by the Board of Directors of Tri-Union, of the
properties and assets not so transferred or sold.
(3) All Net Available Cash shall constitute Trust Moneys and shall be
delivered by Tri-Union to the Collateral Agent and shall be deposited in the
Collateral Account in accordance with the Intercreditor Agreement. Net Available
Cash so deposited may be withdrawn from the Collateral Account for application
by Tri-Union in accordance with this covenant or otherwise pursuant to the
indenture as described under the heading "-- Possession, Use and Release of
Collateral -- Deposit, Use and Release of Trust Moneys."
Limitation on Affiliate Transactions
(1) Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
enter into or permit to exist any transaction with any Affiliate of Tri-Union
(an "Affiliate Transaction") unless the terms of the transaction:
(a) are no less favorable to Tri-Union or the Restricted Subsidiary
than those that could be obtained at the time of the transaction in
arm's-length dealings with a Person who is not an Affiliate;
(b) if the Affiliate Transaction involves an amount between $500,000
and $3,000,000, are certified in an officers' certificate to the effect
that the Affiliate Transaction complies with this covenant, and have been
approved by a majority of the members of the Board of Directors of
Tri-Union having no personal stake in the Affiliate Transaction; or
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(c) if the Affiliate Transaction involves an amount in excess of
$3,000,000, are certified in an officers' certificate to the effect that
the Affiliate Transaction complies with this covenant, has been approved by
a majority of the members of the Board of Directors of Tri-Union having no
personal stake in the Affiliate Transaction and has been determined by a
nationally recognized investment banking firm to be fair, from a financial
standpoint, to Tri-Union or the Restricted Subsidiary, as the case may be.
In addition, the net balance of advances made by Tri-Union and the
Restricted Subsidiaries to Richard Bowman and his Affiliates shall not
exceed $150,000 for more than 30 consecutive days.
(2) The provisions of the preceding paragraph (1) shall not prohibit:
(a) reasonable fees and compensation paid to and indemnity provided on
behalf of, officers, directors, employees or consultants of Tri-Union or
any Restricted Subsidiary as determined in good faith by the Board of
Directors of Tri-Union;
(b) transactions exclusively between or among the Restricted
Subsidiaries; provided that the transactions are not otherwise prohibited
by the indenture; and
(c) Restricted Payments permitted by the indenture.
Change of Control
Upon the occurrence of a Change of Control, each Holder shall have the
right to require that Tri-Union repurchase its Notes at a purchase price in cash
equal to 101% of the stated principal amount of the Notes, together with accrued
and unpaid interest, if any, to the date of purchase (subject to the right of
Holders on the relevant record date to receive interest on the relevant interest
payment date), in accordance with the terms contemplated below.
Within 30 days following any Change of Control, Tri-Union shall mail a
notice to each Holder with a copy to the trustee stating:
(1) that a Change of Control has occurred and that the Holder has the
right to require Tri-Union to purchase its Notes at a purchase price in
cash equal to 101% of the stated principal amount of the Notes, together
with accrued and unpaid interest, if any, to the date of purchase (subject
to the right of Holders on the relevant record date to receive interest on
the relevant interest payment date);
(2) the circumstances and relevant facts regarding the Change of
Control, including information with respect to pro forma historical income,
cash flow and capitalization after giving effect to the Change of Control;
(3) the repurchase date, which shall be no earlier than 30 days nor
later than 60 days from the date the notice is mailed; and
(4) the instructions determined by Tri-Union, consistent with this
covenant, that a Holder must follow in order to have its Notes purchased.
Tri-Union shall comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Notes pursuant to this covenant. To the
extent that the provisions of any securities laws or regulations conflict with
the provisions of this covenant, Tri-Union shall comply with the applicable
securities laws and regulations and shall not be deemed to have breached its
obligations under this covenant by virtue thereof.
The Change of Control purchase feature is a result of negotiations between
Tri-Union and Jefferies. Management has no present intention to engage in a
transaction involving a Change of Control, although it is possible that
Tri-Union would decide to do so in the future. Subject to the limitations
discussed below, Tri-Union could, in the future, enter into certain
transactions, including acquisitions, refinancings or other recapitalizations,
that would not constitute a Change of Control
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under the indenture, but that could increase the amount of Indebtedness
outstanding at the time or otherwise affect Tri-Union's capital structure or
credit ratings. Restrictions on the ability of Tri-Union to incur additional
Indebtedness are contained in the covenants described under the heading
"-- Limitation on Indebtedness," "-- Limitation on Liens" and "-- Limitation on
Synthetic Leases." Except for the limitations contained in such covenants, the
indenture will not contain any covenants or provisions that may afford Holders
protection in the event of a highly leveraged transaction.
The provisions under the indenture relating to Tri-Union's obligation to
make an offer to repurchase the Notes as a result of a Change of Control or
Asset Disposition may be waived or modified with the written consent of the
Holders of a majority in principal amount of the Notes.
Tri-Union will not be required to make an offer to purchase the Notes as a
result of a Change of Control if a third party:
(1) makes the offer in the manner, at the times and otherwise in compliance
with the requirements set forth in the indenture applicable to
Tri-Union and
(2) purchases all Notes validly tendered and not withdrawn under the an
offer.
Limitation on the Sale or Issuance of Capital Stock of Restricted Subsidiaries
Tri-Union shall not sell or otherwise dispose of any shares of Capital
Stock of a Restricted Subsidiary, and shall not permit any Restricted
Subsidiary, directly or indirectly, to issue or sell or otherwise dispose of any
shares of its Capital Stock except:
(1) to Tri-Union or a Wholly Owned Subsidiary;
(2) if all shares of Capital Stock of the Restricted Subsidiary (other
than Tri-Union) are sold or otherwise disposed of; or
(3) to the extent the shares represent directors' qualifying shares or
shares required by applicable law to be held by a Person other than
Tri-Union or a Restricted Subsidiary;
provided that in the case of clause (2), Tri-Union complies with the provisions
of the covenant described under the heading "-- Limitation on Sales of Assets"
and provided further, Tri-Union shall not sell or otherwise dispose of any
Capital Stock of Tri-Union. If Tri-Union or a Restricted Subsidiary shall
dispose of all of the Capital Stock of any Subsidiary Guarantor, the Subsidiary
Guarantor shall be released from the obligations under its Subsidiary Guarantee.
Limitation on Liens
Tri-Union will not, and will not cause or permit any of the Restricted
Subsidiaries to, directly or indirectly, create, incur, assume or permit or
suffer to exist or remain in effect any Liens other than Permitted Liens.
Limitation on Synthetic Leases
Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
enter into any Synthetic Lease Transaction with respect to any property unless:
(1) Tri-Union or the Restricted Subsidiary would be entitled to Incur
Indebtedness in an amount equal to the Attributable Debt with respect to
the Synthetic Lease pursuant to the covenant described under the heading
"-- Limitation on Indebtedness;"
(2) the net cash proceeds received by Tri-Union or any Restricted
Subsidiary in connection with the Synthetic Lease are at least equal to the
fair value, as determined by the Board of Directors of Tri-Union of the
property; and
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(3) Tri-Union or the Restricted Subsidiary shall apply or cause to be
applied the proceeds of the transaction in compliance with the covenant
described under the heading "-- Limitation on Sales of Assets."
Future Subsidiary Guarantors
Tri-Union shall cause each of its Subsidiaries which is or becomes a
Restricted Subsidiary to execute an Assumption Agreement required by the
Guaranty Agreement.
Merger and Consolidation
Tri-Union shall not consolidate with or merge with or into, or convey,
transfer or lease, in one transaction or a series of transactions, all or
substantially all its assets to, any Person, unless:
(1) Tri-Union shall be the resulting, surviving or transferee
corporation (the "Successor Company");
(2) the Successor Company, if not Tri-Union, shall expressly assume by
a supplemental indenture, in a form acceptable to the trustee, all the
obligations of Tri-Union under the indenture and the Security Documents;
(3) immediately after giving effect to the transaction on a pro forma
basis, and treating any Indebtedness which becomes an obligation of the
Successor Company as a result of the transaction as having been issued by
the Person at the time of the transaction, no Default shall have occurred
and be continuing;
(4) immediately after giving effect to the transaction, the Successor
Company would be able to Incur an additional $1.00 of Indebtedness pursuant
to paragraph (1) of the covenant described under the heading "-- Limitation
on Indebtedness";
(5) immediately after giving effect to the transaction, the Successor
Company shall have Consolidated Net Worth in an amount that is not less
than the Consolidated Net Worth of Tri-Union immediately prior to the
transaction; and
(6) Tri-Union delivers to the trustee an officers' certificate and an
opinion of counsel, each stating that the consolidation, merger or transfer
and the supplemental indenture, if any, complies with the indenture.
The Successor Company shall be the successor to Tri-Union and shall succeed to,
and be substituted for, and may exercise every right and power of, Tri-Union
under the indenture.
SEC Reports
Notwithstanding that Tri-Union may not at any time be subject to the
reporting requirements of Section 13 or 15 of the Exchange Act, Tri-Union shall
provide the trustee and the Holders, in each case within 15 days after the time
periods specified for the filings in the SEC's rules and regulations:
(1) all quarterly and annual financial information that would be
required to be contained in a filing by Tri-Union with the SEC on Forms
10-Q and 10-K if Tri-Union were required to file such form, including a
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and, with respect to the annual information only, a report on
the annual financial statements by Tri-Union certified independent
accountants; and
(2) all current reports that would be required to be filed with the
SEC on Form 8-K if Tri-Union were required to file the reports;
provided that after the date that the Exchange Offer Registration Statement or
the Shelf Registration Statement, as the case may be, is due to be filed, and
notwithstanding that Tri-Union may not be
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subject to the reporting requirements of Section 13 or 15 of the Exchange Act,
Tri-Union will file with the SEC, to the extent permitted, and provide the
trustee and the Holders with the annual and quarterly reports and the
information, documents and other reports specified in Sections 13 and 15(d) of
the Exchange Act.
Limitation on Impairment of Lien
Neither Tri-Union nor any of its Affiliates will take or omit to take any
action which action or omission would have the result of adversely affecting or
impairing the Lien in favor of the Collateral Agent, on behalf of itself, the
Approved Hedge Counterparties or Hedge Liquidity Providers, as applicable, the
trustee and the Holders or the priority thereof, with respect to the Collateral,
and neither Tri-Union nor any of its Affiliates shall grant to any Person, or
suffer any Person, other than Tri-Union and the Restricted Subsidiaries, to have
(other than to the Collateral Agent on behalf of the Approved Hedge
Counterparties or Hedge Liquidity Providers, as applicable, the trustee and the
Holders) any interest whatsoever in the Collateral other than Permitted Liens.
Neither Tri-Union nor any of the Restricted Subsidiaries will enter into any
agreement or instrument that by its terms requires the proceeds received from
any sale of Collateral to be applied to repay, redeem, defease or otherwise
acquire or retire any Indebtedness, other than pursuant to the indenture and the
Security Documents.
Limitation on Conduct of Business
Tri-Union will not, and will not permit any of the Restricted Subsidiaries
to, engage in the conduct of any business other than the oil and gas business.
Lien on Additional Collateral
(1) If, after the Closing Date, Tri-Union or any of the Restricted
Subsidiaries shall (a) acquire any oil and gas assets or other assets as
non-cash consideration for any Asset Disposition or (b) engage in successful
drilling and exploration activities resulting in the creation of new proved oil
and gas reserves having a PV-10 Value in excess of $500,000, then Tri-Union
shall, and shall cause each of the Restricted Subsidiaries to, execute and file
in the appropriate filing offices additional Security Documents granting to the
Collateral Agent for the benefit of the Approved Hedge Counterparties or Hedge
Liquidity Providers, as applicable, the trustee and the Holders a first Lien,
subject only to Permitted Liens (or in the case of property securing Acquired
Indebtedness, to the extent not prohibited by the terms of the instruments
creating the Acquired Indebtedness, a junior Lien), as is necessary or
appropriate to ensure that the Lien of the indenture and the Security Documents
covers substantially all of the new assets.
(2) On the date any oil and gas assets or interests in a Permitted Joint
Venture shall be acquired in exchange for or replacement of any Collateral,
Tri-Union shall, and shall cause each of the Restricted Subsidiaries to, execute
and file in the appropriate filing offices additional Security Documents
granting to the Collateral Agent, for the benefit of the Approved Hedge
Counterparties or Hedge Liquidity Providers, as applicable, the trustee and the
Holders, a first Lien, subject only to Permitted Liens (or in the case of
property securing Acquired Indebtedness, to the extent not prohibited by the
terms of the instruments creating the Acquired Indebtedness, a junior Lien), on
the portion of the assets as is necessary to ensure that the Lien of the
indenture and the Security Documents covers substantially all of the assets
received in exchange or trade or on the interests in the Permitted Joint
Venture.
(3) In connection with any Security Documents executed and filed under
clause (1) or (2), Tri-Union shall, and shall cause each Restricted Subsidiary
to, comply with the terms of the Trust Indenture Act to the extent applicable.
(4) On March 15th of each year that the Notes are outstanding, beginning
with March 15, 2002, Tri-Union shall review the oil and gas assets of Tri-Union
and the Restricted Subsidiaries as of the
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preceding January 1st to ascertain whether substantially all of the oil and gas
assets as of such January 1st are then subject to the Lien of the indenture and
the Security Documents, provided that to the extent any such oil and gas assets
secure Acquired Indebtedness, the discounted future net revenues attributable to
the oil and gas assets may be excluded to the extent the instruments securing
the Acquired Indebtedness prohibit the Incurrence of a Lien on the assets. If
substantially all of the assets are not then subject to the Lien of the
indenture and the Security Documents, then Tri-Union shall, and shall cause the
Restricted Subsidiaries to, execute and file in the appropriate filing offices
additional Security Documents granting to the Collateral Agent for the benefit
of the Approved Hedge Counterparties or Hedge Liquidity Providers, as
applicable, the trustee and the Holders a first Lien, subject only to Permitted
Liens (or in the case of property securing Acquired Indebtedness, to the extent
not prohibited by the terms of instruments creating the Acquired Indebtedness, a
junior Lien), as is necessary or appropriate to encumber substantially all the
assets.
Reserve Reports
Not later than March 15 of each year, commencing March 15, 2002, Tri-Union
shall furnish to the trustee a Reserve Report that (a) evaluates the oil and gas
assets of Tri-Union and the Restricted Subsidiaries as of the immediately
preceding January 1st, and (b) sets forth the projected production from proved
producing properties for each month during the period commencing on such March
15 and ending 36 months after such date, for both crude oil and natural gas
production, individually, and in the aggregate on an Mcfe basis. In addition,
not later than 30 days following any acquisition or exchange, or series of such
transactions, of any oil and gas assets having aggregate volumes of proved
developed producing reserves in excess of 20% of the aggregate proved producing
reserves set forth in the most recently delivered Reserve Report, Tri-Union
shall furnish to the trustee a supplemental Reserve Report pertaining to the oil
and gas assets acquired in the exchange. Each such Reserve Report of each year
shall be prepared by certified independent petroleum engineers or other
independent petroleum consultant(s) of recognized national standing.
Hedging Obligations
Tri-Union and/or a Restricted Subsidiary will enter into and maintain oil
and gas Hedging Contracts with an Approved Hedge Counterparty pursuant to which
Tri-Union and/or a Restricted Subsidiary will receive a fixed price payment or a
minimum floor price so that at all times to July 1, 2006, Tri-Union and/or a
Restricted Subsidiary will have a Hedged Revenue Ratio of not less than 3.0 to
1.0 as of the first business day of each month for the then current Hedge
Period; provided that:
(1) in no event shall Tri-Union and/or a Restricted Subsidiary enter
into oil and gas hedging contracts that, when in effect, hedge aggregate
volumes in excess of 80% of (a) the Projected Proved Developed Producing
Production of each of crude oil and natural gas and (b) the Projected
Proved Developed Producing Production of both crude oil and natural gas, in
each case, from the oil and gas assets of Tri-Union and/or the Restricted
Subsidiaries for the then current Hedge Period and each month in the then
current Hedge Period, except that Tri-Union and/or a Restricted Subsidiary
may enter into oil and gas hedging contracts which are price floor
contracts, options for a price floor or other similar arrangements (and for
which neither Tri-Union nor any Restricted Subsidiary has any liability
other than the payment of an initial premium price) which, with all oil and
gas hedging contracts then in effect, result in the aggregate volumes
exceeding 80%, but in no event in excess of 100%, of the Projected Proved
Developed Producing Production of each of oil and natural gas of Tri-Union
and the Restricted Subsidiaries;
(2) any oil and gas hedging contract executed pursuant to this
covenant may be terminated, for any reason, without violation of this
covenant if either (a) termination is required pursuant to clause (4) below
or (a) a replacement oil and gas hedging contract with an Approved Hedge
Counterparty is entered into such that, after giving effect to the
termination and the execution
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and delivery of the replacement oil and gas hedging contract, the Hedged
Revenue Ratio is not less than 3.0 to 1.0, subject to clause (1) of this
covenant;
(3) if, as of any date of determination, NYMEX prices available for
natural gas (Henry Hub) and crude oil (West Texas Intermediate) are less
than $2.75 per MMBtu of natural gas (Henry Hub) or $18.00 per barrel of
crude oil (West Texas Intermediate) for the one or more months during the
then current Hedge Period (such period during which such prices are not
available being the "Make-Up Period"), then the Hedged Revenue Ratio shall
not be tested during the Make-Up Period, and as soon thereafter as
available hedge prices for the Make-Up Period or any month during the
Make-Up Period exceed the relevant minimum levels, then Tri-Union and/or a
Restricted Subsidiary shall be required to have a Hedged Revenue Ratio for
the then current Hedge Period of not less than 3.0 to 1.0, subject to
clause (1) of this covenant; and
(4) in the event of any sale, exchange or other disposition of oil and
gas assets by Tri-Union and/or any Restricted Subsidiary, Tri-Union and/or
a Restricted Subsidiary shall calculate its Hedged Revenue Ratio on a pro
forma basis (to exclude the oil and gas asset disposed of utilizing the
Projected Proved Developed Producing Production for the asset reflected in
the most recently delivered Reserve Report) as of the first day of the
month during which the sale, exchange or other disposition occurred for the
Hedge Period commencing on such date and shall either (a) be in compliance
with this covenant as of such day for the entirety of the Hedge Period or
(b) terminate one or more oil and gas hedging contracts such that after
giving effect to the termination, it would be in compliance with this
covenant.
Notwithstanding anything herein to the contrary, Tri-Union and/or a
Restricted Subsidiary will enter into oil and gas hedging contracts for ordinary
business purposes, to hedge their and the Restricted Subsidiaries' actual
exposure to fluctuations in commodity prices and not for speculative purposes.
It is the intention of the parties that if (a) as of the first business day
of each month for the then current Hedge Period the Hedged Revenue Ratio is less
than 3.0 to 1.0, and (b) a Reserve Report is delivered which indicates an
increase in the Projected Proved Producing Production for any month or months in
the then current Hedge Period or in the aggregate Projected Proved Producing
Production, then Tri-Union and/or a Restricted Subsidiary shall be obligated to
enter into and maintain incremental oil and gas hedging contracts with an
Approved Hedge Counterparty to hedge incremental volumes such that it has either
met the minimum Hedge Revenue Ratio of 3.0 to 1.0 or hedged the maximum amount
of revenue for each month in the then current Hedge Period possible without
violating the volume caps set forth in clause (1) of this covenant.
Excess Cash Flow Offer
On the 45th day following the end of each fiscal quarter, commencing with
the quarter ended June 30, 2004, Tri-Union shall calculate its Excess Cash Flow
for the most recently ended fiscal quarter, certify to the trustee in writing
the calculations to compute the Excess Cash Flow, and if Tri-Union has Excess
Cash Flow of at least $1,000,000, Tri-Union will make an offer (an "Excess Cash
Flow Offer") to purchase Notes at 100% of the aggregate principal amount of the
Notes, plus accrued interest, to the date of purchase; provided that the amount
required to be paid by Tri-Union to repurchase the Notes shall be limited to an
amount equal to 50% of the Excess Cash Flow.
Tri-Union must commence its Excess Cash Flow Offer not later than the date
on which the certificate computing the Excess Cash Flow is delivered to the
trustee. If the aggregate purchase price for the Notes, exclusive of interest,
tendered pursuant to the Excess Cash Flow Offer is less than the Excess Cash
Flow, then Tri-Union and the Restricted Subsidiaries may use the remaining
Excess Cash Flow for general corporate purposes not prohibited by the terms of
the indenture.
Each Excess Cash Flow Offer shall remain open for a period of 20 Business
Days, unless a longer period is required by law (the "Excess Cash Flow Offer
Period"). Promptly after the
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termination of the Excess Cash Flow Period (the "Excess Cash Flow Payment
Date"), Tri-Union shall purchase and mail or deliver payment for the Notes or
portions of the Notes tendered pro rata or by such other method as may be
required by law.
Tri-Union shall make a public announcement of the results of the Excess
Cash Flow Offer as soon as practicable after the Excess Cash Flow Payment Date.
Independent Board of Tri-Union
Within 45 days of the Closing Date, the Board of Directors of Tri-Union
shall consist of at least three directors, at least 60% of whom shall be
Independent Directors, and the composition of the Board of Directors shall be
maintained so long as any of the Notes remain outstanding. Until a Board of
Directors meeting the requirements of this covenant shall have been appointed,
Tri-Union and the Restricted Subsidiaries shall not engage in any activities
requiring the approval of the Board of Directors of Tri-Union under the terms of
the indenture except for the transactions disclosed in this prospectus.
Jefferies shall have the right to require that Tri-Union cause to be appointed
to its Board of Directors a person designated by Jefferies for so long as any of
the Notes remain outstanding.
Exploration Costs
Tri-Union and the Restricted Subsidiaries shall not incur exploration costs
(as reported in the supplemental oil and natural gas information in Tri-Union's
annual financial statements in accordance with GAAP) in excess of $10,000,000 in
any fiscal year.
DEFAULTS
An "Event of Default" is defined in the indenture as:
(1) a default in the payment of interest on the Notes when due,
continued for 30 days;
(2) a default in the payment of principal of any Note when due at its
Stated Maturity, upon optional redemption, upon required repurchase, upon
declaration or otherwise;
(3) the failure by Tri-Union to comply with its obligations described
under the heading "-- Certain Covenants -- Merger and Consolidation" or the
failure by any Subsidiary Guarantor to comply with its obligations
described in the final paragraph under the heading "-- Guarantees;"
(4) the failure by Tri-Union or any Restricted Subsidiaries to comply
for 30 days after notice from the trustee or any Holder with any of its
obligations, if any, in the covenants described under the heading
"-- Certain Covenants -- Limitation on Indebtedness," "-- Limitation on
Restricted Payments," "-- Limitation on Dividend and Other Payment
Restrictions Affecting Restricted Subsidiaries," "-- Limitation on Sales of
Assets" (other than a failure to purchase Notes), "-- Limitation on
Affiliate Transactions," "-- Limitation on the Sale or Issuance of Capital
Stock of Restricted Subsidiaries," "-- Change of Control," "-- Limitation
on Liens," "-- Limitation on Synthetic Leases," "-- Future Subsidiary
Guarantors," "-- SEC Reports," "-- Limitation on Impairment of Lien,"
"-- Limitation on Conduct of Business," "-- Lien on Additional Collateral,"
"-- Reserve Reports," "-- Hedging Obligations," "-- Excess Cash Flow
Offer," "-- Independent Board of Tri-Union," or "Exploration Costs;"
(5) the failure by Tri-Union or any Subsidiary Guarantor to comply for
60 days after notice from the trustee or any Holder with its other
agreements contained in the indenture or any Security Document;
(6) principal of, or interest on, any Indebtedness of Tri-Union or any
Restricted Subsidiary in excess of $5,000,000 is not paid when due, after
giving effect to any applicable grace period, or any default shall occur
and be continuing under any Indebtedness of Tri-Union or any Restricted
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Subsidiary in excess of $5,000,000 and the maturity thereof is accelerated
by the holders thereof (the "cross acceleration provision");
(7) certain events of bankruptcy, insolvency or reorganization of
Tri-Union or a Restricted Subsidiary (the "bankruptcy provisions");
(8) any judgment or decree for the payment of money in excess of
$5,000,000 is rendered against Tri-Union or a Restricted Subsidiary,
remains outstanding for a period of 60 days following the judgment and is
not discharged, waived or stayed within 10 days after notice from the
trustee or any Holder (the "judgment default provision");
(9) the Guaranty Agreement or any Security Document ceases to be in
full force and effect (other than in accordance with the terms of the
Guaranty Agreement or the Security Document) or Tri-Union or a Subsidiary
Guarantor denies or disaffirms its obligations under any Security Document
to which it is a party or the Guaranty Agreement, as applicable, if the
default continues for a period of 10 days after notice from the trustee or
any Holder thereof to Tri-Union; or
(10) a material breach of any of the representations or warranties
contained in any Security Document or in the indenture or a material
misstatement in any certification provided pursuant to any Security
Document or the indenture.
However, a default under clauses (4), (5), (8) and (10) will not constitute an
Event of Default until the trustee or the Holders of 25% in principal amount of
the outstanding Notes notify Tri-Union of the default and Tri-Union or the
relevant Subsidiary Guarantor does not cure the default within the time
specified after receipt of the notice.
If an Event of Default occurs and is continuing, the trustee or the Holders
of at least 25% in principal amount of the outstanding Notes may declare the
principal of and accrued but unpaid interest on all the Notes to be due and
payable. Upon such a declaration, the principal and interest shall be due and
payable immediately. If an Event of Default relating to the bankruptcy
provisions occurs and is continuing, the principal of and interest on all the
Notes will ipso facto become and be immediately due and payable without any
declaration or other act on the part of the trustee or any Holders. Under
certain circumstances, the Holders of a majority in principal amount of the
outstanding Notes may rescind any acceleration with respect to the Notes and its
consequences.
Subject to the provisions of the indenture relating to the duties of the
trustee, if an Event of Default occurs and is continuing, the trustee will be
under no obligation to exercise any of the rights or powers under the indenture
at the request or direction of any of the Holders unless the Holders have
offered to the trustee reasonable indemnity or security against any loss,
liability or expense. Except to enforce the right to receive payment of
principal or interest when due, no Holder may pursue any remedy with respect to
the indenture, the Notes or any Subsidiary Guarantee unless:
(1) the Holder has previously given the trustee notice that an Event
of Default is continuing;
(2) Holders of at least 25% in principal amount of the outstanding
Notes have requested the trustee to pursue the remedy;
(3) the Holders have offered the trustee reasonable security or
indemnity against any loss, liability or expense;
(4) the trustee has not complied with the request within 60 days after
the receipt of the request and the offer of security or indemnity; and
(5) the Holders of a majority in principal amount of the outstanding
Notes have not given the trustee a direction inconsistent with the request
within the 60-day period.
Subject to certain restrictions, the Holders of a majority in principal
amount of the outstanding Notes are given the right to direct the time, method
and place of conducting any proceeding for any
89
remedy available to the trustee or of exercising any trust or power conferred on
the trustee. The trustee, however, may refuse to follow any direction that
conflicts with law or the indenture or that the trustee determines is unduly
prejudicial to the rights of any other Holder of a Note or that would involve
the trustee in personal liability. No Holder may enforce any right or remedy
provided in any other Security Document. Such rights and remedies will be
enforced by the Collateral Agent subject to the terms of the Intercreditor
Agreement.
If a Default occurs and is continuing and is known to the trustee, the
trustee must mail to each Holder notice of the Default within 90 days after it
occurs. Except in the case of a Default in the payment of principal of or
interest on any Note, the trustee may withhold notice if and so long as a
committee of its trust officers determines that withholding notice is not
opposed to the interest of the Holders. In addition, Tri-Union is required to
deliver to the trustee, within 120 days after the end of each fiscal year, an
officers' certificate indicating whether the signer of the certificate knows of
any Default that occurred during the fiscal year. Tri-Union also is required to
deliver to the trustee, within 30 days after the occurrence thereof, written
notice of any event which would constitute certain Defaults, their status and
what action Tri-Union is taking or proposes to take in respect thereto.
AMENDMENTS AND WAIVERS
Subject to certain exceptions, the indenture may be amended with the
consent of the Holders of a majority in principal amount of the Notes then
outstanding (including consents obtained in connection with a tender offer or
exchange for the Notes) and any past default or noncompliance with any
provisions may also be waived with the consent of the Holders of a majority in
principal amount of the Notes then outstanding. However, without the consent of
each Holder of an outstanding Note affected thereby, no amendment may, among
other things:
(1) reduce the amount of Notes whose Holders must consent to an
amendment;
(2) reduce the rate of or extend the time for payment of interest on
any Note;
(3) reduce the principal of or extend the Stated Maturity of any Note;
(4) reduce the premium payable upon the redemption of any Note or
change the time at which any Note may be redeemed;
(5) make any Note payable in any currency other than that stated in
the Note;
(6) impair the right of any Holder to receive payment of principal of
and interest and any additional interest on the Holder's Notes on or after
the due dates therefor (other than a payment required by one of the
covenants described above under the heading "-- Certain
Covenants -- Limitation on Sales of Assets" or "-- Change of Control") or
to institute suit for the enforcement of any payment on or with respect to
the Holder's Notes;
(7) make any change in the amendment provisions which require each
Holder's consent or in the waiver provisions;
(8) make any change in any Subsidiary Guarantee or any Security
Document that could adversely affect the Holder; or
(9) release any Collateral from the Liens created pursuant to the
indenture and the Security Documents or release any Subsidiary Guarantor
from any of its obligations under the indenture or the Guaranty Agreement,
as the case may be, in any case otherwise than in accordance with the terms
of the indenture, the Guaranty Agreement and the Security Documents.
Without notice to or the consent of any Holder, the trustee, Tri-Union and
the Subsidiary Guarantors may amend the indenture to cure any ambiguity,
omission, defect or inconsistency, to provide for the assumption by a Successor
Company of the obligations of Tri-Union or a Subsidiary Guarantor under the
indenture, the Security Documents or the Guaranty Agreement, as the case may be,
to provide for uncertificated Notes in addition to or in place of certificated
Notes, to make
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any change that does not adversely affect the rights of any Holder or to comply
with any requirement of the SEC in connection with the qualification of the
indenture under the Trust Indenture Act.
The consent of the Holders is not necessary under the indenture to approve
the particular form of any proposed amendment. It is sufficient if the consent
approves the substance of the proposed amendment.
Amendments, modifications, supplements, waivers, consents and approvals of
or in connection with the Guaranty Agreement, the Intercreditor Agreement and
any Security Document may be effectuated only upon the written consent of each
of the Approved Hedge Counterparties then a party thereto, Hedge Liquidity
Providers having greater than 50% of the aggregate commitments of the Hedge
Liquidity Providers if a Hedge Liquidity Agreement is in place and Holders
having 50% or more of the outstanding principal amount of the then outstanding
principal amount of the Notes (and, if the rights or duties of the Collateral
Agent or the trustee or any of the Issuer or Subsidiary Guarantors are affected
thereby, by the Collateral Agent, the trustee, the Issuer or the applicable
Subsidiary Guarantor, as the case may be); provided that
(1) the provisions of the Intercreditor Agreement governing
application of proceeds shall not be amended without the unanimous written
consent of each creditor and, if the rights or duties of the Collateral
Agent, the trustee or any of the Issuer or Subsidiary Guarantors are
affected thereby, by the Collateral Agent, the trustee or the Issuer, or
applicable Subsidiary Guarantor, as the case may be;
(2) any waiver of Triggering Events, Releases of Collateral (except
Asset Dispositions, Released Working Capital Revolver Interests and
Releases of Collateral Account Assets in accordance with the terms of the
Intercreditor Agreement) and any release of the Issuer, or any Subsidiary
Guarantor requires approval of the Approved Hedge Counterparties; and
(3) no Security Document may be amended if the effect of the amendment
would be:
(a) to secure additional obligations, other than additional Notes
issued under the indenture, or any other obligations
(b) to secure indebtedness or obligations owed in favor of any
other creditor or groups of creditors;
(c) to change the priority of or subordinate the Liens created
thereby;
(d) to modify any material remedy provided for therein; or
(e) to cause the obligations owed to any Holder, Hedge Liquidity
Provider or Approved Hedge Counterparty to not be equally and ratably
secured thereby (subject to the priorities set forth herein).
After an amendment under the indenture, the Guaranty Agreement or any
Security Document becomes effective, Tri-Union is required to mail to Holders a
notice briefly describing the amendment. However, the failure to give the notice
to all Holders, or any defect therein, will not impair or affect the validity of
the amendment.
POSSESSION, USE AND RELEASE OF COLLATERAL
Unless an Event of Default or a Termination Event under the indenture, the
Approved Hedge Agreement or the Hedge Liquidity Agreements (the "Principal
Agreements") shall have occurred and be continuing, Tri-Union and the Restricted
Subsidiaries will have the right to remain in possession and retain exclusive
control of the Collateral securing the Notes (other than any cash, securities,
obligations and Temporary Cash Investments constituting part of the Collateral
and deposited with the Collateral Agent in the Collateral Account and other than
as set forth in the Security
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Documents), to freely operate the Collateral and to collect, invest and dispose
of any income thereon or therefrom.
Release of Collateral
Upon compliance by Tri-Union and the Restricted Subsidiaries with the
conditions set forth in the indenture in respect of any sale, lease, transfer or
other disposition to any Person involving Collateral (including the disposition
of all of the Capital Stock of a Subsidiary Guarantor), the trustee will direct
the Collateral Agent to release the Collateral from the Lien of the Security
Documents and reconvey the Released Interests to the Collateral to Tri-Union or
the relevant Restricted Subsidiary or such other Person as Tri-Union or the
relevant Restricted Subsidiary may direct in writing. Tri-Union and the
Restricted Subsidiaries will have the right to obtain a release of items of
Collateral subject to any sale, lease, transfer or other disposition or owned by
a Subsidiary Guarantor all of the Capital Stock of which is the subject of a
disposition under limited circumstances.
Upon compliance by Tri-Union and the Restricted Subsidiaries, with the
conditions set forth in the indenture in respect of any instrument governing a
Working Capital Revolver, to the extent and only to the extent the instrument
involves the creation of Permitted Liens on accounts receivable, related general
intangibles and related proceeds of Tri-Union and the Restricted Subsidiaries to
secure Indebtedness Incurred under the Working Capital Revolver, the trustee
will direct the Collateral Agent to release the Collateral from the Lien of the
indenture and the Security Documents and reconvey the Collateral to Tri-Union or
the Restricted Subsidiaries or such other Person as they may direct in writing.
Tri-Union and the Restricted Subsidiaries will have the right to obtain a
release of the accounts receivable, related general intangibles and related
proceeds of Tri-Union and the Restricted Subsidiaries to secure Indebtedness
Incurred under the Working Capital Revolver.
Notwithstanding the provisions described under this heading "-- Release of
Collateral," so long as no Event of Default or Termination Event under any of
the Principal Agreements shall have occurred and be continuing or would result
therefrom, Tri-Union or a Restricted Subsidiary may engage in any number of
ordinary course activities in respect of the Collateral, in limited dollar
amounts specified by the Trust Indenture Act, upon satisfaction of certain
conditions. For example, among other things, subject to the dollar limitations
and conditions, Tri-Union or a Restricted Subsidiary would be permitted to:
(1) sell or otherwise dispose of any property subject to the Lien of
the Security Documents, which may have become worn out or obsolete;
(2) abandon, terminate, cancel, release or make alterations in or
substitutions of any leases or contracts subject to the Lien of the
Security Documents;
(3) surrender or modify any franchise, license or permit subject to
the Lien of the Security Documents which it may own or under which it may
be operating;
(4) alter, repair, replace, change the location or position of and add
to its structures, machinery, systems, equipment, fixtures and
appurtenances;
(5) demolish, dismantle, tear down or scrap any Collateral or abandon
any Collateral thereof; and
(6) grant farm-outs, leases or sub-leases in respect of real property
to the extent any of the preceding does not constitute an Asset
Disposition.
Deposit, Use and Release of Trust Moneys
All Net Available Cash aggregating in excess of $1,000,000 in any fiscal
year from any Asset Dispositions involving Collateral shall be deposited into a
securities account maintained by the Collateral Agent at its corporate offices
or at any securities intermediary selected by the trustee having a combined
capital and surplus of at least $250,000,000 and having a long-term debt rating
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of at least "A3" by Moody's Investors Service, Inc. and at least "A -- " by
Standard & Poor's Ratings Services styled the "Tri-Union Collateral Account"
(such account being the "Collateral Account") which shall be under the exclusive
dominion and control of the Collateral Agent.
All amounts on deposit in the Collateral Account shall be treated as
financial assets and cash funds on deposit in the Collateral Account may be
invested by the Collateral Agent, at the direction of Tri-Union, as applicable,
in Temporary Cash Investments; provided, however, in no event shall Tri-Union
have the right to withdraw funds or assets from the Collateral Account except in
compliance with the terms of the Intercreditor Agreement and all assets credited
to the Collateral Account shall be subject to a perfected, first priority Lien
in favor of the Collateral Agent for the benefit of the Approved Hedge
Counterparties or Hedge Liquidity Providers (as applicable), the trustee and the
Holders.
Any such funds will be released to Tri-Union by it delivering to the
Collateral Agent and the trustee an officers' certificate stating that:
(1) no Event of Default or Termination Event under any Principal
Agreement has occurred and is continuing as of the date of the proposed
release;
(2) (a) if the Trust Moneys represent Net Available Cash subject to the
covenant described under the heading "-- Certain Covenants -- Limitation
on Sales of Assets" in respect of an Asset Disposition, that the funds
will be applied in accordance with the covenant; or
(b) if the Trust Moneys do not represent Net Available Cash,
subject to the covenant described under the heading "-- Certain
Covenants -- Limitation on Sales of Assets," that the amounts will be
utilized in connection with the business of Tri-Union and the Restricted
Subsidiaries in compliance with the terms of the Approved Hedging
Agreements, the Hedge Liquidity Agreements (if applicable) and the
indenture;
(3) all other terms and conditions in the Approved Hedge Agreements,
the Hedge Liquidity Agreements (if applicable) and the indenture relating
to the release in question have been complied with; and
(4) all documentation required by the Trust Indenture Act, if any,
prior to the release of the Trust Moneys has been delivered to the
Collateral Agent and the trustee.
Notwithstanding the preceding, (1) if no Triggering Event has occurred and
is continuing and Tri-Union so elects by giving written notice to the Collateral
Agent, the Collateral Agent shall apply Trust Moneys credited to the Collateral
Account to the payment of amounts due under any Approved Hedge Agreement
(whether regularly scheduled payments or termination payments) or Hedge
Liquidity Agreements (if applicable) or any Note, including interest due on any
interest payment date, and (2) if Tri-Union so elects, by giving written notice
to the Collateral Agent, the Collateral Agent shall, subject to the priorities
set forth in the Intercreditor Agreement, apply Trust Moneys credited to the
Collateral Account to the payment of amounts specified in the Intercreditor
Agreement as being secured by the Collateral, including the principal of, and
accrued and unpaid interest on, any Notes at their Stated Maturity or upon
redemption or to the purchase of Notes upon tender or in the open market or at
private sale or upon any exchange or in any one or more of such ways, in each
case in compliance with the indenture and at the direction of Tri-Union.
TRANSFER
The Notes will be issued in registered form and will be transferable only
upon the surrender of the Notes being transferred for registration of transfer.
Tri-Union may require payment of a sum sufficient to cover any tax, assessment
or other governmental charge payable in connection with certain transfers and
exchanges.
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DEFEASANCE
Tri-Union at any time may terminate all its obligations under the Notes and
the indenture and all of the obligations of the Subsidiary Guarantors under the
Guaranty Agreement and the Indenture ("legal defeasance"), except for certain
obligations, including those respecting the defeasance trust and obligations to
register the transfer or exchange of the Notes, to replace mutilated, destroyed,
lost or stolen Notes and to maintain a Registrar and Paying Agent in respect of
the Notes. Tri-Union at any time may terminate its obligations under the
covenants described under the heading "-- Certain Covenants" (other than the
covenant described under the heading "-- Certain Covenants -- Merger and
Consolidation"), the operation of the cross acceleration provision, the
bankruptcy provisions with respect to Restricted Subsidiaries and the judgment
default provision described under the heading "-- Defaults" above and the
limitations contained under "-- Certain Covenants -- Merger and Consolidation"
above ("covenant defeasance").
Tri-Union may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If Tri-Union exercises its
legal defeasance option, payment of the Notes may not be accelerated because of
an Event of Default with respect thereto. If Tri-Union exercises its covenant
defeasance option, payment of the Notes may not be accelerated because of an
Event of Default specified in clause (4), (5), (6), (7) (with respect only to
Restricted Subsidiaries) or (8) under the heading "-- Defaults" above or because
of the failure to comply with the covenants under "-- Certain
Covenants -- Merger and Consolidation" above. If Tri-Union exercises its legal
defeasance option or its covenant defeasance option, each Subsidiary Guarantor,
if any, will be released from all its obligations with respect to its Guarantee
and the Lien of the Security Documents will also be released.
In order to exercise either defeasance option, Tri-Union must irrevocably
deposit in trust (the "defeasance trust") with the trustee money or United
States Government Obligations for the payment of principal and interest on the
Notes to redemption or maturity, as the case may be, and must comply with
certain other conditions, including delivery to the trustee of an opinion of
counsel to the effect that Holders will not recognize income, gain or loss for
federal income tax purposes as a result of the deposit and defeasance and will
be subject to federal income tax on the same amount and in the same manner and
at the same times as would have been the case if the deposit and defeasance had
not occurred (and, in the case of legal defeasance only, such opinion of counsel
must be based on a ruling of the Internal Revenue Service or other change in
applicable federal income tax law).
CONCERNING THE TRUSTEE
Firstar Bank, National Association, is to be the trustee under the
indenture and has been appointed by Tri-Union as the initial Registrar and
initial Paying Agent with regard to the Notes.
The Holders of a majority in principal amount of the outstanding Notes will
have the right to direct the time, method and place of conducting any proceeding
for exercising any remedy available to the trustee, subject to certain
exceptions and the terms of the Intercreditor Agreement. If an Event of Default
occurs (and is not cured), the indenture requires that the trustee, in the
exercise of its power, use the degree of care of a prudent man in the conduct of
his own affairs. Subject to such provisions, the trustee will be under no
obligation to exercise any of its rights or powers under the indenture at the
request of any Holder, unless the Holder shall have offered to the trustee
security and indemnity satisfactory to it against any loss, liability or expense
and then only to the extent required by the terms of the indenture.
BOOK-ENTRY; DELIVERY AND FORM
The Notes initially will be represented by one or more permanent global
Notes in definitive, fully registered form without interest coupons
(collectively, the "Global Note") and will be deposited with the trustee as
custodian for, and registered in the name of, a nominee of DTC.
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Ownership of beneficial interests in the Global Note will be limited to
persons who have accounts with DTC ("participants") or persons who hold
interests through participants. Ownership of beneficial interests in the Global
Note will be shown on, and the transfer of that ownership will be effected only
through, records maintained by DTC or its nominee (with respect to interests of
participants) and the records of participants (with respect to interests of
persons other than participants).
So long as DTC, or its nominee, is the registered owner or holder of the
Global Note, DTC or the nominee, as the case may be, will be considered the sole
owner or holder of the Notes represented by the Global Note for all purposes
under the indenture and the Notes. No beneficial owner of an interest in a
Global Note will be able to transfer that interest except in accordance with
DTC's applicable procedures, in addition to those provided for under the
indenture and, if applicable, those of a participant through which the Note is
held.
Payments of the principal of, and interest on, the Global Note will be made
to DTC or its nominee, as the case may be, as the registered owner of the Global
Note. Neither Tri-Union, the trustee nor any Paying Agent will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in the Global Note or
for maintaining, supervising or reviewing any records relating to the beneficial
ownership interests.
Tri-Union expects that DTC or its nominee, upon receipt of any payment of
principal or interest in respect of the Global Note, will credit participants'
accounts with payments in amounts proportionate to their respective beneficial
interests in the principal amount of the Global Note as shown on the records of
DTC or its nominee. Tri-Union also expects that payments by participants to
owners of beneficial interests in the Global Note held through the participants
will be governed by standing instructions and customary practices, as is now the
case with securities held for the accounts of customers registered in the names
of nominees for the customers. Such payments will be the responsibility of the
participants.
Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will to be settled in same-day funds.
Tri-Union expects that DTC will take any action permitted to be taken by a
Holder (including the presentation of Notes for exchange as described below)
only at the direction of one or more participants to whose account the DTC
interests in the Global Note is credited and only in respect of the portion of
the aggregate principal amount of any Note as to which the participant or
participants has or have given such direction. However, if there is an Event of
Default under the Notes, DTC may exchange the applicable Global Note for
certificated Notes, as discussed below under the heading "-- Certificated
Notes," which it will distribute to its participants.
Tri-Union understands that DTC is a limited purpose trust company organized
under the laws of the State of New York, a "banking organization" within the
meaning of New York Banking Law, a member of the Federal Reserve System, a
"clearing corporation" within the meaning of the Uniform Commercial Code and a
"Clearing Agency" registered pursuant to the provisions of Section 17A of the
Exchange Act. DTC was created to hold securities for its participants and
facilitate the clearance and settlement of securities transactions between
participants through electronic book-entry changes in accounts of its
participants, thereby eliminating the need for physical movement of certificates
and certain other organizations. Indirect access to the DTC system is available
to others such as banks, brokers, dealers and trust companies that clear through
or maintain a custodial relationship with a participant, either directly or
indirectly ("indirect participants").
Although DTC is expected to follow the preceding procedures in order to
facilitate transfers of interests in the Global Note among participants of DTC,
it is under no obligation to perform or continue to perform the procedures, and
the procedures may be discontinued at any time. Neither Tri-Union nor the
trustee will have any responsibility for the performance by DTC or its
participants or
95
indirect participants of their respective obligations under the rules and
procedures governing their operations.
CERTIFICATED NOTES
The indenture requires that payments in respect of Notes, including
principal and interest, be made by wire transfer of immediately available funds
to the account specified by the Holders of the Notes or, if no such account is
specified, by mailing a check to each such Holder's registered address.
If DTC is at any time unwilling or unable to continue as a depositary for
the Global Note and a successor depositary is not appointed by Tri-Union within
90 days, Tri-Union will issue certificated Notes in exchange for the Global
Note.
GOVERNING LAW
The indenture provides that it and the Notes will be governed by, and
construed in accordance with, the laws of the State of New York. The Security
Documents and the Guaranty Agreement will be governed by, and construed in
accordance with, the laws of the State of New York, except to the extent the law
of another jurisdiction otherwise mandatorily applies to certain issues.
CERTAIN DEFINITIONS
"Accreted Value" means $945.00 per Note, initially, increasing by $27.50
for each quarter following the Closing Date, not to exceed $1,000.00 at any
time.
"Acquired Indebtedness" means Indebtedness of Tri-Union or any of the
Restricted Subsidiaries of the type described under clause (2)(f) of the
covenant described under the heading "-- Certain Covenants -- Limitation on
Indebtedness."
"Additional Assets" means:
(1) any property or assets (other than cash or cash equivalents,
Indebtedness and Capital Stock) used or useful in the oil and gas business;
or
(2) the Capital Stock of a Person that becomes a Restricted Subsidiary
as a result of the acquisition of the Capital Stock by Tri-Union or a
Restricted Subsidiary;
provided that any such Restricted Subsidiary described in clause (2) above is
primarily engaged in the oil and gas business.
"Adjusted Consolidated Net Tangible Assets" means (without duplication), as
of the date of determination,
(1) the sum of:
(a) discounted future net revenues from proved oil and gas reserves
of Tri-Union and any Restricted Subsidiaries calculated in accordance
with SEC guidelines before any state or federal income taxes, as
estimated in a reserve report prepared as of the end of Tri-Union's most
recently completed fiscal year, which reserve report is prepared or
reviewed by independent petroleum engineers, as increased by, as of the
date of determination, the discounted future net revenues of (i)
estimated proved oil and gas reserves of Tri-Union and any Restricted
Subsidiaries attributable to any material acquisition consummated since
the date of the year-end reserve report, and (ii) estimated proved oil
and gas reserves of Tri-Union and any Restricted Subsidiaries
attributable to material extensions, discoveries and other additions and
upward determinations of estimates of proved oil and gas reserves due to
exploration, development or exploitation, production or other activities
conducted or otherwise occurring since the date of the year-end reserve
96
report which would, in the case of determinations made pursuant to
clauses (i) and (ii), in accordance with standard industry practice,
result in such additions or revisions, in each case calculated in
accordance with SEC guidelines (utilizing the prices utilized in the
year-end reserve report), and decreased by, as of the date of
determination, the discounted future net revenues of (iii) estimated
proved oil and gas reserves of Tri-Union and any Restricted Subsidiaries
produced or disposed of since the date of the year-end reserve report
and (iv) reductions in the estimated proved oil and gas reserves of
Tri-Union and any Restricted Subsidiaries since the date of the year-end
reserve report attributable to material downward determinations of
estimates of proved oil and gas reserves due to exploration, development
or exploitation, production or other activities conducted or otherwise
occurring since the date of the year-end reserve report which would, in
the case of determinations made pursuant to clauses (iii) and (iv), in
accordance with standard industry practice, result in such
determinations, in each case calculated in accordance with SEC
guidelines (utilizing the prices utilized in the year-end reserve
report); provided that, in the case of each of the determinations made
pursuant to clauses (i) through (iv), the increases and decreases shall
be as estimated by Tri-Union's engineers unless, if as a result of the
acquisitions, dispositions, discoveries, extensions or revisions, there
is a Material Change, then the increases and decreases in the discounted
future net revenue shall be confirmed in writing by an independent
petroleum engineer;
(b) the capitalized costs that are attributable to oil and gas
properties of Tri-Union and any Restricted Subsidiaries to which no
proved oil and gas reserves are attributed, based on Tri-Union's and the
Restricted Subsidiaries' books and records as of a date no earlier than
the date of Tri-Union's latest annual or quarterly financial statements;
(c) the Net Working Capital on a date no earlier than the date of
Tri-Union's latest annual or quarterly financial statements; and
(d) the greater of (i) the net book value on a date no earlier than
the date of Tri-Union's latest annual or quarterly financial statements
and (ii) the appraised value, as estimated by independent appraisers, of
other tangible assets of Tri-Union and any Restricted Subsidiaries as of
a date no earlier than the date of Tri-Union's latest audited financial
statements (provided that Tri-Union shall not be required to obtain such
an appraisal of the assets if no such appraisal has been performed);
minus
(2) the sum of:
(a) minority interests;
(b) any gas balancing liabilities of Tri-Union and any Restricted
Subsidiaries reflected in Tri-Union's latest audited financial
statements;
(c) the discounted future net revenue, calculated in accordance
with SEC guidelines (utilizing the same prices utilized in Tri-Union's
year-end reserve report), attributable to reserves subject to
participation interests, overriding royalty interests or other interests
of third parties, pursuant to participation, partnership, vendor
financing or other agreements then in effect, or which otherwise are
required to be delivered to third parties;
(d) the discounted future net revenues, calculated in accordance
with SEC guidelines (utilizing the same prices utilized in Tri-Union's
year-end reserve report), attributable to reserves that are required to
be delivered to third parties to fully satisfy the obligations of
Tri-Union and any Restricted Subsidiaries with respect to Volumetric
Production Payments on the schedules specified with respect thereto; and
(e) the discounted future net revenues, calculated in accordance
with SEC guidelines, attributable to reserves subject to
Dollar-Denominated Production Payments that, based on the estimates of
production included in determining the discounted future net revenues
97
specified in the immediately preceding clause (1)(a) (utilizing the same
prices utilized in Tri-Union's year-end reserve report), would be
necessary to satisfy fully the obligations of Tri-Union and any
Restricted Subsidiaries with respect to Dollar-Denominated Production
Payments on the schedules specified with respect thereto.
"Affiliate" of any specified Person means any other Person, directly or
indirectly, controlling or controlled by or under direct or indirect common
control with the specified Person, and if the Person is an individual, any
family member of the Person within four degrees of consanguinity and spouses of
the persons. For the purposes of this definition, "control" when used with
respect to any Person means the power to direct the management and policies of
the Person, directly or indirectly, whether through the ownership of voting
securities, by contract or otherwise; and the terms "controlling" and
"controlled" have meanings correlative to the preceding. For purposes of the
provisions described under the heading "-- Certain Covenants -- Limitation on
Restricted Payments," "-- Limitation on Sales of Assets" and "-- Limitation on
Affiliate Transactions" only, "Affiliate" shall also mean any beneficial owner
of Capital Stock representing 10% or more of the total voting power of the
Voting Stock (on a fully diluted basis) of a Person or of rights or warrants to
purchase such Capital Stock (whether or not currently exercisable) and any
Person who would be an Affiliate of any such beneficial owner pursuant to the
first sentence hereof.
"Affiliate Transactions" has the meaning given to the term under the
heading "-- Certain Covenants -- Limitation on Affiliate Transactions."
"Approved Hedge Agreement" means:
(1) any oil and gas hedging contract with Bank of America, N.A.;
(2) any oil and gas hedging contract with any other Approved Hedge
Counterparty (a) which designates in the confirmation or other transaction
statement pursuant to which the oil and gas hedging contract is evidenced
that it is an "Approved Hedge Agreement" for purposes of the Intercreditor
Agreement, the indenture and the Security Documents; and (b) a copy of
which has been delivered to the Collateral Agent and the trustee, in case
of either (1) or (2) until (i) the Approved Hedge Counterparty ceases to be
an Approved Hedge Counterparty under the Intercreditor Agreement or (ii)
the Approved Hedge Counterparty specifies in writing to the Collateral
Agent, the trustee and Tri-Union that the contract ceased to be an Approved
Hedge Agreement; and
(3) any oil and gas hedging contract that is a price floor, option for
a price floor or other similar arrangement for which, upon entering into
the contract, neither Tri-Union nor any Restricted Subsidiary will have any
liability other than the payment of an initial premium price.
"Approved Hedge Counterparties" means:
(1) Bank of America, N.A., unless it has ceased to be an Approved
Hedge Counterparty;
(2) any other Person that (a) executes an Oil and Gas Hedging Contract
with Tri-Union or a Restricted Subsidiary, (b) has, or receives credit
support in the form of an unconditional guarantee of payment from a parent
who has a long-term unsecured senior debt rating of at least BBB- by
Standard & Poor's Rating Service or Baa3 by Moody's Investors Service,
Inc., (c) is designated as such by Tri-Union in writing to the trustee and
the Collateral Agent and (d) if no Hedge Liquidity Provider is then (or
thereafter) providing letters of credit as collateral for the Hedging
Obligations owed to the Person or the Person has not otherwise ceased to be
an Approved Hedge Counterparty, executes and delivers to the Collateral
Agent and the trustee a supplement to the Intercreditor Agreement; and
(3) for purposes of the covenant "-- Hedging Obligations" and the
definition of "Hedged Revenues" only, the Persons in Clauses (1) and (2)
above and any Person who meets the requirement set forth in subclause
(2)(b) above and who enters into any oil and gas hedging
98
contract with Tri-Union or a Restricted Subsidiary that is a price floor,
option for a price floor or other similar arrangement for which, upon
entering into the contract, neither Tri-Union nor any Restricted Subsidiary
will have any liability other than the payment of an initial premium price.
"Asset Disposition" means any sale, lease, transfer or other disposition
(or series of related sales, leases, transfers or dispositions) by Tri-Union or
any Restricted Subsidiary, including any disposition by means of a merger,
consolidation or similar transaction (each referred to for the purposes of this
definition as a "disposition"), of:
(1) any shares of Capital Stock of a Restricted Subsidiary (other than
directors' qualifying shares or shares required by applicable law to be
held by a Person other than Tri-Union or a Restricted Subsidiary);
(2) all or substantially all the assets of any division or line of
business of Tri-Union or any Restricted Subsidiary; or
(3) any other assets of Tri-Union or any Restricted Subsidiary outside
of the ordinary course of business of Tri-Union or the Restricted
Subsidiary.
Notwithstanding the preceding, none of the following shall be deemed to be an
Asset Disposition:
(1) a disposition by a Restricted Subsidiary to Tri-Union or by
Tri-Union or a Restricted Subsidiary to a Wholly Owned Subsidiary;
(2) the sale or transfer, whether or not in the ordinary course of
business, of oil and gas properties; provided that at the time of the sale
or transfer the properties do not have associated with them any proved
reserves;
(3) the abandonment, farm-out, lease or sublease of developed or
undeveloped oil and gas properties in the ordinary course of business;
(4) the trade or exchange by Tri-Union or any Restricted Subsidiary of
any oil and gas property owned or held by Tri-Union or the Restricted
Subsidiary for any oil and gas property owned or held by another Person,
provided that if any property so contains proved reserves, then the
property received therefor contains a reasonably equivalent value of proved
reserves;
(5) the trade or exchange by Tri-Union or any Restricted Subsidiary of
any oil and gas property owned or held by Tri-Union or the Restricted
Subsidiary for any Investment in equity interests of a Person engaged in
the oil and gas business, provided that if any property so traded or
exchanged contains proved reserves, then (a) Tri-Union's or the Restricted
Subsidiary's pro rata Investment in the Person shall represent a reasonably
equivalent value of proved reserves and (b) the Person is or becomes by
virtue of the Investment a Restricted Subsidiary; or
(6) the sale or transfer of hydrocarbons or other mineral products or
surplus or obsolete equipment all in the ordinary course of business.
"Attributable Debt" in respect of a Synthetic Lease means, as at the time
of determination, the present value (discounted at the interest rate implicit in
the Synthetic Lease, compounded annually) of the total obligations of the lessee
for rental payments during the remaining term of the lease included in the
Synthetic Lease, including any period for which the lease has been extended.
"Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum
of the products of numbers of years from the date of determination to the dates
of each successive scheduled principal payment of the Indebtedness or redemption
or similar payment with respect to the Preferred Stock multiplied by the amount
of the payment by (2) the sum of all the payments.
99
"Board of Directors" means with respect to any Person, the board of
directors of the Person or any committee thereof duly authorized to act on
behalf of the board of directors.
"Business Day" means each day which is not a Legal Holiday (as defined in
the indenture).
"Capital Expenditures" means the amount of any expenditures in respect of
fixed or capital assets.
"Capital Lease Obligations" means an obligation that is required to be
classified and accounted for as a capital lease for financial reporting purposes
in accordance with GAAP, and the amount of Indebtedness represented by the
obligation shall be the capitalized amount of the obligation determined in
accordance with GAAP; and the Stated Maturity thereof shall be the date of the
last payment of rent or any other amount due under the lease prior to the first
date upon which the lease may be terminated by the lessee without payment of a
penalty.
"Capital Stock" of any Person means any and all shares, interests, rights
to purchase, warrants, options, participations or other equivalents of or
interests in (however designated) equity of the Person, including any Preferred
Stock, but excluding any debt securities convertible into the equity and any
warrants or options granted to directors, officers or employees of the Person in
the ordinary course of business and the issuance of equity upon the exercise
thereof.
"Change of Control" means the occurrence of any of the following events:
(1) any "person" (as such term is used in Sections 13(d) and 14(d) of
the Exchange Act), other than one or more Permitted Holders, is or becomes
the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the
Exchange Act, except that for purposes of this clause (1) the person shall
be deemed to have "beneficial ownership" of all shares that the person has
the right to acquire, whether the right is exercisable immediately or only
after the passage of time), directly or indirectly, of more than 35% of the
total voting power of the Voting Stock of Tri-Union; provided that the
Permitted Holders beneficially own (as defined in Rules 13d-3 and 13d-5
under the Exchange Act), directly or indirectly, in the aggregate a lesser
percentage of the total voting power of the Voting Stock of Tri-Union than
such other person and do not have the right or ability by voting power,
contract or otherwise to elect or designate for election a majority of its
Board of Directors (for the purposes of this clause (1), such other person
shall be deemed to beneficially own any Voting Stock of a specified
corporation held by a parent corporation, if such other person is the
beneficial owner (as defined in this clause (1)), directly, or indirectly,
of more than 35% of the voting power of the Voting Stock of the parent
corporation and the Permitted Holders beneficially own (as defined in this
provision), directly or indirectly, in the aggregate a lesser percentage of
the voting power of the Voting Stock of the parent corporation and do not
have the right or ability by voting power, contract or otherwise to elect
or designate for election a majority of the Board of Directors of the
parent corporation);
(2) during any period of two consecutive years from and after the
Closing Date, individuals who at the beginning of the period constituted
the Board of Directors of Tri-Union (together with any new directors whose
election by the Board of Directors or whose nomination for election by the
shareholders of Tri-Union was approved by a vote of a majority of the
directors of Tri-Union then still in office who were either directors at
the beginning of the period or whose election or nomination for election
was previously so approved) cease for any reason to constitute a majority
of the Board of Directors of Tri-Union then in office other than as a
result of the election of directors by the holders of the class B common
stock; or
(3) the merger or consolidation of Tri-Union with or into another
Person or the merger of another Person with or into Tri-Union, or the sale
of all or substantially all the assets of Tri-Union to another Person
(other than a Person that is controlled by the Permitted Holders), and, in
the case of any such merger or consolidation, the securities of Tri-Union
that are outstanding immediately prior to the transaction and which
represent 100% of the aggregate voting power of the Voting Stock of
Tri-Union are changed into or exchanged for cash, securities or property,
100
unless pursuant to the transaction the securities are changed into or
exchanged for, in addition to any other consideration, securities of the
surviving corporation that represent immediately after the transaction, at
least a majority of the aggregate voting power of the Voting Stock of the
surviving corporation.
"Closing Date" means the date on which the indenture is executed.
"Code" means the Internal Revenue Code of 1986, as amended.
"Collateral" means, collectively, all of the property and assets,
including, without limitation, Trust Moneys, that are from time to time subject
to, or purported to be subject to, the Lien of the indenture or any of the
Security Documents.
"Collateral Account" has the meaning given to the term under the heading
"-- Possession, Use and Release of Collateral -- Deposit, Use and Release of
Trust Moneys."
"Collateral Agent" means Wells Fargo Bank Minnesota, National Association.
"Consolidated Coverage Ratio" as of any date of determination means the
ratio of:
(1) the aggregate amount of EBITDA for the period of the most recent
four consecutive fiscal quarters for which financial statements are
available prior to the date of the determination to
(2) Consolidated Interest Expense for the four fiscal quarters;
provided that:
(a) if Tri-Union or any Restricted Subsidiary has Incurred any
Indebtedness since the beginning of the period that remains outstanding
or if the transaction giving rise to the need to calculate the
Consolidated Coverage Ratio is an Incurrence of Indebtedness, or both,
EBITDA and Consolidated Interest Expense for the period shall be
calculated after giving effect on a pro forma basis to the Indebtedness
as if the Indebtedness had been Incurred on the first day of the period
and the discharge of any other Indebtedness repaid, repurchased,
defeased or otherwise discharged with the proceeds of the new
Indebtedness as if the discharge had occurred on the first day of the
period
(b) if Tri-Union or any Restricted Subsidiary has repaid,
repurchased, defeased or otherwise discharged any Indebtedness since the
beginning of the period or if any Indebtedness is to be repaid,
repurchased, defeased or otherwise discharged on the date of the
transaction giving rise to the need to calculate the Consolidated
Coverage Ratio, EBITDA and Consolidated Interest Expense for the period
shall be calculated on a pro forma basis as if the discharge had
occurred on the first day of the period and as if Tri-Union or the
Restricted Subsidiary has not earned the interest income actually earned
during the period in respect of cash or Temporary Cash Investments used
to repay, repurchase, defease or otherwise discharge the Indebtedness;
(c) if since the beginning of the period Tri-Union or any
Restricted Subsidiary shall have made any Asset Disposition, other than
an Asset Disposition involving assets having a fair market value of less
than the greater of one percent (1%) of Adjusted Consolidated Net
Tangible Assets as of the end of Tri-Union's then most recently
completed fiscal year and $2,000,000, then EBITDA for the period shall
be reduced by an amount equal to EBITDA (if positive) or increased by an
amount equal to EBITDA (if negative), in each case, directly
attributable thereto for the period and Consolidated Interest Expense
for the period shall be reduced by an amount equal to the Consolidated
Interest Expense directly attributable to any Indebtedness of Tri-Union
or any Restricted Subsidiary repaid, repurchased, defeased or otherwise
discharged with respect to Tri-Union and the continuing Restricted
Subsidiaries in connection with the Asset Disposition for the period
(or, if the Capital Stock of any Restricted Subsidiary is sold, the
Consolidated Interest Expense for the period directly
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attributable to the Indebtedness of the Restricted Subsidiary to the
extent Tri-Union and the continuing Restricted Subsidiaries are no
longer liable for the Indebtedness after the sale);
(d) if since the beginning of the period Tri-Union or any
Restricted Subsidiary, by merger or otherwise, shall have made an
Investment in any Restricted Subsidiary, or any Person which becomes a
Restricted Subsidiary, or an acquisition, including by way of lease, of
assets, including any acquisition of assets occurring in connection with
a transaction requiring a calculation to be made hereunder, EBITDA and
Consolidated Interest Expense for the period shall be calculated after
giving pro forma effect thereto, including the Incurrence of any
Indebtedness, as if the Investment or acquisition occurred on the first
day of the period; and
(e) if since the beginning of the period any Person (that
subsequently became a Restricted Subsidiary or was merged with or into
Tri-Union or any Restricted Subsidiary since the beginning of the
period) shall have made any Asset Disposition, any Investment or
acquisition of assets that would have required an adjustment pursuant to
clause (c) or (d) above if made by Tri-Union or a Restricted Subsidiary
during the period, EBITDA and Consolidated Interest Expense for the
period shall be calculated after giving pro forma effect thereto as if
the Asset Disposition, Investment or acquisition occurred on the first
day of the period.
For purposes of this definition, whenever pro forma effect is to be given to an
acquisition or disposition of assets, the amount of income or earnings relating
thereto and the amount of Consolidated Interest Expense associated with any
Indebtedness Incurred or repaid in connection therewith, the pro forma
calculations shall be determined in good faith by a responsible financial or
accounting officer of Tri-Union. If any Indebtedness bears a floating rate of
interest and is being given pro forma effect, the interest of the Indebtedness
shall be calculated as if the rate in effect on the date of determination had
been the applicable rate for the entire period (taking into account any Interest
Rate Agreement applicable to the Indebtedness if the Interest Rate Agreement has
a remaining term in excess of 12 months).
"Consolidated Interest Expense" means, for any period, the total interest
expense of Tri-Union and the Restricted Subsidiaries for the period, determined
on a consolidated basis in accordance with GAAP, plus, to the extent not
included in the total interest expense, without duplication:
(1) interest expense attributable to capital leases and imputed
interest with respect to Attributable Debt;
(2) capitalized interest;
(3) non-cash interest expenses;
(4) commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing;
(5) net costs, including amortization of fees and upfront payments,
associated with interest rate caps and other interest rate and currency
options that, at the time entered into, resulted in Tri-Union and the
Restricted Subsidiaries being net payees as to future payouts under such
caps or options, and interest rate and currency swaps and forwards for
which Tri-Union or the Restricted Subsidiaries has paid a premium;
(6) Preferred Stock dividends in respect of all Preferred Stock held
by Persons other than Tri-Union or a Wholly Owned Subsidiary, to the extent
that, by the terms of the Preferred Stock, failure to pay the dividends
would result in a bankruptcy of the issuer thereof; and
(7) interest accruing on any Indebtedness of any other Person to the
extent the Indebtedness is guaranteed by Tri-Union or any Restricted
Subsidiary or secured by a Lien on assets of Tri-Union or any Restricted
Subsidiary to the extent the Indebtedness constitutes
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Indebtedness of Tri-Union or any Restricted Subsidiary (whether or not the
guarantee or Lien is called upon);
provided "Consolidated Interest Expense" shall not include any:
(a) amortization of costs relating to debt issuances (including the
amortization of debt discount) other than the amortization of debt discount
related to the issuance of securities with an original issue price of not
more than 90% of the principal thereof;
(b) amortization of debt discount to the extent it relates to
revaluations of financial instruments recognized in connection with the
consolidation; and
(c) noncash interest expense Incurred in connection with interest rate
caps and other interest rate and currency options that, at the time entered
into, resulted in Tri-Union and the Restricted Subsidiaries being either
neutral or net payors as to future payouts under the caps or options.
"Consolidated Net Income" means, for any period, the net income of
Tri-Union and the consolidated Subsidiaries; provided that there shall not be
included in the Consolidated Net Income any of the following (without
duplication):
(1) any net income of any Person, other than Tri-Union, if the Person
is not a Restricted Subsidiary, except that
(a) subject to the exclusion contained in clause (4) below,
Tri-Union's equity in the net income of the Person for the period shall
be included in the Consolidated Net Income up to the aggregate amount of
cash actually distributed by the Person during the period to Tri-Union
or a Restricted Subsidiary as a dividend or other distribution (subject,
in the case of a dividend or other distribution paid to a Restricted
Subsidiary, to the limitations contained in clause (3) below); and
(b) Tri-Union's equity in a net loss of the Person for the period
shall be included in determining the Consolidated Net Income;
(2) any net income or loss of any Restricted Subsidiary acquired by
Tri-Union or a consolidated Subsidiary in a pooling of interests
transaction for any period prior to the date of the acquisition;
(3) any net income of any Restricted Subsidiary if the Restricted
Subsidiary is subject to restrictions, directly or indirectly, on the
payment of dividends or the making of distributions by the Restricted
Subsidiary, directly or indirectly, to Tri-Union, except that
(a) subject to the exclusion contained in clause (4) below,
Tri-Union's equity in the net income of the Restricted Subsidiary for
the period shall be included in the Consolidated Net Income up to the
aggregate amount of cash actually distributed by the Restricted
Subsidiary during the period to Tri-Union or another Restricted
Subsidiary as a dividend or other distribution, subject, in the case of
a dividend or other distribution paid to another Restricted Subsidiary,
to the limitation contained in this clause) and
(b) Tri-Union's equity in a net loss of the Restricted Subsidiary
for the period shall be included in determining the Consolidated Net
Income;
(4) any gain or loss realized upon the sale or other disposition of
any assets of Tri-Union or its consolidated Restricted Subsidiaries,
including pursuant to any sale-and-leaseback arrangement, which is not sold
or otherwise disposed of in the ordinary course of business and any gain or
loss realized upon the sale or other disposition of any Capital Stock of
any Person;
(5) extraordinary gains or losses; and
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(6) the cumulative effect of a change in accounting principles.
"Consolidated Net Worth" means, with respect to any Person, the total of
the amounts shown on the balance sheet of the Person and its Restricted
Subsidiaries, determined on a consolidated basis in accordance with GAAP, as of
the end of the most recent fiscal quarter of the Person for which financial
statements are available, as:
(1) the par or stated value of all outstanding Capital Stock of the
Person; plus
(2) paid-in capital or capital surplus relating to the Capital Stock;
plus
(3) any retained earnings or earned surplus less
(a) any accumulated deficit; and
(b) any amounts attributable to Disqualified Stock.
"Default" means any event that is, or after notice or passage of time or
both would be, an Event of Default.
"Disqualified Stock" means, with respect to any Person, any Capital Stock
to the extent that by its terms (or by the terms of any security into which it
is convertible or for which it is exchangeable) or upon the happening of any
event, it:
(1) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise;
(2) is convertible or exchangeable for Indebtedness or Disqualified
Stock; or
(3) is redeemable, in whole or in part, at the option of the holder of
the Capital Stock;
in each case described in clause (3) and in the immediately preceding clauses
(1) and (2), on or prior to the Stated Maturity of the Notes;
provided that any Capital Stock that would not constitute Disqualified Stock but
for provisions thereof giving holders thereof the right to require the Person to
repurchase or redeem the stock upon the occurrence of an "asset sale" or "change
of control" occurring prior to the Stated Maturity of the Notes shall not
constitute Disqualified Stock if the "asset sale" or "change of control"
provisions applicable to the Capital Stock are not more favorable to the holders
of the Capital Stock than the provisions described under the heading "-- Certain
Covenants -- Limitation on Sales of Assets" and "-- Change of Control."
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"EBITDA" for any period means the sum of Consolidated Net Income for the
period, Consolidated Interest Expense for the period, and each of the following
(without duplication) to the extent deducted in calculating the Consolidated Net
Income for the period:
(1) provision for taxes based on income or profits;
(2) depletion and depreciation expense;
(3) amortization expense;
(4) exploration costs;
(5) reorganization costs; and
(6) all other non-cash charges (excluding any such non-cash charge to
the extent that it represents an accrual of or reserve for cash charges in
any future period or amortization of a
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prepaid cash expense that was paid in a prior period except the amounts as
Tri-Union determines in good faith are nonrecurring);
and less, to the extent included in calculating the Consolidated Net Income and
in excess of any costs or expenses attributable thereto and deducted in
calculating the Consolidated Net Income, the sum of
(1) the amount of deferred revenues that are amortized during the
period and are attributable to reserves that are subject to Volumetric
Production Payments; and
(2) amounts recorded in accordance with GAAP as repayments of
principal, premium, if any, and interest pursuant to Dollar-Denominated
Production Payments.
Notwithstanding the preceding, the provision for taxes based on the income or
profits of, and the depreciation and amortization and other non-cash charges of,
a Restricted Subsidiary shall be added to Consolidated Net Income to compute
EBITDA only to the extent, and in the same proportion, that the net income of
the Subsidiary was included in calculating Consolidated Net Income and only if a
corresponding amount would be permitted at the date of determination to be
dividended to Tri-Union by the Subsidiary without prior approval (that has not
been obtained) pursuant to the terms of its charter and all agreements,
instruments, judgments, decrees, orders, statutes, rules and governmental
regulations applicable to the Subsidiary or its stockholders. Solely for the
purpose of calculating EBITDA for determining Excess Cash Flow, EBITDA shall be
reduced by estimated cash income tax expense for any quarter or increased for
any cash income tax credits for any quarter to the extent not already reflected
in the calculation of EBITDA.
"Equity Offering" means a primary public offering of shares of Capital
Stock of Tri-Union.
"Event of Default" has the meaning given to the term under the heading
"-- Defaults."
"Excess Cash Flow" means for any fiscal quarter, EBITDA for Tri-Union and
the Restricted Subsidiaries for the quarter, minus each of the following:
(1) interest expense of Tri-Union and the Restricted Subsidiaries
determined in accordance with GAAP; and
(2) all Capital Expenditures made during the quarter by Tri-Union and
the Restricted Subsidiaries.
"Excess Proceeds" has the meaning given to the term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Excess Proceeds Offer" has the meaning given to the term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Excess Proceeds Payment" has the meaning given to the term under the
heading "-- Certain Covenants -- Limitation on Sales of Assets."
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"GAAP" means generally accepted accounting principles in the United States
as in effect from time to time, including those set forth in:
(1) the opinions and pronouncements of the Accounting Principles Board
of the American Institute of Certified Public Accountants;
(2) statements and pronouncements of the Financial Accounting
Standards Board;
(3) such other statements by such other entity as approved by a
significant segment of the accounting profession; and
105
(4) the rules and regulations of the SEC governing the inclusion of
financial statements, including pro forma financial statements, in periodic
reports required to be filed pursuant to Section 13 of the Exchange Act,
including opinions and pronouncements in staff accounting bulletins and
similar written statements from the accounting staff of the SEC.
"Guarantee" has the meaning given to the term in the section
"-- Guarantees."
"Guaranteed Obligations" has the meaning given to the term in the section
"-- Guarantees."
"Guaranty Agreement" means the Guaranty Agreement, dated as of the Closing
Date, by Tri-Union and the Subsidiary Guarantors party thereto in favor of the
trustee, the Approved Hedge Counterparties party to the Intercreditor Agreement,
the Hedge Liquidity Providers party to the Intercreditor Agreement and each
Holder, as the same may be amended, supplemented or modified from time to time
in accordance with the terms thereof and of the Intercreditor Agreement.
"Hedge Liquidity Agreements" has the meaning set forth in clause (2)(h)
under the heading "-- Certain Covenants -- Limitation on Indebtedness."
"Hedge Liquidity Providers" means the financial institutions party to Hedge
Liquidity Agreements.
"Hedge Period" means, as of the first business day of any month, the period
commencing on the date of determination pro forma to be entered into and ending
on the date which is two years after the date of determination.
"Hedged Revenue Ratio" means for Tri-Union and the Restricted Subsidiaries,
the ratio, calculated on a consolidated basis as of the first business day of
each month for the then current Hedge Period, of (1) Hedged Revenues for the
period to (2) Projected Consolidated Interest Expense for the period.
"Hedged Revenues" means, for Tri-Union and the Restricted Subsidiaries, the
amount, calculated on a consolidated basis as of the first business day of each
month for the then current Hedge Period, equal to:
(1) for all oil and gas hedging contracts with an Approved Hedge
Counterparty which are price swaps or fixed price purchase and sales
contracts, the sum of the products attained by multiplying the notional or
physical volume of crude oil or natural gas for each month during the Hedge
Period hedged therein and the fixed price for the month; plus
(2) for all oil and gas hedging contracts with an Approved Hedge
Counterparty which are price collars or price floors, the sum of the
products attained by multiplying the notional volume of crude oil or
natural gas for each month during the Hedge Period hedged therein and the
fixed price floor for the month; minus
(3) both
(a) the sum of each premium for any oil and gas hedging contract
for which a premium has been paid during the Hedge Period by Tri-Union
or any Restricted Subsidiary; and
(b) all amounts due under any oil and gas hedging contract for
which the counterparty thereunder is either in default or in respect of
which a termination event has occurred and is continuing.
"Hedging Obligations" of any Person means the obligations of the Person
pursuant to any oil and gas hedging contract or Interest Rate Agreement.
"Holder" means the Person in whose name a Note is registered on the
Registrar's books.
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"Immediate Family" means a Person's spouse, parents, children, siblings,
mother-in-law, father-in-law, brother-in-law, sister-in-law, son-in-law,
daughter-in-law and anyone who resides in the Person's home (other than a
domestic servant).
"Incur" means issue, assume, guarantee, incur or otherwise become liable
for, provided that any Indebtedness, Capital Stock or Lien of a Person existing
at the time the Person becomes a Subsidiary, whether by merger, consolidation,
acquisition or otherwise, shall be deemed to be Incurred by the Subsidiary at
the time it becomes a Subsidiary. The term "Incurrence" when used as a noun
shall have a correlative meaning. The accretion of principal of a non-interest
bearing or other discount security shall not be deemed the Incurrence of
Indebtedness.
"Indebtedness" means, with respect to any Person on any date of
determination (without duplication);
(1) the principal of and premium, if any, in respect of (a)
indebtedness of the Person for money borrowed and (b) indebtedness
evidenced by notes, debentures, bonds or other similar instruments for the
payment of which the Person is responsible or liable;
(2) all Capital Lease Obligations of the Person and all Attributable
Debt of the Person;
(3) all obligations of the Person issued or assumed as the deferred
purchase price of property (which purchase price is due more than six
months after the date of taking delivery of title to the property),
including all obligations of the Person for the deferred purchase price of
property under any title retention agreement (but excluding trade accounts
payable arising in the ordinary course of business);
(4) all obligations of the Person for the reimbursement of any obligor
on any letter of credit, banker's acceptance or similar credit transaction
(other than obligations with respect to letters of credit securing
obligations (other than obligations described in (1) through (3) above)
entered into in the ordinary course of business of the Person to the extent
the letters of credit are not drawn upon or, if and to the extent drawn
upon, the drawing is reimbursed no later than the tenth Business Day
following receipt by the Person of a demand for reimbursement following
payment on the letter of credit);
(5) the amount of all obligations of the Person with respect to the
redemption, repayment or other repurchase of any Disqualified Stock or,
with respect to any Subsidiary of the Person the liquidation preference
with respect to, any Preferred Stock (but excluding, in each case, any
accrued dividends);
(6) all obligations of the Person relating to any Production Payment
or in respect of production imbalances (but excluding production imbalances
arising in the ordinary course of business);
(7) all obligations of the type referred to in clauses (1) through (6)
of other Persons and all dividends of other Persons for the payment of
which, in either case, the Person is responsible or liable, directly or
indirectly, as obligor, guarantor or otherwise, including by means of any
guarantee (including, with respect to any Production Payment, any
warranties or guarantees of production or payment by the Person with
respect to the Production Payment but excluding other contractual
obligations of the Person with respect to the Production Payment);
(8) all obligations of the type referred to in clauses (1) through (7)
of other Persons secured by any Lien on any property or asset of the
first-mentioned Person (whether or not the obligation is assumed by the
first-mentioned Person), the amount of the obligation being deemed to be
the lesser of the value of the property or assets or the amount of the
obligation so secured; and
(9) to the extent not otherwise included in this definition, Hedging
Obligations of the Person.
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The "amount" or "principal amount" of Indebtedness at any time of
determination as used herein represented by:
(1) any Capital Lease Obligation shall be the amount determined in
accordance with the definition thereof;
(2) all other unconditional obligations shall be the amount of the
liability thereof determined in accordance with GAAP; and
(3) all other contingent obligations shall be the maximum liability at
such date of such Person.
None of the following shall constitute Indebtedness:
(1) indebtedness arising from agreements providing for indemnification
or adjustment of purchase price or from guarantees securing any obligations
of Tri-Union or any of its Subsidiaries pursuant to the agreements,
incurred or assumed in connection with the disposition of any business,
assets or Subsidiary of Tri-Union, other than guarantees or similar credit
support by Tri-Union or any of its Subsidiaries of Indebtedness incurred by
any Person acquiring all or any portion of the business, assets or
Subsidiary for the purpose of financing the acquisition;
(2) any trade payables and other accrued current liabilities incurred
in the ordinary course of business (including as the deferred purchase
price of property);
(3) obligations arising from guarantees to suppliers, lessors,
licensees, contractors, franchisees or customers incurred in the ordinary
course of business;
(4) obligations (other than express guarantees of indebtedness for
borrowed money) in respect of Indebtedness of other Persons arising in
connection with (a) the sale or discount of accounts receivable, (b) trade
acceptances and (c) endorsements of instruments for deposit in the ordinary
course of business;
(5) obligations in respect of performance bonds provided by Tri-Union
or its Subsidiaries in the ordinary course of business and refinancings
thereof;
(6) obligations arising from the honoring by a bank or other financial
institution of a check, draft or similar instrument drawn against
insufficient funds in the ordinary course of business, provided that the
obligation is extinguished within two business days of its incurrence; and
(7) obligations in respect of any obligations under workers'
compensation laws and similar legislation.
"Independent Director" means a director who has no relationship to
Tri-Union or a Restricted Subsidiary or other Affiliate that could reasonably be
expected to interfere with the exercise of his or her independence from
management and the company on whose board the director sits. In addition, the
following persons may not serve as Independent Directors:
(1) Persons employed by Tri-Union or any of the Restricted
Subsidiaries or other Affiliates of the foregoing during the current year
or any of the three past years;
(2) Persons who during the current year are or any of the past three
years were partners, controlling shareholders or executive officers of an
organization that has a business relationship or who have direct business
relationships with Tri-Union or any of the Restricted Subsidiaries or other
Affiliates of the foregoing;
(3) a Person who is employed as an executive officer of another entity
where any of Tri-Union's or a Restricted Subsidiaries' or other Affiliates'
executive officers serve on that entity's compensation committee; and
108
(4) Persons who are Immediate Family of an individual who is, or has
been, during the current year or any of the past three years, employed by
Tri-Union or any Restricted Subsidiary or other Affiliate as an executive
officer of such.
"Intercreditor Agreement" means the Intercreditor and Collateral Agency
Agreement among Tri-Union and the Subsidiary Guarantors party thereto, the
Approved Hedge Counterparties or Hedge Liquidity Providers party thereto, the
Collateral Agent and the trustee, dated as of the Closing Date, as the same may
be amended, supplemented or modified from time to time in accordance with its
terms.
"Interest Rate Agreement" means any interest rate swap agreement, interest
rate cap agreement or other financial agreement or arrangement designed to
protect a Person and its Subsidiaries against fluctuations in interest rates.
"Investment" in any Person means any direct or indirect advance, loan
(other than advances to customers or joint interest partners or drilling
partnerships sponsored by Tri-Union or any Restricted Subsidiary in the ordinary
course of business that are recorded as accounts receivable on the balance sheet
of the lender) or other extensions of credit (including by way of guarantee or
similar arrangement) or capital contribution to (by means of any transfer of
cash or other property to others or any payment for property or services for the
account or use of others), or any purchase, short sale or acquisition of Capital
Stock, Indebtedness or other similar instruments issued by the Person. For
purposes of the definition of "Unrestricted Subsidiary," the definition of
"Restricted Payment" and the covenant described under the heading "-- Certain
Covenants -- Limitation on Restricted Payments":
(1) "Investment" shall include the portion (proportionate to
Tri-Union's equity interest in the Subsidiary) of the fair market value of
the net assets of any Subsidiary of Tri-Union at the time that the
Subsidiary is designated an Unrestricted Subsidiary; provided that upon a
redesignation of the Subsidiary as a Restricted Subsidiary, Tri-Union shall
be deemed to continue to have a permanent "Investment" in an Unrestricted
Subsidiary equal to an amount (if positive) equal to Tri-Union's
"Investment" in the Subsidiary at the time of the redesignation less the
portion (proportionate to Tri-Union's equity interest in the Subsidiary) of
the fair market value of the net assets of the Subsidiary at the time of
the redesignation; and
(2) any property transferred to or from an Unrestricted Subsidiary
shall be valued at its fair market value at the time of the transfer, in
each case as determined in good faith by the Board of Directors of
Tri-Union.
"Lien" means any mortgage, pledge, security interest, encumbrance, lien or
charge of any kind, including any conditional sale or other title retention
agreement or lease in the nature thereof.
"Major Asset Sale" has the meaning given to the term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Major Asset Sale Offer" has the meaning given to the term under the
heading "-- Certain Covenants -- Limitation on Sales of Assets."
"Make-Up Period" has the meaning ascribed to the term in clause (3) of the
covenant "-- Hedging Obligations."
"Material Change" means an increase or decrease (excluding changes that
result solely from changes in prices) of more than 10% during a fiscal quarter
in the discounted future net revenues from proved oil and gas reserves of
Tri-Union and the Restricted Subsidiaries, calculated in
109
accordance with clause (1)(a) of the definition of Adjusted Consolidated Net
Tangible Assets; provided that the following will be excluded from the
calculation of Material Change:
(1) any acquisitions during the fiscal quarter of oil and gas reserves
that have been estimated by independent petroleum engineers and with
respect to which a report or reports of the engineers exist; and
(2) any disposition of properties existing at the beginning of the
fiscal quarter that have been disposed of in compliance with the covenant
described under the heading "-- Certain Covenants -- Limitation on Sales of
Assets."
"MMBtu" means one million British thermal units.
"Mortgage" means mortgage, deed of trust, assignment of production,
security agreement, fixture filing and financing statement granted by Tri-Union
or any Subsidiary Guarantor to the Collateral Agent for the benefit of the
Approved Hedge Counterparties or Hedge Liquidity Providers, as applicable,
trustee and the Holders and pursuant to which one or more Liens on oil and gas
assets or interests therein are created, as the same may be amended,
supplemented or modified from time to time in accordance with the terms thereof
and of the Intercreditor Agreement.
"Net Available Cash" from an Asset Disposition means cash payments received
therefrom (including any cash payments received by way of deferred payment of
principal pursuant to a note or installment receivable or otherwise, but only as
and when received, but excluding any other consideration received in the form of
assumption by the acquiring Person of Indebtedness or other obligations relating
to the properties or assets or received in any other noncash form) in each case
net of:
(1) all legal, title and recording tax expenses, commissions and other
fees (including financial and other advisory fees) and expenses incurred,
and all federal, state, provincial, foreign and local taxes required to be
accrued as a liability under GAAP, as a consequence of the Asset
Disposition;
(2) all payments made on any Indebtedness (including termination
payments made on Approved Hedge Agreements on account of settlement
amounts, unpaid amounts, interest and other amounts due thereunder, but
excluding Subordinated Obligations) which is secured by a senior Lien on
any assets subject to the Asset Disposition, in accordance with the terms
of any Lien upon or other security agreement of any kind with respect to
the assets, or which must by its terms, or in order to obtain a necessary
consent to the Asset Disposition, or by applicable law, be repaid out of
the proceeds from the Asset Disposition;
(3) all distributions and other payments required to be made to
minority interest holders in Subsidiaries or joint ventures as a result of
the Asset Disposition; and
(4) the deduction of appropriate amounts provided by the seller as a
reserve, in accordance with GAAP, against any liabilities associated with
the property or other assets disposed in the Asset Disposition and retained
by Tri-Union or any Restricted Subsidiary after the Asset Disposition.
"Net Cash Proceeds" means, with respect to any Equity Offering, the cash
proceeds of the issuance or sale net of attorneys' fees, accountants' fees,
underwriters' or placement agents' fees, discounts or commissions and brokerage,
consultant and other fees actually incurred in connection with the issuance or
sale and net of taxes paid or payable as a result thereof.
"Net Working Capital" means all current assets of Tri-Union and its
Restricted Subsidiaries minus all current liabilities of Tri-Union and its
Restricted Subsidiaries, except current liabilities included in Indebtedness,
determined in accordance with GAAP.
"New Notes" has the meaning given to the term under the heading
"-- General."
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"Non-Recourse Indebtedness" with respect to any Person means Indebtedness
of the Person for which:
(1) the sole legal recourse for collection of principal, premium, if
any, and interest on the Indebtedness is against the specific property
identified in the instruments evidencing or securing the Indebtedness and
the property was acquired with the proceeds of the Indebtedness or the
Indebtedness was incurred within 90 days after the acquisition of the
property; and
(2) no other assets of the Person may be realized upon in collection
of principal or interest on the Indebtedness;
provided that any such Indebtedness shall not cease to be "Non-Recourse
Indebtedness" solely as a result of the instrument governing the Indebtedness
containing terms pursuant to which the Indebtedness becomes recourse upon
(1) fraud or misrepresentation by the Person in connection with the
Indebtedness;
(2) the Person failing to pay taxes or other charges that result in
the creation of liens on any portion of the specific property securing the
Indebtedness or failing to maintain any insurance on the property required
under the instruments securing the Indebtedness;
(3) the conversion of any of the collateral for the Indebtedness;
(4) the Person failing to maintain any of the collateral for the
Indebtedness in the condition required under the instruments securing the
Indebtedness;
(5) any income generated by the specific property securing the
Indebtedness being applied in a manner not otherwise allowed in the
instruments securing the Indebtedness;
(6) the violation of any applicable law or ordinance governing
hazardous materials or substances or otherwise affecting the environmental
condition of the specific property securing the Indebtedness; or
(7) the rights of the holder of the Indebtedness to the specific
property becoming impaired, suspended or reduced by any act, omission or
misrepresentation of the Person; provided, further that upon the occurrence
of any of the foregoing clauses (1) through (7) above, any such
Indebtedness which shall have ceased to be "Non-Recourse Indebtedness"
shall be deemed to have been Indebtedness incurred by the Person at such
time.
"Notes" has the meaning given to the term under the heading "-- General."
"Obligations" means all obligations for principal, premium, interest,
penalties, fees, indemnifications, reimbursements, damages and other liabilities
payable under the indenture and other documentation governing the Notes.
"Old Notes" has the meaning given to the term under the heading
"-- General."
"Payment Restrictions" has the meaning given to the term under the heading
"-- Certain Covenants -- Limitation on Dividend and Other Payment Restrictions
Affecting Restricted Subsidiaries."
"Permitted Business Investment" means any Investment or expenditure made in
the ordinary course of, and of a nature that is or shall have become customary
in, the oil and gas business as a means of actively exploiting, exploring for,
acquiring, developing, producing, processing, gathering, marketing or
transporting oil and gas through agreements, transactions, interests or
arrangements which permit one to share risks or costs, comply with regulatory
requirements regarding local ownership or satisfy other objectives customarily
achieved through the conduct of oil and gas business jointly with third parties,
including:
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(1) ownership interests in oil and gas properties, processing
facilities, gathering systems or ancillary real property interests; and
(2) Investments in the form of or pursuant to operating agreements,
processing agreements, farm-in agreements, farm-out agreements, development
agreements, area of mutual interest agreements, unitization agreements,
pooling agreements, joint bidding agreements, service contracts, joint
venture agreements, partnership agreements (whether general or limited),
subscription agreements, stock purchase agreements and other similar
agreements with third parties.
"Permitted Holders" means:
(1) Richard Bowman;
(2) any Affiliates of Richard Bowman or Tri-Union;
(3) Richard Bowman's heirs, estate and any trust or family limited
partnership (or similar estate planning vehicle) in which Mr. Bowman and/or
his Immediate Family members own, directly or indirectly, at least a
majority of the outstanding beneficial interests; and
(4) Jefferies & Company, Inc. and its Affiliates.
"Permitted Investment" means an Investment by Tri-Union or any Restricted
Subsidiary in:
(1) a Restricted Subsidiary or a Person that will, upon the making of
the Investment, become a Restricted Subsidiary; provided that the primary
business of the Restricted Subsidiary is an oil and gas business;
(2) another Person if as a result of the Investment the other Person
is merged or consolidated with or into, or transfers or conveys all or
substantially all its assets to, Tri-Union or a Restricted Subsidiary;
provided that the Person's primary business is an oil and gas business;
(3) Temporary Cash Investments;
(4) receivables owing to Tri-Union or any Restricted Subsidiary if
created or acquired in the ordinary course of business and payable or
dischargeable in accordance with customary trade terms; provided that the
trade terms may include the concessionary trade terms as Tri-Union or any
such Restricted Subsidiary deems reasonable under the circumstances;
(5) payroll, travel and similar advances to cover matters that are
expected at the time of the advances ultimately to be treated as expenses
for accounting purposes and that are made in the ordinary course of
business;
(6) loans or advances to employees made in the ordinary course of
business;
(7) stock, obligations or securities received in settlement of debts
created in the ordinary course of business and owing to Tri-Union or any
Restricted Subsidiary or in satisfaction of judgments;
(8) any Person to the extent the Investment represents the non-cash
portion of the consideration received for an Asset Disposition as permitted
pursuant to the covenant described under the heading "-- Certain Covenants
-- Limitation on Sales of Assets"; and
(9) Permitted Business Investments.
"Permitted Joint Venture" means any Person engaged in the oil and gas
business in which Tri-Union or a Restricted Subsidiary makes a Permitted
Business Investment and which cannot, by the terms of the Person's constituent
documents, Incur or guarantee Indebtedness.
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"Permitted Liens" means, with respect to any Person:
(1) pledges or deposits by the Person under workers' compensation
laws, unemployment insurance laws or similar legislation, or good faith
deposits in connection with bids, tenders, contracts (other than for the
payment of Indebtedness) or leases to which the Person is a party, or
deposits to secure public, statutory or regulatory obligations of the
Person or deposits of cash or United States government bonds to secure
surety or appeal bonds to which the Person is a party, or deposits as
security for contested taxes or import duties or for the payment of rent,
in each case Incurred in the ordinary course of business;
(2) Liens imposed by law, such as carriers', warehousemen's and
mechanics' Liens, in each case for sums not yet due or being contested in
good faith by appropriate proceedings;
(3) Liens for property taxes not yet subject to penalties for
non-payment or which are being contested in good faith and by appropriate
proceedings;
(4) minor survey exceptions, minor encumbrances, easements or
reservations of, or rights of others for, licenses, rights of way, sewers,
electric lines, telegraph and telephone lines and other similar purposes,
or zoning or other restrictions as to the use of real property or Liens
incidental to the conduct of the business of the Person or to the ownership
of its properties which were not Incurred in connection with Indebtedness
and which do not in the aggregate materially impair their use in the
operation of the business of the Person;
(5) Liens securing Indebtedness Incurred under clause (2)(f) of the
covenant described under the heading "-- Certain Covenants -- Limitation on
Indebtedness"; provided that the Lien may not extend to any other property
owned by the Person or any of its Subsidiaries at the time the Lien is
Incurred, and the Indebtedness secured by the Lien may not be Incurred more
than 365 days after the later of the acquisition, completion of
construction, repair, improvement, addition or commencement of full
operation of the property subject to the Lien;
(6) Liens existing on the Closing Date;
(7) Liens securing Indebtedness or other obligations of a Subsidiary
of the Person owing to the Person or a wholly owned Subsidiary of the
Person (or, in the case of Tri-Union, a Wholly Owned Subsidiary);
(8) Liens securing Hedging Obligations pursuant to any Interest Rate
Agreement so long as the Hedging Obligations relate to Indebtedness that
is, and is permitted to be Incurred under the indenture, secured by a Lien
on the same property, other than Collateral, securing the Hedging
Obligations;
(9) Liens securing Hedging Obligations under the Approved Hedge
Agreements required to be maintained by Tri-Union under the covenant
described under the heading "-- Certain Covenants -- Hedging Obligations"
or securing obligations to Hedge Liquidity Providers under Hedge Liquidity
Agreements;
(10) Liens on accounts receivable, related general intangibles and
related proceeds of Tri-Union and its Restricted Subsidiaries to secure up
to $20,000,000 of Indebtedness under the Working Capital Revolver;
(11) Liens arising in the ordinary course of business in favor of the
United States, any state of the United States, any foreign country or any
department, agency, instrumentality or political subdivision of any such
jurisdiction, to secure partial, progress, advance or other payments
pursuant to any contract or statute;
(12) Liens on pipeline or pipeline facilities which arise out of
operation of law;
(13) Liens reserved in oil and gas mineral leases for bonus or rental
payments and for compliance with the terms of the leases;
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(14) Liens arising under partnership agreements, oil and gas leases,
farm-out agreements, division orders, contracts for the sale, purchase,
exchange, transportation or processing (but not the refining) of oil, gas
or other hydrocarbons, unitization and pooling declarations and agreements,
development agreements, operating agreements, area of mutual interest
agreements and other similar agreements which are customary in the oil and
gas business;
(15) Liens arising out of judgments or awards against the Person with
respect to which the Person shall then be proceeding with an appeal or
other proceedings for review; and
(16) Liens arising pursuant to the indenture or any Security Document
or otherwise securing the Obligations or the Subsidiary Guarantees.
"Person" means any individual, corporation, partnership, limited liability
company, joint venture, association, joint-stock company, trust, unincorporated
organization, government or any agency or political subdivision thereof or any
other entity.
"Plan" means Tri-Union's First Amended Plan of Reorganization dated May 9,
2001, pursuant to Chapter 11 of the United States Bankruptcy Code.
"Preferred Stock," as applied to the Capital Stock of any Person, means
Capital Stock of any class or classes, however designated, which is preferred as
to the payment of dividends or as to the distribution of assets upon any
voluntary or involuntary liquidation or dissolution of the Person over shares of
Capital Stock of any other class of the Person.
"Principal" of a Note means the stated principal of the Note plus the
premium, if any, payable on the Note which is due or overdue or is to become due
at the relevant time.
"Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
"Projected Consolidated Interest Expense" means, for Tri-Union and the
Restricted Subsidiaries, the amount, calculated on a consolidated basis as of
the first business day of each month for the then current Hedge Period, equal to
the pro forma Consolidated Interest Expense of Tri-Union and the Restricted
Subsidiaries for the Hedge Period, calculated based upon the following
assumptions:
(1) all obligations giving rise to any amount characterized as
interest in the definition of Consolidated Interest Expense will be
outstanding for the entire balance of the Hedge Period, except that all
scheduled amortization of the obligations will be paid when due;
(2) if any such obligation bears interest at a floating rate, interest
expense shall be calculated as if the rate in effect on the date of
determination will be in effect for the entire Hedge Period (taking into
account any Interest Rate Agreements in respect of the obligations); and
(3) balances of Indebtedness used to calculate interest expense shall
be increased or decreased, as the case may be, to the extent that asset
acquisitions or dispositions result in additions to or reductions in
interest expense of Tri-Union and the Restricted Subsidiaries.
"Projected Proved Developed Producing Production" means, as of any date of
determination, for Tri-Union and the Restricted Subsidiaries, the volumes of
hydrocarbons (either crude oil or natural gas or crude oil and natural gas, on
an Mcfe basis, as applicable) that are projected to be produced from the
Persons' proved developed producing oil and natural gas properties during the
then current Hedge Period, in each case as reflected as of the most recently
delivered Reserve Report and after giving effect to any acquisition, sale,
exchange or other disposition of any such Person's oil and gas assets.
"PV-10 Value" means with respect to any oil and gas assets of Tri-Union and
the Restricted Subsidiaries the aggregate net present value of the oil and gas
assets calculated before income
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taxes and discounted at 10 percent in accordance with SEC guidelines (including
using pricing provisions based on the most recent year-end prices), as reported
in the most recently prepared or audited report of Tri-Union's independent
petroleum engineers.
"Refinance" means, in respect of any Indebtedness, to refinance, extend,
renew, refund, repay, prepay, redeem, defease or retire, or to issue other
Indebtedness in exchange or replacement for, the Indebtedness (including an
Incurrence pursuant to the covenant described under the heading "-- Certain
Covenants -- Merger and Consolidation"). "Refinanced" and "Refinancing" shall
have correlative meanings.
"Refinancing Indebtedness" means Indebtedness that Refinances any
Indebtedness of Tri-Union or any Restricted Subsidiary existing on the Closing
Date or Incurred in compliance with the indenture, including Indebtedness that
Refinances Refinancing Indebtedness and Indebtedness that is deemed to be
Incurred at the time of a merger or consolidation pursuant to the covenant
described under the heading "-- Certain Covenants -- Merger and Consolidation,"
provided that:
(1) the Refinancing Indebtedness has a Stated Maturity no earlier than
the Stated Maturity of the Indebtedness being Refinanced;
(2) the Refinancing Indebtedness has an Average Life at the time the
Refinancing Indebtedness is Incurred that is equal to or greater than the
Average Life of the Indebtedness being Refinanced; and
(3) the Refinancing Indebtedness has an aggregate principal amount (or
if Incurred with original issue discount, an aggregate issue price) that is
equal to or less than the aggregate principal amount (or if Incurred with
original issue discount, the aggregate accreted value) then outstanding or
committed (plus fees and expenses, including any premium and defeasance
costs) under the Indebtedness being Refinanced; provided further that
Refinancing Indebtedness shall not include:
(a) Indebtedness of a Subsidiary (other than a Subsidiary
Guarantor) that Refinances Indebtedness of Tri-Union or another
Subsidiary; or
(b) Indebtedness of Tri-Union or a Restricted Subsidiary that
Refinances Indebtedness of an Unrestricted Subsidiary.
"Replacement Assets" has the meaning given to the term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Reserve Report" means the most recently delivered annual report of one or
more independent petroleum engineers of recognized national standing delivered
by Tri-Union pursuant to the covenant "-- Reserve Reports."
"Restricted Payment" with respect to any Person means:
(1) the declaration or payment of any dividends or any other
distributions of any sort in respect of its Capital Stock (including any
payment in connection with any merger or consolidation involving the
Person) or similar payment to the direct or indirect holders of its Capital
Stock (other than:
(a) dividends or distributions payable solely in its Capital Stock
(other than Disqualified Stock), (y) dividends or distributions payable
solely to Tri-Union or a Restricted Subsidiary; and
(b) pro rata dividends or other distributions made by a Subsidiary
that is not a Wholly Owned Subsidiary to minority stockholders (or
owners of an equivalent interest in the case of a Subsidiary that is an
entity other than a corporation));
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(2) the purchase, redemption or other acquisition or retirement for
value of any Capital Stock of Tri-Union held by any Person or of any
Capital Stock of a Restricted Subsidiary held by any Affiliate of Tri-Union
(other than a Restricted Subsidiary), including the exercise of any option
to exchange any Capital Stock (other than into Capital Stock of Tri-Union
that is not Disqualified Stock);
(3) the purchase, repurchase, redemption, defeasance or other
acquisition or retirement for value, prior to scheduled maturity, scheduled
repayment or scheduled sinking fund payment of any Subordinated
Obligations; or
(4) the making of any Investment in any Person (other than a Permitted
Investment).
"Restricted Subsidiary" means any Subsidiary of Tri-Union that is not an
Unrestricted Subsidiary.
"SEC" means the Securities and Exchange Commission.
"Securities Act" means the Securities Act of 1933, as amended.
"Security Documents" means, collectively, the Intercreditor Agreement, the
Mortgages, and all security agreements, mortgages, deeds of trust, collateral
assignments or other instruments evidencing or creating any Lien in favor of the
Collateral Agent in all or any portion of the Collateral, in each case as
amended, supplemented or modified from time to time in accordance with their
terms and the terms of the indenture.
"Stated Maturity" means, with respect to any security, the date specified
in the security as the fixed date on which the final payment of principal of the
security is due and payable, including pursuant to any mandatory redemption
provision (but excluding any provision providing for the repurchase of the
security at the option of the holder of the security upon the happening of any
contingency unless the contingency has occurred).
"Subordinated Obligations" means any Indebtedness or Preferred Stock of
Tri-Union, or any Subsidiary Guarantor (whether outstanding on the Closing Date
or thereafter Incurred) which is subordinate or junior in right of payment to
the Notes, or any Subsidiary Guarantee pursuant to a written agreement to the
effect.
"Subsidiary" means, with respect to any Person, any corporation,
association, partnership or other business entity of which more than 50% of the
total voting power of shares of Capital Stock or other interests (including
partnership interests) entitled (without regard to the occurrence of any
contingency) to vote in the election of directors, managers or trustees thereof
is at the time owned or controlled, directly or indirectly, by:
(1) the Person;
(2) the Person and one or more Subsidiaries of the Person; or
(3) one or more Subsidiaries of the Person. Unless otherwise
indicated, references to Subsidiaries in this Description of the Senior
Secured Notes refer to Subsidiaries of Tri-Union.
"Subsidiary Guarantor" means each Subsidiary that is or becomes a
Subsidiary Guarantor of the Notes in compliance with the provisions of the
indenture.
"Successor Company" has the meaning given to the term under the heading
"-- Certain Covenants -- Merger and Consolidation."
"Synthetic Leases" means in respect of any Person, all leases which shall
have been, or should have been, in accordance with GAAP, treated as operating
leases on the financial statements of the Person liable (whether contingently or
otherwise) for the payment of rent thereunder and which were properly treated as
indebtedness for borrowed money for purposes of United States federal income
taxes, if the lessee in respect thereof is obligated to either purchase for an
amount in excess of, or
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pay upon early termination an amount in excess of, 80% of the residual value of
the property subject to the operating lease upon expiration or early termination
of the lease.
"Tack-On Senior Secured Notes" means additional Notes not to exceed
$20,000,000 in aggregate principal amount issued by Tri-Union after the Closing
Date in accordance with clause (1) of the covenant described under the heading
"-- Certain Covenants -- Limitation on Indebtedness."
"Temporary Cash Investments" means any of the following:
(1) any investment in direct obligations of the United States or any
agency of the United States or obligations guaranteed by the United States
or any agency of the United States having maturities not more than 180 days
from the date of acquisition;
(2) investments in time deposit accounts, certificates of deposit and
money market deposits maturing within 180 days of the date of acquisition
thereof issued by a bank or trust company which is organized under the laws
of the United States, any state of the United States or any foreign country
recognized by the United States, and which bank or trust company has
capital, surplus and undivided profits aggregating in excess of $50,000,000
(or the foreign currency equivalent thereof) and has outstanding debt which
is rated "A" (or such similar equivalent rating) or higher by at least one
nationally recognized statistical rating organization (as used in the
Securities Act and the Exchange Act and the rules promulgated thereunder)
or any money-market fund sponsored by a registered broker dealer or mutual
fund distributor;
(3) repurchase obligations with a term of not more than 30 days for
underlying securities of the types described in clause (1) above entered
into with a bank meeting the qualifications described in clause (2) above;
(4) investments in commercial paper, maturing not more than 180 days
after the date of acquisition, issued by a Person (other than an Affiliate
of Tri-Union) organized and in existence under the laws of the United
States or any foreign country recognized by the United States with a rating
at the time as of which any investment therein is made of "P-2" (or higher)
according to Moody's Investors Service, Inc. or "A-2" (or higher) according
to Standard & Poor's Ratings Services; and
(5) investments in securities with maturities of six months or less
from the date of acquisition issued or fully guaranteed by any state,
commonwealth or territory of the United States, or by any political
subdivision or taxing authority of the United States, and rated at least
"A" by Standard & Poor's Ratings Services or "A" by Moody's Investors
Service, Inc.
"Trust Moneys" means all cash or Temporary Cash Investments received by the
trustee:
(1) upon the release of Collateral from the Lien of the indenture and
the Security Documents, including investment earnings thereon;
(2) pursuant to the provisions of any Mortgage;
(3) as proceeds of any Asset Disposition or other sale or other
disposition of all or any part of the Collateral by or on behalf of the
trustee or any collection, recovery, receipt, appropriation or other
realization of or from all or any part of the Collateral pursuant to the
indenture or any of the Security Documents or otherwise; or
(4) for application under the indenture as provided for in the
indenture or the Security Documents, or whose disposition is not elsewhere
specifically provided for in the indenture or in the Security Documents;
provided that Trust Moneys shall not include any property deposited with
the trustee pursuant to any Change of Control offer, Excess Proceeds Offer
or redemption or defeasance of any Notes.
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"United States Government Obligations" means direct obligations (or
certificates representing an ownership interest in the obligations) of the
United States, including any agency or instrumentality of the United States, for
the payment of which the full faith and credit of the United States is pledged
and which are not callable at the issuer's option.
"Unrestricted Subsidiary" means:
(1) any Subsidiary of Tri-Union that at the time of determination
shall be designated an Unrestricted Subsidiary by the Board of Directors of
Tri-Union in the manner provided below; and
(2) any Subsidiary of an Unrestricted Subsidiary. The Board of
Directors of Tri-Union may designate any Subsidiary of Tri-Union, including
any newly acquired or newly formed Subsidiary, to be an Unrestricted
Subsidiary unless the Subsidiary or any of its Subsidiaries owns any
Capital Stock or Indebtedness of, or holds any Lien on any property of,
Tri-Union or any other Subsidiary of Tri-Union that is not a Subsidiary of
the Subsidiary to be so designated. The Board of Directors of Tri-Union may
designate any Unrestricted Subsidiary to be a Restricted Subsidiary;
provided that immediately after giving effect to the designation:
(a) Tri-Union could Incur $1.00 of additional Indebtedness under
paragraph (1) of the covenant described under the heading "-- Certain
Covenants -- Limitation on Indebtedness"; and
(b) no Default (including no Default under the covenant described
under the heading "-- Certain Covenants -- Limitation on Restricted
Payments") shall have occurred and be continuing or would result from
the action.
For the avoidance of doubt, on the date any Restricted Subsidiary is
redesignated to be an Unrestricted Subsidiary, the redesignation shall be deemed
to be an Investment in an Unrestricted Subsidiary in an amount equal to the fair
market value of the assets of that Unrestricted Subsidiary. Any such designation
by the Board of Directors of Tri-Union shall be evidenced by Tri-Union to the
trustee by promptly filing with the trustee a copy of the board resolution
giving effect to the designation and an officers' certificate certifying that
the designation complied with the preceding provisions.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" of a Person means all classes of Capital Stock of the Person
then outstanding and normally entitled (without regard to the occurrence of any
contingency) to vote in the election of directors, managers or trustees thereof.
"Wholly Owned Subsidiary" means a Restricted Subsidiary all the Capital
Stock of which, other than directors' qualifying shares and shares held by other
Persons to the extent the shares are required by applicable law to be held by a
Person other than Tri-Union or a Restricted Subsidiary, is owned by Tri-Union or
one or more Wholly Owned Subsidiaries.
"Working Capital Revolver" means with respect to Tri-Union or any
Restricted Subsidiary, one or more debt facilities or commercial paper
facilities with banks or other institutional lenders providing for revolving
working capital loans.
PLAN OF DISTRIBUTION
Each broker-dealer that receives new notes for its own account must
acknowledge that it will deliver a prospectus in connection with any resale of
such new notes. This prospectus, as it may be amended or supplemented from time
to time, may be used by a broker-dealer in connection with resales of new notes
received in exchange for old notes where such old notes were acquired as a
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result of market-making activities or other trading activities. We have agreed,
for a period of 180 days after consummation of the exchange offer, to make
available a prospectus meeting the requirements of the Securities Act to any
broker-dealer for use in connection with any resale of any publicly registered
note acquired in the exchange offer. In addition, until , 2001 (90
days after the date of this prospectus), all dealers effecting transactions in
the new notes may be required to deliver a prospectus.
We will not receive any proceeds from any sales of new notes by
broker-dealers. New notes received by broker-dealers for their own account
pursuant to the exchange offer may be sold from time to time in one or more
transactions in the over-the-counter market, in negotiated transactions, through
the writing of options on the new notes or a combination of such methods of
resale, at market prices prevailing at the time of resale, at prices related to
such prevailing market prices or negotiated prices. Any such resale may be made
directly to purchasers or to or through brokers or dealers who may receive
compensation in the form of concessions from any such broker-dealer or the
purchasers of any such new notes. Any broker-dealer that resells new notes that
were received by it for its own account pursuant to the exchange offer and any
broker-dealer that participates in a distribution of such new notes may be
deemed to be an "underwriter" within the meaning of the Securities Act and any
profit on any such resale of new notes and any commissions or concessions
received by any such persons may be deemed to be underwriting compensation under
the Securities Act. The letter of transmittal states that, by acknowledging that
it will deliver and by delivering a prospectus, a broker-dealer will not be
deemed to admit that it is an "underwriter" within the meaning of the Securities
Act.
We will furnish copies of the prospectus included in this registration
statement, including any preliminary prospectus, and any amendment or supplement
thereto, as any broker-dealer may reasonably request. We have agreed to pay all
expenses incident to the exchange offer other than commissions or concessions of
any brokers or dealers and will indemnify the holders of the old notes
(including any broker-dealers) against certain liabilities, including
liabilities under the Securities Act.
REGISTRATION RIGHTS
Pursuant to a registration rights agreement, we agreed to file with the SEC
a registration statement on the appropriate form under the Securities Act with
respect to an offer to exchange the old notes for publicly registered new notes
with substantially identical terms. Upon the effectiveness of the registration
statement, we will offer to the holders of old notes who are able to make
certain representations the opportunity to exchange their old notes for publicly
registered notes. Such offer shall remain open for not less than 30 days (or
longer if required by applicable law) after the date notice of the exchange
offer is mailed to holders of the old notes. For each old note surrendered to us
under the exchange offer, the holder will receive a publicly registered note of
equal principal amount. Interest on each publicly registered note will accrue
from the last interest payment date on which interest was paid on the old notes
so surrendered or, if no interest has been paid on such notes, from the date of
original issuance of the old notes.
If we effect the exchange offer, we will be entitled to close the exchange
offer 30 days after the commencement thereof, provided, however, that we have
accepted all old notes previously and validly surrendered in accordance with the
terms of the exchange offer. Old notes not tendered in the exchange offer,
together with any publicly registered new notes will be treated as a single
class of securities under the indenture. However, any old notes not tendered in
the exchange offer will remain subject to the transfer restrictions originally
placed on the old notes.
If (i) we are not permitted to file the exchange offer registration
statement or to consummate the exchange offer because the exchange offer is not
permitted by applicable law or SEC policy or (ii) any holder of old notes
notifies us within the specified time period that (A) due to a change in law or
policy it is not entitled to participate in the exchange offer, (B) due to a
change in law or policy it
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may not resell the publicly registered notes acquired by it in the exchange
offer to the public without delivering a prospectus and the prospectus contained
in the exchange offer registration statement is not appropriate or available for
such resales by holders or (C) it is a broker-dealer and owns old notes acquired
directly from us or an affiliate of us, we will file with the SEC a shelf
registration statement to cover resales of any transfer restricted notes (as
described below) by the holders thereof, and we will use our best efforts to
cause the applicable registration statement to be declared effective within
specified periods by the SEC. For purposes of the foregoing, "transfer
restricted notes" means each old note until (i) the date on which such note has
been exchanged by a person other than a broker-dealer for a publicly registered
note in the exchange offer, (ii) following the exchange by a broker-dealer in
the exchange offer of an old note for a publicly registered note, the date on
which such publicly registered note is sold to a purchaser who receives from
such broker-dealer on or prior to the date of such sale a copy of the prospectus
contained in the exchange offer registration statement, (iii) the date on which
such old note has been effectively registered under the Securities Act and
disposed of in accordance with the shelf registration statement or (iv) the date
on which such old note may be distributed to the public pursuant to Rule 144(k)
under the Securities Act.
Under existing SEC interpretations, any transfer restricted notes would, in
general, be freely transferable by the holders (other than our affiliates) after
the exchange offer without further registration under the Securities Act;
provided, however, that in the case of broker-dealers participating in the
exchange offer, a prospectus meeting the requirements of the Securities Act will
be delivered upon resale by such broker-dealer in connection with resales of the
publicly registered notes. We have agreed, for a period of 180 days after
consummation of the exchange offer, to make available a prospectus meeting the
requirements of the Securities Act to any such broker-dealer for use in
connection with any resale of any publicly registered note acquired in the
exchange offer. A broker-dealer which delivers such a prospectus to purchasers
in connection with such resales will be subject to certain of the civil
liability provisions under the Securities Act and will be bound by the
provisions of the registration rights agreement (including certain
indemnification rights and obligations).
Each holder of the old notes who wishes to exchange such notes for publicly
traded notes in the exchange offer will be required to make certain
representations, including representations that (i) any publicly traded notes to
be received by it will be acquired in the ordinary course of its business, (ii)
it is not participating in, and it has no arrangement with any person to
participate in the distribution (within the meaning of the Securities Act) of
the publicly traded notes, (iii) it is not an "affiliate" of us, as defined in
Rule 405 of the Securities Act, and (iv) it is not a broker-dealer tendering
notes acquired directly from us for its own account. If the holder is a
broker-dealer that will receive publicly traded notes for its own account in
exchange for old notes that were acquired as a result of market-making
activities or other trading activities, it will be required to acknowledge that
it will deliver a prospectus in connection with any resale of such publicly
traded notes.
The registration rights agreement provides that: (i) unless the exchange
offer would not be permitted by applicable law or SEC policy, we will file an
exchange offer registration statement with the SEC on or prior to 60 days after
the date of original issuance of the old notes, (ii) unless the exchange offer
would not be permitted by applicable law or SEC policy, we will use our best
efforts to have the exchange offer registration statement declared effective by
the SEC on or prior to 120 days after the date of original issuance of the old
notes, (iii) unless the exchange offer would not be permitted by applicable law
or SEC policy, we will commence the exchange offer and use our best efforts to
issue, on or prior to 60 days after the date on which the exchange offer
registration statement was declared effective by the SEC, publicly registered
notes, in exchange for all old notes tendered prior thereto in the exchange
offer and (iv) if obligated to file the shelf registration statement, we will
file on or prior to the earlier of (x) 180 days after the date of original
issuance of the old notes or (y) 30 days after such filing obligation arises and
use our best efforts to cause the shelf registration statement to be declared
effective by the SEC on or prior to 90 days after such
120
obligation arises; provided that if we have not consummated the exchange offer
within 180 days of the date of original issuance of the old notes, then we will
file the shelf registration statement with the SEC on or prior to the 181st day
after the date of original issuance of the old notes and use our best efforts to
cause the shelf registration statement to be declared effective within 60 days
after such filing. We will be required to use our best efforts to keep such
shelf registration statement continuously effective, supplemented and amended
until the second anniversary of the date of original issuance of the old notes
or such shorter period that will terminate when all the transfer restricted
notes covered by the shelf registration statement have been sold pursuant
thereto.
We will, in the event that a shelf registration statement is filed with
respect to the old notes, provide each holder with copies of the prospectus that
is a part of the shelf registration statement, notify each such holder when the
shelf registration statement for the old notes has become effective and take
certain other actions as are required to permit unrestricted resales of the old
notes. A holder that sells pursuant to the shelf registration statement will be
required to be named as a selling security holder in the related prospectus and
to deliver a prospectus to purchasers, will be subject to certain of the civil
liability provisions under the Securities Act in connection with such sales and
will be bound by the provisions of the registration rights agreement that are
applicable to such a holder (including certain indemnification rights and
obligations).
If (i) we fail to file any of the registration statements required by the
registration rights agreement on or before the date specified for such filing,
(ii) any of such registration statements is not declared effective by the SEC or
prior to the date specified for such effectiveness, (iii) we fail to consummate
the exchange offer within 60 days of the date specified for effectiveness with
respect to the exchange offer registration statement, or (iv) the shelf
registration statement with respect to the old notes or the exchange offer
registration statement is declared effective but thereafter, subject to certain
exceptions, ceases to be effective or usable in connection with the exchange
offer or resales of transfer restricted notes, as the case may be, during the
periods specified in the registration rights agreement, then the interest rate
on transfer restricted notes will increase, with respect to the first 90-day
period immediately following the occurrence of any default referred to in
clauses (i) through (iv) above by 0.50% per annum and will increase by an
additional 0.50% per annum with respect to each subsequent 90-day period until
all such defaults have been cured, up to a maximum amount of 2% per annum with
respect to all such defaults. Following the cure of all such defaults, the
accrual of all such additional interest will cease and the interest rate will
revert to the original rate.
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following is a general discussion of the material U.S. federal income
tax considerations to holders of the old notes and new notes. This discussion is
based upon the Internal Revenue Code of 1986, as amended (the "Code"), Treasury
Regulations, Internal Revenue Service ("IRS") rulings, and judicial decisions
now in effect, all of which are subject to change (possibly with retroactive
effect) or different interpretations. This discussion does not purport to deal
with all aspects of federal income taxation that may be relevant to a particular
investor's decision to purchase or exchange notes, and it is not intended to be
wholly applicable to all categories of investors, some of which, such as dealers
in securities, banks, insurance companies, tax-exempt organizations, regulated
investment companies, persons holding notes as a hedge against currency risks or
as a position in a straddle for tax purposes, or persons whose functional
currency is not the United States dollar, may be subject to special rules. In
addition, this discussion is limited to persons that will hold the notes as a
capital asset (generally, property held for investment). Further, the old notes
were sold only to United States persons that are qualified institutional buyers
and, therefore, the comments are addressed primarily to such persons as holders.
Finally, this summary does not describe any tax considerations arising under the
U.S. estate tax, the U.S. alternative minimum tax, or the laws of any applicable
foreign, state, or local jurisdiction.
121
YOU ARE URGED TO CONSULT YOUR OWN TAX ADVISORS AS TO THE PARTICULAR TAX
CONSEQUENCES OF THE EXCHANGE OF OLD NOTES FOR NEW NOTES AND THE PURCHASE,
OWNERSHIP AND DISPOSITION OF THE NOTES, INCLUDING THE APPLICABILITY OF ANY
FEDERAL TAX LAW OR ANY STATE, LOCAL OR FOREIGN TAX LAWS, AND ANY CHANGES (OR
PROPOSED CHANGES) IN APPLICABLE TAX LAWS OR INTERPRETATIONS THEREOF.
NOTES
Stated Interest and Original Issue Discount. The notes were issued with,
and the new notes will be deemed to have, original issue discount ("OID") for
U.S. federal income tax purposes. OID is the excess of the stated redemption
price at maturity of a note over its issue price.
The stated redemption price at maturity of a note is the sum of all
payments provided by the instrument, whether denominated as interest or
principal, required to be made on the note other than payments of qualified
stated interest. Qualified stated interest is interest that is unconditionally
payable at least annually at a single fixed rate of interest. Interest is
payable on the notes on June 1 and December 1 of each year, beginning December
1, 2001, at a rate of 12.5%. The stated interest payments on the notes will
constitute qualified stated interest and will not be included in a note's stated
redemption price at maturity. You will be required to include stated interest in
your income at the time it accrues or is received, depending on whether you use
the cash or accrual method of accounting.
Each note will be treated by the IRS as having been issued as part of an
investment unit consisting of the note and the associated class A common stock.
The issue price of a unit is the first price at which a substantial amount of
the units was sold to the public, ignoring sales to underwriters or placement
agents. We allocated the issue price of a unit between the note and the
associated class A common stock on the basis of their relative fair market
values. The units were sold to the public for $945. Each unit was comprised of a
note having an issue price of $888.00 and a share of class A common stock with
an ascribed value of $57.00. You may make a different allocation, provided that
you explicitly disclose to the IRS that your allocation is different from the
one made by us. Disclosure must be made on a form prescribed by the IRS and must
be attached to your timely filed federal income tax return for the taxable year
that includes the acquisition date of the unit. In all other instances, the
allocation to be made by us will be binding on us and all holders. The
allocation is not binding on the IRS, however, and it is possible that the IRS
will assert that a different allocation is appropriate. If such an assertion
were made successfully, the amount of OID associated with the notes would be
increased or decreased accordingly.
All notes that you acquire will be treated as a single debt instrument for
purposes of applying the OID rules. You will be required to include OID in gross
income as ordinary income as it accrues under a constant yield method before you
receive cash payments attributable to such income, regardless of your regular
method of accounting.
The amount of OID includable in your income will equal the sum of the daily
portions of OID for each day during the taxable year when you held a note. The
daily portion is determined by allocating the OID for an accrual period equally
to each day in that accrual period. The accrual period for a note may be of any
length up to one year, so long as each scheduled payment of principal or
interest occurs either on the first or final day of an accrual period, and may
vary in length over the term of a note. The amount of OID for an accrual period
is generally equal to the product of the note's adjusted issue price at the
beginning of such accrual period and its yield to maturity, determined on the
basis of a compounding assumption that reflects the length of the accrual
period, less the amount of any qualified stated interest allocable to the
accrual period. The adjusted issue price of a note at the beginning of any
accrual period equals the issue price of the note increased by the amount of all
previously accrued OID and reduced by the amount of all prior cash payments on
the note, other than qualified stated interest payments. The yield to maturity
of a
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note is the interest rate that, when used in computing the present value of all
payments to be made on a note, produces an amount equal to the issue price of
the note. Under these rules, you generally will have to include in income
increasingly greater amounts of OID in successive accrual periods.
Acquisition Premium. If you purchase a note for an amount greater than its
adjusted issue price as of the purchase date but less than or equal to its
stated redemption price at maturity, you will have purchased the note at an
"acquisition premium." You will reduce the amount of OID that you must include
in your gross income for a taxable year by the amount of acquisition premium
properly allocable to that year.
Bond Premium. If you purchase a note for an amount greater than its stated
redemption price at maturity, the note has "bond premium." You may elect to
amortize bond premium over the remaining term of the note or, if it results in a
smaller amount of amortizable bond premium, until an earlier call date.
If you elect to amortize bond premium, you will reduce the amount of
interest that you must include in income. The reduction will equal the portion
of premium allocable to the period ending on an interest payment date or at the
stated maturity, as the case may be, as computed based on the note's yield to
maturity. If an election to amortize bond premium is not made, you must include
the full amount of each interest payment in income in accordance with your
regular method of accounting. In that case, you will receive a tax benefit from
the premium only in computing your gain or loss on the sale or other disposition
or payment of the principal amount of a note.
If you elect to amortize bond premium, that election will apply to all
notes and other debt instruments that you hold during the first taxable year to
which the election applies or that you subsequently acquire. You may revoke the
election only with the consent of the IRS.
Market Discount. If you purchase a note, other than at original issue, for
an amount that is less than its revised issue price, the amount of the
difference will be "market discount," unless the difference is de minimis. You
will be required to treat any gain realized on a partial principal payment or on
the sale or other disposition of a note purchased with market discount as
ordinary income, not capital gain, to the extent of the accrued market discount
that you have not previously included in income. In addition, you may be
required to defer, until the maturity date of the note or its earlier
disposition in a taxable transaction, the deduction of a portion of the interest
expense on any debt incurred or continued to purchase or carry the note.
Any market discount will accrue on a straight line basis from the date when
acquired to the maturity date, unless you elect to accrue market discount on a
constant interest method. You may elect to include market discount in income
currently as it accrues under either the straight line or constant interest
method. If you make this election, it will apply to all market discount
obligations acquired during or after the first taxable year to which the
election applies. You may revoke this election only with IRS consent. If you
make the election, you would not be required to defer interest deductions on
debt incurred or maintained to purchase or carry the note.
Election to Treat All Interest as OID. You may elect, subject to certain
limitations, to include all interest that accrues on a note in gross income on a
constant yield basis. For purposes of this election, interest includes stated
interest, OID, market discount, de minimis market discount and unstated
interest, as adjusted by any amortizable bond premium or acquisition premium.
If you make this election, the issue price of a note will equal your basis
in the note immediately after you acquire it. The issue date of a note will be
the date when you acquire the note. This election generally will apply only to
the note for which it is made. The election may be revoked only with IRS
consent.
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If you make this election for a note on which there is market discount, you
will be treated as having made the election to include market discount in income
currently over the life of all debt instruments you hold or subsequently
acquire. See "Market Discount."
Sale, Exchange, and Retirement of Notes. You generally will recognize gain
or loss upon the sale, exchange, repurchase, redemption, retirement or other
disposition of a note measured by the difference (if any) between the amount of
cash and the fair market value of any property you receive and your adjusted tax
basis in that note. To the extent that the cash or other property is
attributable to the payment of accrued interest not previously included in
income, that amount will be taxable as ordinary income. Your adjusted tax basis
in a note will equal the cost of the note to you (not including the portion of
the purchase price that is allocated to the class A common stock) plus any
amounts included in income as OID and less any payments received by you, other
than stated interest, and any premium amortized by you. Any gain or loss
recognized on the sale, exchange, repurchase, redemption, retirement or other
disposition of a note should be capital gain or loss, except to the extent of
market discount, and will be long-term capital gain or loss if the note has been
held by you for more than one year. If you are a noncorporate holder, any
long-term capital gain you recognize may be taxable at reduced rates. Your
ability to deduct capital losses may be limited.
THE EXCHANGE OFFER
The exchange of old notes for new notes under the exchange offer should not
constitute a significant modification of the terms of the notes and should have
no U.S. federal income tax consequences to you. You will continue to be required
to include qualified stated interest payments and OID in your gross income on
the notes received in the exchange in the same manner as when you held the notes
given up in the exchange.
If there is a default in connection with the exchange offer, liquidated
damages will be paid to you through an increased interest rate on the notes.
Because there is only a remote possibility that the liquidated damages will
become payable, we believe that the liquidated damages will not be treated as
OID. Instead, any liquidated damages should be taken into account by you as
ordinary income only to the extent and at such time that such amounts become
fixed or are actually paid, in accordance with your method of accounting for
U.S. federal income tax purposes.
INFORMATION REPORTING AND BACKUP WITHHOLDING
We are required to provide the IRS and holders of record other than
corporations and other exempt holders with information returns each year stating
the amount of OID that accrued on the notes during the calendar year.
In general, information reporting requirements may apply to principal and
interest payments on a note and to payments of the proceeds of a sale of a note.
In addition, a backup withholding tax may apply to such payments at the
applicable rate, which is 31% now and will be 30.5% for payments made after
August 6, 2001. The backup withholding tax may apply unless you (i) are a
corporation or come within certain other exempt categories and, when required,
demonstrate your exemption, or (ii) provide a correct taxpayer identification
number, certify as to no loss of exemption from backup withholding, and
otherwise comply with applicable requirements of the backup withholding rules.
If you do not provide us with your correct taxpayer identification number, you
may be subject to penalties imposed by the IRS.
Any amounts withheld under the backup withholding rules will be allowed as
a credit against your U.S. federal income tax liability if the required
information is furnished to the IRS.
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LEGAL MATTERS
The validity of the new notes offered pursuant to this prospectus will be
passed upon for us by Thompson & Knight LLP, Houston, Texas.
CHANGE IN ACCOUNTANTS
On March 14, 2001, we terminated Hidalgo, Banfill, Zlotnik & Kermali, P.C.
("Hidalgo") as our independent auditors and engaged BDO Seidman, LLP ("BDO") as
our new auditors. Prior to such engagement, we had not consulted with BDO on
issues relating to our accounting principles or the type of audit opinion to be
issued with respect to our financial statements. Hidalgo's reports for the years
ended December 31, 1998 and 1999 contained a "going concern" qualification due
to our default under our bank loan resulting from the commodity price decreases
experienced during the latter half of 1998 and our subsequent bankruptcy.
Hidalgo's reports for such periods did not contain any adverse opinion or
disclaimer of opinion, nor were they qualified (other than as described above),
or modified as to uncertainty, audit scope or accounting principles. There was
no disagreement between us and Hidalgo during any period of their engagement
through the date of their dismissal on any matter of accounting principles or
practices, financial statement disclosure or auditing scope or procedures which,
if not resolved to the satisfaction of Hidalgo, would have caused them to make
reference to the matter in their reports.
EXPERTS
The financial statements included in this prospectus and in the
Registration Statement have been audited by BDO Seidman, LLP and by Hidalgo,
Banfill, Zlotnik & Kermali, P.C., independent certified public accountants, to
the extent and for the periods set forth in the respective reports of such firms
contained herein and in the Registration Statement. All such financial
statements have been included in reliance upon such reports given upon the
authority of such firms as experts in auditing and accounting.
RESERVE ENGINEERS
Information in this prospectus and in our attached financial statements
relating to our estimated proved reserves of oil and natural gas and the related
estimates of future net revenues and present values thereof as of December 31,
1998, 1999 and 2000, have been prepared by Huddleston & Co., Inc., independent
petroleum engineers.
AVAILABLE INFORMATION
We are not subject to the informational requirements of the Securities
Exchange Act of 1934, as amended. Under the terms of the indenture governing the
old notes and the new notes, we have agreed to provide to the holders of these
notes with annual reports and the information, documents and other reports
otherwise required pursuant to Section 13 of the Exchange Act. While any notes
remain outstanding, we will make available, upon request, to any holder and any
prospective purchaser of notes, the information required pursuant to Rule
144A(d)(4) under the Securities Act of 1933, as amended, during any period in
which we are not subject to Section 13 or 15(d) of the Exchange Act. Any such
request should be directed to the Secretary of Tri-Union at 530 Lovett
Boulevard, Houston, Texas 77006; (713) 533-4000.
This prospectus is part of a registration statement on Form S-4 filed by us
with the Securities and Exchange Commission under the Securities Act. This
prospectus omits certain information contained in the registration statement.
Reference is hereby made to the registration statement and to the exhibits to
the registration statement for further information about us and the securities
offered by this prospectus. Statements contained in this prospectus concerning
the provisions of instruments, contracts or other documents are not necessarily
complete, and each such statement is
125
qualified in its entirety by reference to the copy of the applicable instrument,
contract or other document filed with the SEC. The registration statement, its
exhibits and any other documents that we file with the SEC may be read and
copied at the public reference facilities maintained by the SEC at 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549, and at the following
regional offices of the SEC: 7 World Trade Center, Suite 1300, New York, New
York 10048 and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. You
can call the SEC at 1-800-SEC-0330 for more information about the public
reference rooms. In addition, the SEC maintains a site on the Internet that
contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC. The SEC's Internet
address is http://www.sec.gov.
126
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and natural gas industry that are used in this prospectus. All volumes
of natural gas referred to herein are stated at the legal pressure base to the
state or area where the reserves exit and at 60 degrees Fahrenheit and in most
instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume of oil,
condensate or natural gas liquids.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent, determined using
the ratio of six Mcf of natural gas to one Bbl of oil condensate or natural gas
liquids.
Behind pipe. Oil and natural gas in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of oil and natural gas from another formation penetrated by the well
bore.
Boe. Barrel of oil equivalent, determined using the ratio of one Bbl of
crude oil, condensate or natural gas liquids to six Mcf of natural gas.
Completion. The installation of permanent equipment for the production of
oil and natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Development. The drilling and bringing into production of wells in
addition to the exploratory or discovery well on a lease.
Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry hole or well. A well found to be incapable of producing oil or natural
gas in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
Exploration. The search for oil and natural gas. Exploration operations
include: aerial surveys, geophysical surveys, geological studies, core testing,
and the drilling of test wells (wildcat wells).
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which working interests are owned.
Horizontal drilling. A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of oil and natural gas.
MBbls. One thousand barrels of oil.
MBoe. One thousand barrels of oil equivalent, determined using the ratio
of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.
Mcf. One thousand cubic feet of natural gas.
Mcfd. One thousand cubic feet of natural gas per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
127
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of natural gas equivalent, determined using
the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.
MMS. The Minerals Management Service.
Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange.
Oil. Crude oil, condensate and natural gas liquids.
Present value and PV-10 Value. When used with respect to oil and natural
gas reserves, represents the estimated future net revenue to be generated from
the production of proved reserves, determined in all material respects in
accordance with the rules and regulations of the SEC (generally using prices and
costs in effect as of the date indicated) without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
future income tax expenses or to depreciation, depletion and amortization,
discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing oil or
natural gas in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production.
Proved developed reserves. Proved reserves that are expected to be
recovered from existing wellbores, whether or not currently producing, without
drilling additional wells. Production of such reserves may require a
recompletion.
Proved reserves. The estimated quantities of crude oil, natural gas, and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage.
Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has been previously completed.
Reserve life. A ratio determined by dividing proved reserves by production
from such reserves for the prior 12-month period.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reserves.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
Standardized Measure. The estimated future net revenue, including the
effects of estimated future income tax expense, to be generated from the
production of proved reserves, determined in all material respects in accordance
with the rules and regulations of the SEC (generally using prices and costs in
effect as of the date indicated) without giving effect to non-property related
expenses
128
such as general and administrative expenses and debt service or to depreciation,
depletion and amortization, discounted using an annual discount rate of 10%.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Wellbore. The hole made by the drill bit.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
Workover. Operations on a producing well to restore or increase
production.
129
INDEX TO FINANCIAL STATEMENTS
<Table>
<Caption>
PAGE
----
TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM
CORPORATION) CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Certified Public Accountants........ F-2
Report of Independent Certified Public Accountants........ F-3
Consolidated Balance Sheets as of December 31, 1999 and
2000 (audited) and June 30, 2001 (unaudited)........... F-4
Consolidated Statements of Operations and Comprehensive
Income (Loss) for the Years Ended December 31, 1998,
1999 and 2000 (audited) and for the Six Months Ended
June 30, 2000 and 2001 (unaudited)..................... F-5
Consolidated Statements of Stockholders' Equity (Capital
Deficit) for the Years Ended December 31, 1998, 1999
and 2000 (audited) and for the Six Months Ended June
30, 2000 and 2001 (unaudited).......................... F-6
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1999 and 2000 (audited) and for the
Six Months Ended June 30, 2000 and 2001
(unaudited)............................................ F-7
Notes to Consolidated Financial Statements................ F-8
</Table>
F-1
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Stockholder and Board of Directors
Tri-Union Development Corporation (formerly Tribo Petroleum Corporation)
Houston, Texas
We have audited the accompanying consolidated balance sheet of Tri-Union
Development Corporation (formerly Tribo Petroleum Corporation) and subsidiaries
as of December 31, 2000, and the related consolidated statements of operations
and comprehensive income (loss), stockholder's equity (capital deficit) and cash
flows for the year ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Tri-Union
Development Corporation and subsidiaries at December 31, 2000, and the results
of their operations and their cash flows for the year ended December 31, 2000 in
conformity with accounting principles generally accepted in the United States of
America.
BDO SEIDMAN, LLP
Houston, Texas
March 21, 2001, except for
Notes 13 and 14 which is
as of July 30, 2001
F-2
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Director and Stockholder
Tri-Union Development Corporation (formerly Tribo Petroleum Corporation)
Houston, Texas
We have audited the accompanying consolidated balance sheet of Tri-Union
Development Corporation (formerly Tribo Petroleum Corporation) and subsidiaries
as of December 31, 1999, and the related consolidated statements of operations
and comprehensive income (loss), stockholder's equity (capital deficit) and cash
flows for the years ended December 31, 1998 and 1999. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Tri-Union
Development Corporation and subsidiaries as of December 31, 1999, and the
results of their operations and their cash flows for the years ended December
31, 1998 and 1999, in conformity with generally accepted accounting principles.
As discussed in Note 11 to the consolidated financial statements, the
Company restated the valuation allowance to eliminate deferred tax assets.
HIDALGO, BANFILL, ZLOTNIK &
KERMALI, P.C.
Houston, Texas
April 22, 2000, except as to Note 11,
which is as of March 23, 2001, and
Notes 13 and 14 which is as of
July 30, 2001
F-3
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
AT DECEMBER 31,
--------------------------- AT JUNE 30,
1999 2000 2001
------------ ------------ ------------
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents................................. $ 2,813,996 $ 32,989,939 $ 12,964,750
Restricted cash........................................... -- -- 13,566,895
Accounts receivable net of allowance for doubtful accounts
of $867,864, $351,505 and $336,668...................... 9,157,640 24,281,409 22,257,363
Marketable securities..................................... 235,000 472,248 214,728
Prepaid and other......................................... 926,286 1,777,763 1,499,245
Derivative contracts...................................... -- -- 1,649,326
------------ ------------ ------------
Total current assets............................... 13,132,922 59,521,359 52,152,307
------------ ------------ ------------
Oil and natural gas properties -- full cost method, net..... 89,640,441 87,132,723 80,046,064
Other assets
Restricted cash and bonds................................. 4,181,507 4,674,645 5,095,251
Furniture, fixtures and equipment, net.................... 256,515 175,521 438,375
Receivables from affiliates, net.......................... 1,192,937 989,866 --
Deferred loan costs, net.................................. 498,499 99,700 19,284,697
Derivative contracts...................................... -- -- 1,937,300
------------ ------------ ------------
Total other assets................................. 6,129,458 5,939,732 26,755,263
------------ ------------ ------------
$108,902,821 $152,593,814 $158,953,994
============ ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY (CAPITAL DEFICIT)
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued liabilities................ $ 23,411,646 $ 26,609,284 $ 28,228,755
Accounts payable subject to renegotiation............... -- -- 10,119,904
Accrued interest........................................ 4,784,286 7,224,477 586,806
Notes payable........................................... 358,427 333,880 82,643
Current maturities of senior secured notes.............. -- -- 20,000,000
Notes payable -- in default............................. 104,700,000 -- --
------------ ------------ ------------
133,254,359 34,167,641 59,018,108
------------ ------------ ------------
Pre-petition liabilities subject to compromise:
Note payable -- in default................................ -- 104,323,500 --
Accrued interest.......................................... -- 6,226,808 --
Accounts payable and accrued liabilities -- unsecured..... -- 38,015,232 --
------------ ------------ ------------
Total pre-petition liabilities subject to
compromise....................................... -- 148,565,540 --
------------ ------------ ------------
Senior secured notes........................................ -- -- 85,512,472
------------ ------------ ------------
Commitments and contingencies (Notes 1, 3, 8, 9, 12 and 14)
Stockholders' equity (capital deficit):
Class A common stock, $0.01 par value, 445,000 shares
authorized; 238,333, 238,333 and 368,333 shares issued
and outstanding......................................... 2,383 2,383 3,683
Class B common stock, $0.01 par value, 65,000 shares
authorized; none, none, and 65,000 shares issued and
outstanding............................................. -- -- 650
Additional paid in capital................................ -- -- 25,380,183
Deficit................................................... (24,355,724) (30,141,750) (10,961,102)
Accumulated other comprehensive income.................... 1,803 -- --
------------ ------------ ------------
Total stockholders' equity (capital deficit)....... (24,351,538) (30,139,367) 14,423,414
------------ ------------ ------------
$108,902,821 $152,593,814 $158,953,994
============ ============ ============
</Table>
See accompanying notes to consolidated financial statements.
F-4
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
<Table>
<Caption>
YEARS ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
---------------------------------------- -------------------------
1998 1999 2000 2000 2001
------------ ----------- ----------- ----------- -----------
(UNAUDITED)
Revenues and other:
Oil and natural gas
revenues.................... $ 25,836,896 $36,270,343 $73,452,054 $26,187,263 $54,666,487
Gain (loss) on marketable
securities.................. (27,414) -- 995,180 902,696 (417,180)
Gain on derivative
contracts................... -- -- -- -- 3,586,626
Other......................... 542,644 1,495,393 28,404 419,306 896,922
------------ ----------- ----------- ----------- -----------
Total revenues and
other................ 26,352,126 37,765,736 74,475,638 27,509,265 58,732,855
------------ ----------- ----------- ----------- -----------
Expenses:
Lease operating expense....... 17,450,088 15,542,277 19,485,359 6,804,142 10,480,429
Workover expense.............. 599,690 2,410,410 6,649,074 1,696,898 3,340,129
Production taxes.............. 638,955 704,855 1,968,342 712,441 1,341,576
Depreciation, depletion and
amortization................ 12,397,800 11,040,035 13,506,477 5,394,322 7,262,043
General and administrative.... 3,326,747 5,236,733 4,328,358 2,446,873 3,149,231
Interest expense (contractual
interest during 2000 of
$13,100,000)................ 7,733,931 11,981,460 12,757,863 6,733,250 6,276,250
------------ ----------- ----------- ----------- -----------
Total expenses......... 42,147,211 46,915,770 58,695,473 23,787,926 31,849,658
------------ ----------- ----------- ----------- -----------
Income (loss) before
reorganization costs and
income taxes.................. (15,795,085) (9,150,034) 15,780,165 3,721,339 26,883,197
Reorganization costs............ -- -- 21,487,191 914,809 7,311,108
------------ ----------- ----------- ----------- -----------
Income (loss) before income
taxes......................... (15,795,085) (9,150,034) (5,707,026) 2,806,530 19,572,089
Provisions for income taxes..... -- -- 79,000 -- 391,441
------------ ----------- ----------- ----------- -----------
Net income (loss)............... (15,795,085) (9,150,034) (5,786,026) 2,806,530 19,180,648
Other comprehensive income
(loss):
Unrealized gains (losses) on
available-for-sale
securities.................. 97 1,803 (1,803) (1,803) --
------------ ----------- ----------- ----------- -----------
Comprehensive income (loss)..... $(15,794,988) $(9,148,231) $(5,787,829) $ 2,804,727 $19,180,648
============ =========== =========== =========== ===========
Net income (loss) per share --
basic and diluted............. $ (66.27) $ (38.39) $ (24.28) $ 11.77 $ 76.01
============ =========== =========== =========== ===========
Weighted average shares
outstanding................... 238,333 238,333 238,333 238,333 252,339
============ =========== =========== =========== ===========
</Table>
See accompanying notes to consolidated financial statements.
F-5
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
<Table>
<Caption>
CLASS A CLASS B ACCUMULATED
COMMON STOCK COMMON STOCK ADDITIONAL RETAINED OTHER
---------------- --------------- PAID IN EARNINGS COMPREHENSIVE
SHARES AMOUNT SHARES AMOUNT CAPITAL (DEFICIT) INCOME (LOSS) TOTAL
------- ------ ------ ------ ----------- ------------ ------------- ------------
FOR THE YEARS ENDED DECEMBER 31,
1998, 1999 AND 2000:
Balance, January 1, 1998......... 238,333 $2,383 -- $ -- $ -- $ 589,395 $ (97) $ 591,681
Net loss....................... -- -- -- -- -- (15,795,085) -- (15,795,085)
Change in unrealized gains on
available-for-sale
securities................... -- -- -- -- -- -- 97 97
------- ------ ------ ---- ----------- ------------ ------- ------------
Balance, December 31, 1998....... 238,333 2,383 -- -- -- (15,205,690) -- (15,203,307)
Net loss....................... -- -- -- -- -- (9,150,034) -- (9,150,034)
Change in unrealized gains on
available-for-sale
securities................... -- -- -- -- -- -- 1,803 1,803
------- ------ ------ ---- ----------- ------------ ------- ------------
Balance, December 31, 1999....... 238,333 2,383 -- -- -- (24,355,724) 1,803 (24,351,538)
Net loss....................... -- -- -- -- -- (5,786,026) -- (5,786,026)
Change in unrealized gains on
available-for-sale
securities................... -- -- -- -- -- -- (1,803) (1,803)
------- ------ ------ ---- ----------- ------------ ------- ------------
Balance, December 31, 2000....... 238,333 $2,383 -- $ -- $ -- $(30,141,750) $ -- $(30,139,367)
======= ====== ====== ==== =========== ============ ======= ============
FOR THE SIX MONTHS ENDED JUNE 30,
2000 AND 2001 (UNAUDITED):
Balance, January 1, 2000......... 238,333 $2,383 -- $ -- $ -- $(24,355,724) $ 1,803 $(24,351,538)
Net income (unaudited)......... -- -- -- -- -- 2,806,530 -- 2,806,530
Change in unrealized gains on
available-for-sale securities
(unaudited).................. -- -- -- -- -- -- (1,803) (1,803)
------- ------ ------ ---- ----------- ------------ ------- ------------
Balance, June 30, 2000
(unaudited).................... 238,333 $2,383 -- $ -- $ -- $(21,549,194) $ -- $(21,546,811)
======= ====== ====== ==== =========== ============ ======= ============
Balance, January 1, 2001......... 238,333 $2,383 -- $ -- -- $(30,141,750) $ -- $(30,139,367)
Net income (unaudited)......... -- -- -- -- -- 19,180,648 -- 19,180,648
Stock issued in conjunction
with unit offering
(unaudited).................. 130,000 1,300 65,000 650 25,380,183 -- -- 25,382,133
------- ------ ------ ---- ----------- ------------ ------- ------------
Balance, June 30, 2001
(unaudited).................... 368,333 $3,683 65,000 $650 $25,380,183 $(10,961,102) $ -- $ 14,423,414
======= ====== ====== ==== =========== ============ ======= ============
</Table>
See accompanying notes to consolidated financial statements.
F-6
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<Table>
<Caption>
YEARS ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------ ----------------------------
1998 1999 2000 2000 2001
------------ ------------ ------------ ------------ -------------
(UNAUDITED)
Cash flows from operating activities:
Net income (loss)................................... $(15,795,085) $ (9,150,034) $ (5,786,026) $ 2,806,530 $ 19,180,648
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities:
Depletion, depreciation and amortization.......... 12,397,800 11,040,035 13,506,477 5,394,322 7,262,042
Amortization of bond discount..................... -- -- -- -- 262,472
Amortization of deferred loan costs............... -- -- -- -- 206,291
Loss (gain) on sale of marketable securities...... 27,414 -- (995,179) (902,696) 417,180
Accretion of bond interest........................ (24,400) (219,478) (138,040) (82,229) (45,606)
Loss on sale of equipment......................... 5,373 -- -- -- 7,042
Reorganization costs.............................. -- -- 21,487,191 914,809 7,311,108
Gain on derivative contracts...................... -- -- -- -- (3,586,626)
Changes in assets and liabilities:
Deposit of restricted cash...................... -- -- -- -- (13,566,895)
Accounts receivable............................. (584,097) (3,085,313) (15,123,769) 352,469 2,649,245
Prepaid expenses................................ (499,256) (239,304) (851,477) (433,880) 278,518
Receivables from affiliates..................... (157,664) (752,554) 203,071 226,228 (420,711)
Accounts payable and accrued liabilities........ 11,798,139 14,533,644 12,346,569 3,706,164 (5,572,120)
Accounts payable subject to renegotiation....... -- -- -- -- 10,119,904
Pre-petition liabilities subject to
compromise.................................... -- -- 18,043,910 (1,424,676) (44,242,039)
------------ ------------ ------------ ------------ -------------
Net cash provided by (used in) operating
activities before reorganization items...... 7,168,224 12,126,996 42,692,727 10,557,041 (19,739,547)
------------ ------------ ------------ ------------ -------------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid........... -- -- (2,536,788) (610,710) (5,819,922)
Interest earned during bankruptcy................... -- -- 538,841 41,654 945,722
------------ ------------ ------------ ------------ -------------
Net cash used for reorganization items.............. -- -- (1,997,947) (569,056) (4,874,200)
------------ ------------ ------------ ------------ -------------
Net cash provided by (used in) operating
activities.................................. 7,168,224 12,126,996 40,694,780 9,987,985 (24,613,747)
------------ ------------ ------------ ------------ -------------
Cash flows from investing activities
Purchase of marketable securities................... -- (232,268) (1,118,069) (630,321) (159,897)
Proceeds from sale of marketable securities......... 319,217 -- 1,874,245 1,181,904 236
Additions to oil and natural gas properties......... (71,992,146) (13,572,444) (10,877,657) (3,609,141) (3,339,202)
Purchase of furniture, fixtures and equipment....... (326,718) (40,185) (31,280) (17,456) (336,016)
Proceeds from disposal of equipment................. 73,905 4,059 -- -- 6,500
Proceeds from sales of oil and natural gas
properties........................................ -- 2,262,300 389,971 381,500 2,225,529
Purchase of restricted cash and bonds............... -- (3,664,957) (355,000) (161,000) (375,000)
Proceeds from restricted marketable securities...... -- 3,300,000 -- -- --
------------ ------------ ------------ ------------ -------------
Net cash used in investing activities......... (71,925,742) (11,943,495) (10,117,790) (2,854,514) (1,977,850)
------------ ------------ ------------ ------------ -------------
Cash flows from financing activities:
Proceeds from long-term debt........................ 66,460,000 -- -- -- --
Proceeds from unit offering......................... -- -- -- -- 113,444,294
Payments of long-term debt.......................... -- (300,000) (376,500) (381,500) (104,323,500)
Payments of loan fees............................... (1,142,550) (20,927) -- -- (2,303,149)
Increase (decrease) in notes payable................ (164,249) 278,613 (24,547) (287,173) (251,237)
------------ ------------ ------------ ------------ -------------
Net cash provided by (used in) financing
activities.................................. 65,153,201 (42,314) (401,047) (668,673) 6,566,408
------------ ------------ ------------ ------------ -------------
Net increase (decrease) in cash and cash
equivalents......................................... 395,683 141,187 30,175,943 6,464,798 (20,025,189)
Cash and cash equivalents beginning of period......... 2,277,126 2,672,809 2,813,996 2,813,996 32,989,939
------------ ------------ ------------ ------------ -------------
Cash and cash equivalents end of period............... $ 2,672,809 $ 2,813,996 $ 32,989,939 $ 9,278,794 $ 12,964,750
============ ============ ============ ============ =============
Supplemental disclosures of cash flow information
Interest paid during the period..................... $ 4,684,493 $ 7,100,562 $ 4,039,520 $ 2,739,520 $ 19,182,654
Non cash transactions:
Accrued interest added to debt...................... -- 3,600,000 -- -- --
Transfer of long-term debt to pre-petition
liabilities subject to compromise................. -- -- 104,700,000 104,700,000 --
Discount on unit offering........................... -- -- -- -- (24,750,000)
Issuance of Class B common stock.................... -- -- -- -- 11,000,000
Transfer of oil and natural gas properties
to affiliate...................................... -- -- -- -- 1,097,611
Reorganization costs accrued in accounts payable and
accrued liabilities............................... -- -- 1,914,753 -- --
Reorganization costs accrued in pre-petition
liabilities subject to compromise................. -- -- 17,794,272 -- --
</Table>
See accompanying notes to consolidated financial statements.
F-7
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- BASIS OF PRESENTATION
Basis of Presentation
Tri-Union Development Corporation ("New TDC") (formerly Tribo Petroleum
Corporation ("Tribo")) was incorporated in the state of Texas in September,
1992. New TDC and its subsidiaries ("the Company") is an independent oil and
natural gas company engaged in the acquisition, operation and development of oil
and natural gas properties primarily in areas of Texas 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 New TDC and
its wholly-owned subsidiary Tri-Union Development Corporation ("TDC"), which was
incorporated in the state of Texas in November, 1967, and TDC's wholly-owned
subsidiary Tri-Union Operating Company ("TOC"), which was incorporated in the
state of Delaware in November, 1974. New TDC purchased TDC and its subsidiary
TOC in 1996 in a purchase transaction with an unrelated entity. All significant
intercompany accounts and transactions have been eliminated in consolidation. In
July 2001, New TDC and TDC merged and the surviving corporation was New TDC.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Presentation
The accompanying unaudited consolidated interim financial statements and
disclosures for the six months ended June 30, 2000 and 2001, have been prepared
by the Company in accordance with accounting principles generally accepted in
the United States of America and, in the opinion of management, reflect all
adjustments (consisting solely of normal recurring adjustments) necessary for a
fair presentation in all material respects of the results for the interim
periods. The interim unaudited financial statements for the six months ended
June 30, 2000 and 2001 should be read in conjunction with the Company's annual
consolidated financial statements for the years ended December 31, 1999 and
2000. The results of operations for the six months ended June 30, 2001 are not
necessarily indicative of results to be expected for the full year.
Use of Estimates
The accompanying financial statements are prepared in conformity with
accounting principles generally accepted in the United States of America which
require management to make estimates and assumptions that effect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Significant assumptions are
required in the valuation of proved oil and natural gas reserves, which as
described herein may affect the amount at which oil and natural gas properties
are recorded. Actual results could differ from these estimates.
Restricted Cash and Bonds
The Company had restricted cash balances at December 31, 1999 and 2000 of
$340,957 and $372,697, respectively. These restricted cash balances are pledged
for regulatory operating deposits and performance bonds.
In addition, the Company has zero coupon U.S. Treasury Bonds with a 2019
maturity value of $12,250,000, held in trust and pledged to the Minerals
Management Service ("MMS") for the plugging and abandonment of certain wells and
the decommissioning of offshore platforms. At
F-8
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1999 and 2000, these bonds had a carrying value of $3,840,550 and
$4,301,948, respectively.
Marketable Securities
The Company's marketable securities that are bought and held principally
for the purpose of selling them 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 during the period included in
earnings.
Marketable securities that the Company has the positive intent and ability
to hold to maturity are classified as held-to-maturity securities and recorded
at amortized cost. Marketable securities not classified as either
held-to-maturity or trading securities are classified as available-for-sale
securities. Available-for-sale securities are recorded at fair value in the
accompanying balance sheet, with the change in fair value during the period
excluded from earnings and recorded net of tax as a component of other
comprehensive income.
Oil and Natural Gas Interests
The Company follows the full cost method of accounting for oil and natural
gas property acquisition, exploration and development activities. Under this
method, all productive and nonproductive costs incurred in connection with the
acquisition of, exploration for and development of oil and natural gas reserves
for each cost center are capitalized. Capitalized costs include lease
acquisitions, geological and geophysical work, delay rentals and the costs of
drilling, completing and equipping oil and natural gas wells. Gains or losses
are recognized only upon sales or dispositions of significant amounts of oil and
natural gas reserves. Proceeds from all other sales or dispositions are treated
as reductions to capitalized costs.
Internal costs, including salaries, benefits and other internal salary
related costs, which can be directly identified with acquisition, exploration or
development activities are capitalized while any costs related to production,
general corporate overhead, or similar activities are charged to expense.
Geological and geophysical costs not directly associated with a specific
unevaluated property are included in the amortization base as incurred.
Capitalized internal costs directly identified with the Company's acquisition,
exploration and development activities amounted to approximately $680,000,
$764,000 and $767,000 in 1998, 1999 and 2000, respectively. Internal costs
included in capitalized oil and gas properties amounted to approximately
$1,444,000 and $2,211,000 at December 31, 1999 and 2000, respectively.
The capitalized costs of oil and natural gas properties, plus estimated
future development costs relating to proved reserves and estimated costs of
plugging and abandonment, net of estimated salvage value, are amortized on the
unit-of-production method based on total proved reserves. The computation of
depreciation, depletion and amortization ("DD&A") takes into consideration
restoration, dismantlement and abandonment costs and the anticipated proceeds
from equipment salvage. The estimated restoration, dismantlement and abandonment
costs for onshore properties are expected to be offset by the estimated salvage
value of lease and well equipment. The Company has recorded an offshore
abandonment liability of $2,675,000 as of December 31, 2000 based in total
expected abandonment costs of $14,627,000. This liability is included in
accumulated DD&A on the consolidated balance sheets. For the years ended
December 31, 1998, 1999, and 2000, the Company recorded accretion of its
offshore abandonment liability of $687,000, $905,000, and $1,083,000,
respectively. This accretion is recorded as a component of DD&A expense in the
consolidated statements of operations. (See Note 12).
F-9
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The costs of unproved properties are excluded from amortization until the
properties are evaluated, subject to an annual assessment of whether impairment
has occurred. In determining whether impairment of unevaluated properties has
occurred, management evaluates, among other factors, current oil and natural gas
industry conditions, capital availability, primary lease terms of the
properties, holding periods of the properties, and available geological and
geophysical data. Any impairment assessed is added to the costs being amortized.
Costs of drilling exploratory dry holes are included in the amortization base
immediately upon determination that a well is dry. At December 31, 2000, all of
the Company's oil and gas properties were classified as evaluated and are
included in the amortization base. The Company's proved oil and natural gas
reserves were estimated by an independent petroleum engineering firm.
The capitalized oil and natural gas property costs, less accumulated
depreciation, depletion and amortization and related deferred income taxes, if
any, are generally limited to an amount (the ceiling limitation) equal to the
sum of (a) the present value of estimated future net revenues computed by
applying current prices in effect as of the balance sheet date (with
consideration of price changes only to the extent provided by contractual
arrangements) to estimated future production of proved oil and natural gas
reserves, less estimated future expenditures (based on current costs) to be
incurred in developing and producing the reserves using a discount factor of 10%
and assuming continuation of existing economic conditions; and (b) the cost of
investments in unevaluated properties excluded from the costs being amortized.
No ceiling writedown was recorded in 1998, 1999 or 2000.
General and administrative expenses are reported net of amounts allocated
to working interest owners of the oil and natural gas properties operated by
Tribo, net of amounts charged for administrative and overhead costs and net of
amounts capitalized pursuant to the full cost method of accounting.
Furniture, Fixtures and Equipment
Furniture, fixtures and equipment are carried at cost. Depreciation is
provided on the straight-line basis using estimated useful lives of five to ten
years. At the time of a retirement or sale, the related cost and accumulated
depreciation are removed from the accounts, and any resulting gain or loss is
recorded to income. Maintenance and repairs are charged to expense as incurred.
Renewals, betterments and expenditures which increase the value of the property
or extend its useful life, are capitalized.
Cash Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
Financial Instruments and Concentration of Credit Risk
Financial instruments that subject the Company to credit risk consist of
accounts receivable. The receivables are primarily from companies in the oil and
natural gas industry or from individual oil and
F-10
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
natural gas investors. During 1998, 1999 and 2000, the Company had revenues from
certain customers exceeding 10% of total revenues as follows:
<Table>
<Caption>
1998 1999 2000
---- ---- ----
Customer A......................................... 13% 35% 31%
Customer B......................................... 12% 18% 16%
Customer C......................................... 22% 11% --
Customer D......................................... -- -- 11%
</Table>
In the case of receivables from joint interest owners, the Company may have
the ability to offset amounts due against the participant's share of production
from the related property.
The estimated fair value of financial instruments has been determined by
the Company using available market information and appropriate valuation
methodologies. The fair value of these instruments approximates their carrying
value at December 31, 1999 and 2000.
Income Taxes
The Company accounts for income taxes using the "liability method."
Accordingly, deferred tax liabilities or assets are determined based on
temporary differences between the financial statement and income tax bases of
assets and liabilities using enacted tax rates in effect for the year in which
the differences are expected to reverse.
Environmental Matters
Environmental costs are expensed or capitalized depending on their future
economic benefit. Costs that relate to an existing condition caused by past
operations and have no future economic benefit are expensed. Liabilities for
future expenditures of a noncapital nature are recorded when future
environmental expenditures and/or remediation is deemed probable, and the costs
can be reasonably estimated. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.
Derivative Transactions
The Company sometimes enters into fixed-price physical delivery contracts
and commodity price swap derivatives to manage price risk with regard to a
portion of its natural gas and crude oil production. The Company recognizes
revenues under fixed-price physical delivery contracts as the gas is sold. Prior
to January 1, 2001, the Company followed the guidance in Statement of Financial
Accounting Standards No. 80 ("SFAS No. 80"), "Accounting for Futures Contracts",
in accounting for its commodity price swap derivative contracts. Under SFAS No.
80, commodity price swap derivative contracts were accounted for using the hedge
method of accounting. Under this method, realized gains and losses on qualifying
hedges were recognized in oil and gas revenues when the associated production
occurred and the resulting cash flows were reported as cash flows from
operations. These swap contracts were designated as hedges and changes in their
fair value correlated with changes in the price of anticipated future production
such that the Company's exposure to the effects of commodity price changes was
reduced. If a contract does not qualify as a hedge, any changes in its fair
value are recorded currently.
Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"),
"Accounting for Derivative Instruments and Hedging Activities", as amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities -- Deferral of the Effective Date of FASB No. 133",
F-11
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. The adoption of these new accounting standards had no
impact on the Company's financial statements because the Company had no
derivatives at January 1, 2001.
Earnings (Loss) Per Share
Basic earnings per share includes no dilution and is computed by dividing
income available to common stockholders by the weighted average number of common
shares outstanding for the period. Diluted earnings per share reflects the
potential dilution of securities that could share in the earnings of an entity.
The Company had no potentially dilutive securities for the years ended December
31, 1998, 1999 or 2000.
Comprehensive Income
The Company has elected to report comprehensive income in a consolidated
statement of comprehensive income. Comprehensive income is comprised of net
income and all changes to stockholders' equity, except those due to investments
by stockholders, changes in paid-in capital and distributions to stockholders,
and is presented net of income taxes.
Reclassifications
Certain reclassifications have been made to the 1998 and 1999 balances to
conform to the 2000 presentation.
Recently Issued Accounting Pronouncements
In December 1999, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin No. 101 ("SAB 101"), "Revenue Recognition in Financial
Statements." SAB 101 outlines the basic criteria that must be met to recognize
revenue, and provides guidance for disclosure related to revenue recognition
policies. In June 2000, the SEC issued SAB 101B, that delayed the implementation
date of SAB 101 until the quarter ended December 31, 2000, with retroactive
application to the beginning of the Company's fiscal year. The adoption of SAB
101 did not have a material impact on the Company's financial position or
results of operations.
In March 2000, the FASB issued Interpretation No. 44, "Accounting for
Certain Transactions Involving Stock Compensation -- An Interpretation of APB
No. 25 ("FIN 44"). FIN 44 clarified the application of Opinion No. 25 for
certain issues, including: a) the definition of employee for purposes of
applying Opinion No. 25; b) the criteria for determining whether a plan
qualifies as a non-compensatory plan; c) the accounting consequences of various
modifications to the terms of a previously fixed stock option or award; and d)
the accounting for an exchange of stock compensation awards in a business
combination. In general, FIN 44 is effective July 1, 2000. The adoption of FIN
44 did not have a material impact on the Company's financial position or results
of operations.
F-12
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In June 2001, the Financial Accounting Standards Board finalized FASB
Statements No. 141, Business Combinations ("SFAS 141"), and Statement 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 requires 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.
NOTE 3 -- BANKRUPTCY
In October, 1997, the Company obtained a short-term bank loan of $105
million (the "Acquisition Facility") to finance the purchase of certain oil and
gas properties. During 1997 and through May 1998, the Company drew approximately
$35 million and $69 million, respectively, against the Acquisition Facility. In
August, 1998 before the Company was able to refinance the Acquisition Facility
with term debt, commodity prices began falling, with oil prices ultimately
reaching a twelve-year low in December of that year. The resultant negative
effect on the Company's cash flow from the deterioration of commodity prices,
coupled with the required amortization payments on the Acquisition Facility,
severely restricted the amount of capital the Company was able to dedicate to
development drilling. Consequently, the Company's oil and natural gas production
declined which further exacerbated its liquidity problem.
During February 2000, due to the Company's default under the terms of the
Acquisition Facility, the bank demanded payment of all principle and interest.
On March 14, 2000, TDC (the "Debtor") sought protection under Chapter 11 of the
U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of
Texas, Houston Division ("Bankruptcy Court").
Under Chapter 11, certain claims against the Debtor in existence prior to
the filing of the petition are stayed while the Debtor continues business
operations as debtor-in-possession. These claims are reflected in the December
31, 2000 balance sheet as "liabilities subject to compromise." Additional claims
(liabilities subject to compromise) may arise subsequent to the bankruptcy
filing date resulting from rejection of executory contracts by the Bankruptcy
Court (or agreed to by parties in interest). Claims secured against the Debtor's
assets are also stayed, although the holders of such claims have the right to
move the court for relief from the stay.
All payments made from TDC to TOC, TPC or any related party are required to
be approved by the Bankruptcy Court.
F-13
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reorganization Costs -- As a result of TDC filing for protection under
Chapter 11 of the U.S. Bankruptcy Code, the Company incurred certain
reorganization costs totaling $21,487,191 during the year ended December 2000
which include the following:
Amended Rejection of fixed-price physical delivery contract -- The
bankruptcy court approved a motion to reject a fixed-price physical
delivery contract. A claim has been filed by the damaged party resulting in
a liability of $17,059,272 (see Note 9).
Professional fees and other -- The Company was required to hire
certain legal and accounting professionals to help the Company in its
bankruptcy proceedings. The Company has estimated these fees to be
$3,611,760 through December 31, 2000. During the year ended December 31,
2000, the Company paid $1,692,007 of these professional fees.
Retention costs -- In an effort to maintain certain key employees
through the bankruptcy period, the Company is seeking approval from the
creditors committee and the bankruptcy court to set aside approximately
$855,000 to pay employees when certain conditions are met.
Interest -- The Company earned interest income of $538,841 from March
14, 2000 through December 31, 2000.
These reorganization costs were accrued on the accompanying consolidated
balance sheet as of December 31, 2000, as follows:
<Table>
<Caption>
PRE-PETITION ACCOUNTS
LIABILITIES PAYABLE
SUBJECT TO AND ACCRUED
COMPROMISE EXPENSES
------------ -----------
Cancellation of fixed-price physical delivery contract.... $17,059,272 $ --
Professional fees and other............................... 860,000 1,059,753
Retention................................................. -- 855,000
</Table>
The plan of reorganization also required the Company to pay additional bank
charges and interest of $7.7 million of which $4.0 million was accrued for the
three months ended March 31, 2001, and $3.7 million was accrued for the period
from April 1, 2001 to June 18, 2001, and additional professional fees of $4.0
million. The additional professional fees were reduced by $3.3 million upon
completion of the proposed offering as a condition of the settlement of the
Company's counterclaim against the bank. These costs were expensed in June 2001
when the Company emerged from bankruptcy.
During the six month period ended June 30, 2001, the Company incurred
additional reorganization costs totalling $7,311,108, which comprised:
<Table>
<Caption>
AMOUNT
----------
Professional fees........................................... $3,727,279
Interest.................................................... 1,700,839
Forgiveness of indebtedness with and transfers of oil and
gas properties to related parties (see Note 14(d))........ 1,882,990
----------
Total............................................. $7,311,108
==========
</Table>
F-14
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- ALLOWANCE FOR DOUBTFUL ACCOUNTS
The activity of the allowance for doubtful accounts for the year ended
December 31, was as follows:
<Table>
<Caption>
1998 1999 2000
--------- -------- ---------
Balance, beginning of year....................... $ 310,071 $695,791 $ 867,864
Additions (Recoveries)......................... 629,612 225,739 (498,436)
Write offs..................................... (243,892) (53,666) (17,923)
--------- -------- ---------
Balance, end of year............................. $ 695,791 $867,864 $ 351,505
========= ======== =========
</Table>
NOTE 5 -- MARKETABLE SECURITIES
Securities classified as available-for-sale at December 31, were as
follows:
<Table>
<Caption>
1999 2000
------------------- -------------------
MARKET MARKET
VALUE COST VALUE COST
-------- -------- -------- --------
Classified as available-for-sale:
Common stock......................... $172,500 $140,721 $ -- $ --
Common stock warrants................ 62,500 91,547 -- --
-------- -------- -------- --------
Total classified as
available-for-sale......... $235,000 $232,268 $ -- $ --
======== ======== ======== ========
</Table>
At December 31, 1999, unrealized gains and losses from available-for-sale
securities were $31,779, and $29,047, respectively. The net unrealized gains at
December 31, 1999, was $2,732, resulting in net of tax charges of $1,803,
recorded to Other Comprehensive Income. The Company held no available-for-sale
securities during 2000.
Proceeds, realized gains, and realized losses from the sales of securities
classified as available-for-sale for the year ended December 31, 1998 were
$319,217, $35,736, and $63,150, respectively. For the year ended December 31,
1999, the Company did not sell any available-for-sale securities. For the
purposes of determining realized gains and losses, the cost of securities sold
was based on specific identification.
During 2000, the Company began to buy and sell marketable equity securities
to take advantage of favorable market conditions. Accordingly, all
available-for-sale securities were recategorized to trading securities.
<Table>
<Caption>
1999 2000
------------------- -------------------
MARKET MARKET
VALUE COST VALUE COST
-------- -------- -------- --------
Classified as trading securities -- all
common stock......................... $ -- $ -- $472,248 $308,850
</Table>
During 2000, gross gains and gross losses included in results of operations
that resulted from transfers of securities from the available-for-sale category
into the trading category were $510,670 and $42,688, respectively. No such
transfers occurred in 1999 or 1998. All of these securities were sold in 2000.
F-15
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Proceeds, realized gains, realized losses, unrealized gains, and unrealized
losses related to securities classified as trading securities for the year ended
December 31, 2000 were $1,874,245, $879,458, $47,676, $230,429 and $67,031,
respectively. Realized and unrealized gains and losses on such securities are
reflected as gain (loss) on marketable securities in the accompanying statements
of operations. For the purposes of determining realized gains and losses, the
cost of securities sold was based on specific identification. The Company held
no securities classified as trading securities during 1998 or 1999.
NOTE 6 -- RELATED PARTY TRANSACTIONS
Balances owed by/(to) affiliated companies comprised the following at
December 31:
<Table>
<Caption>
1999 2000
---------- ---------
Receivable:
Atasca Resources, Inc..................................... $ 558,716 $ 408,632
Sole Shareholder and Chief Executive Officer.............. 339,962 625,199
Other Affiliates.......................................... 477,678 553,304
Payable:
Atasca Resources, Inc..................................... (146,380) (537,119)
Other Affiliates.......................................... (37,039) (60,150)
---------- ---------
Receivable from affiliates, net............................. $1,192,937 $ 989,866
========== =========
</Table>
Atasca Resources, Inc. and the Other Affiliates referred to above, are all
owned by the Company's sole shareholder and chief executive officer. With the
Company's issuance of class A and B common stock on June 18, 2001 (see note 14),
the sole shareholder's shareholdings were effectively reduced to 55%.
The net amounts receivable from affiliates are recorded in the accompanying
consolidated balance sheets as Receivables from Affiliates. The amounts due to
or from affiliates have no established repayment terms and no interest is
charged.
The receivables and payables with Atasca Resources, Inc. primarily relate
to: cash advances, transfers, reimbursement of corporate expenses, oil and gas
sales, production expenses, and related activities. In addition, Atasca
Resources, Inc. paid the Company a management fee of $118,929, $55,000, and
$60,000 in 1998, 1999, and 2000, respectively.
The receivable from the Company's sole shareholder and chief executive
officer principally relates to cash and travel advances and other business
expenses.
The receivables from other affiliates of the Company are primarily for cash
advances.
The Company earned revenues and incurred production expenses through Atasca
Resources, Inc. for the years ended December 31, as follows:
<Table>
<Caption>
1998 1999 2000
-------- -------- --------
Oil sales.......................................... $380,257 $321,747 $473,072
Natural gas sales.................................. 446,502 131,736 112,620
Production expenses................................ 675,605 381,995 237,807
</Table>
F-16
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 7 -- OIL AND NATURAL GAS PROPERTIES
The following table sets forth information concerning the Company's oil and
natural gas properties at December 31:
<Table>
<Caption>
1999 2000
------------ ------------
Costs of oil and natural gas properties, all
evaluated........................................... $115,690,605 $126,178,261
Accumulation, depreciation, depletion and
amortization........................................ (26,050,164) (39,045,538)
------------ ------------
$ 89,640,441 $ 87,132,723
============ ============
</Table>
At December 31, 2000, all of the Company's oil and gas properties were
evaluated and, accordingly, were included in the amortization base.
NOTE 8 -- NOTE PAYABLE -- IN DEFAULT
The note payable as of December 31, 2000 is included in pre-petition
liabilities subject to compromise in the accompanying consolidated balance
sheet.
The note payable balance at December 31, 1999 and 2000 of $104,700,000 and
$104,323,500, respectively, resulted from a $105,000,000 acquisition facility
with a bank dated October 15, 1997. The borrowings available under the
acquisition facility were to be redetermined after December 31 and June 30 of
each year based upon the Company's proven reserves of oil and natural gas.
Interest accrued at prime plus 4%, payable at 90 day intervals.
The acquisition facility was collateralized by deeds of trust, mortgages,
assignments of oil and natural gas production, security agreements and financing
statements on substantially all of the real and personal property of the
Company. Additional collateral includes the assignment of the common stock of
the Company and the personal guarantee of the Company's stockholder.
In February 2000, due to the Company's violations of the terms of the
acquisition facility, the bank demanded payment of the note and all accrued
interest. On March 14, 2000 TDC filed for protection under Chapter 11 of the
United States Bankruptcy Code (see Note 3).
Beginning March 14, 2000, the Company accrued interest at 12% per annum,
which is different from the stated rate of prime plus 4% (12.5% at December 31,
2000). Because of their adversarial relationship with the bank, the Company was
unable to obtain sufficient information from the bank regarding the rates
charged on the outstanding balance of the loan. The 12% rate accrued by the
Company through December 31, 2000 was consistent with rates the Company had been
charged by the bank prior to the bankruptcy. The actual rate charged by the bank
from March 14, 2000 through the date of the Company's emergence from bankruptcy
in June 2001 could not be determined by the Company; however, the final amount
paid to the bank differed only $100,000 from the Company's estimate.
NOTE 9 -- DERIVATIVE TRANSACTIONS
The Company may use derivative instruments to manage exposures to commodity
prices. The Company's objectives for holding derivatives are to minimize the
risks using the most effective methods to eliminate or reduce the impacts of
this exposure.
In April 1999, the Company entered into a thirty-two month fixed-price
physical delivery contract with Aquila Energy Marketing Corporation ("Aquila")
that obligated the Company to deliver specified volumes of natural gas to Aquila
at a certain price. For the years 1999, 2000, and 2001, the
F-17
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company agreed to deliver approximately 1,525,000 Mbtu, 3,098,000 Mbtu, and
2,894,000 Mbtu, respectively, with prices ranging from $2.353/Mcf to $2.697/Mcf.
With the authorization of the bankruptcy court, the Company rejected this
fixed-price physical delivery contract effective December 20, 2000. Aquila filed
a claim against the Company for damages relating to the cancellation of the
contract for $17,559,272. The claim has been accrued by the Company and is
included in pre-petition "liabilities subject to compromise" in the accompanying
consolidated balance sheet as of December 31, 2000.
In June, 2001 the Company entered into three commodity swap derivative
contracts as a condition of the issuance of the Notes described in Note 14(f).
Under the terms of the Notes, the Company must use these contracts to mitigate
the volatility of the commodity prices to ensure that the Company has sufficient
cash flows to service the Notes. These commodity swap derivative contracts are
designated as cash flow hedges. The contracts do not qualify for hedge
accounting under FAS No. 133, therefore, the Company recorded these contracts at
their estimated fair values, and included the changes in their fair value in the
statement of operations.
As of June 30, 2001 the Company had three outstanding commodity price swap
agreements. The following table sets forth the volumes and hedge prices of the
contracts:
<Table>
<Caption>
CONTRACT 1 CONTRACT 2 CONTRACT 3
------------------------ ------------------------ ------------------------
CRUDE OIL NATURAL GAS NATURAL GAS
------------------------ ------------------------ ------------------------
DATE VOLUME/DAY HEDGE PRICE VOLUME/DAY HEDGE PRICE VOLUME/DAY HEDGE PRICE
---- ---------- ----------- ---------- ----------- ---------- -----------
July 1 - December 31,
2001...................... 2.5 Mbbl $25.30/bbl 10.7 MMcf $3.96/mcf 7.3 MMcf $4.62/mcf
January 1 - June 30, 2002... 2.2 Mbbl 25.30/bbl 6.7 MMcf 3.96/mcf 4.3 MMcf 4.62/mcf
July 1 - December 31,
2002...................... 2.2 Mbbl 25.30/bbl 6.7 MMcf 3.96/mcf 4.3 MMcf 4.36/mcf
January 1 - June 30, 2003... 1.9 Mbbl 25.30/bbl 7.7 MMcf 3.96/mcf 3.4 MMcf 4.36/mcf
</Table>
The contracts call for the Company to receive or make payments based upon
the differential between the hedge prices and the market prices, as defined in
the contracts, for the notional quantities. The estimated fair value of these
contracts at June 30, 2001 of $3,586,626 is included in the accompanying balance
sheet as a current asset of $1,649,326 and as a non-current asset of $1,937,300.
The unrealized gain of $3,586,626 is included in the accompanying statement of
operations as "Gain on Derivative Contracts".
The Company is exposed to credit risk in the event of nonperformance by the
counterparty in the commodity price swap contracts; however, the Company does
not anticipate nonperformance by the counterparty.
NOTE 10 -- ACQUISITION OF OIL AND NATURAL GAS PROPERTIES
On March 31, 1998, the Company purchased certain oil and gas properties
from Apache for approximately $63,000,000. The acquisition was accounted for
using the purchase method of accounting, and accordingly, the purchase price was
allocated to the oil and gas properties acquired based on estimated fair values
at the date of acquisition. In this transaction, the Company acquired only oil
and gas properties from Apache and assumed no liabilities. The operating results
of the assets acquired have been included in the accompanying consolidated
statement of loss and comprehensive loss beginning March 31, 1998. The unaudited
pro forma information for the year ended December 31, 1998 shown below assumes
that the acquisition occurred on January 1, 1998.
F-18
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
This information is not necessarily reflective of the results of operations
which would have been obtained had the acquisition occurred at an earlier date
nor is it reflective of future operating results.
<Table>
<Caption>
AMOUNT
------------
(UNAUDITED)
Revenues............................................. $ 31,439,436
============
Net loss............................................. $(14,951,999)
============
Loss per common share................................ $ (62.74)
============
</Table>
NOTE 11 -- INCOME TAXES
The provision for income taxes for the years ended December 31, consisted
of the following:
<Table>
<Caption>
1998 1999 2000
------- ------- -------
Current............................................... $ -- $ -- $79,000
Deferred.............................................. -- -- --
------- ------- -------
$ -- $ -- $79,000
======= ======= =======
</Table>
Deferred income taxes result from differences between the bases of assets
and liabilities as measured for income tax and financial reporting purposes. The
significant components of deferred tax assets and liabilities as of December 31,
were as follows:
<Table>
<Caption>
1999 2000
------------ ------------
Deferred Tax Assets:
Net operating loss carryforwards..................... $ 14,349,400 $ 16,273,000
Contract loss accrual................................ -- 5,661,000
Oil and natural gas properties and other equipment... 336,669 --
Accrued expenses -- other............................ -- 632,000
Plugging and abandonment costs....................... 255,000 --
Other................................................ -- 41,000
------------ ------------
Total........................................ 14,941,069 22,607,000
------------ ------------
Deferred Tax Liabilities:
Oil and natural gas properties and other equipment... -- (6,402,000)
Unrealized securities gains.......................... (929) --
------------ ------------
Total........................................ (929) (6,402,000)
------------ ------------
Valuation Allowance.................................... (14,940,140) (16,205,000)
------------ ------------
Net deferred tax asset................................. $ -- $ --
============ ============
</Table>
The Company recorded a valuation allowance at December 31, 1999 and 2000
equal to the excess of deferred tax assets over deferred tax liabilities as
management is unable to determine that these tax benefits are more likely than
not to be realized.
F-19
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following reconciles statutory federal income tax with the provision
for income tax for the years ended December 31:
<Table>
<Caption>
1998 1999 2000
----------- ----------- -----------
Income tax benefit at statutory rate........ $(5,370,300) $(3,111,000) $(1,940,000)
Alternative minimum tax..................... -- -- 79,000
Non-deductible expenses..................... 13,400 71,200 2,000
Increase in valuation allowance............. 5,356,900 3,039,800 1,938,000
----------- ----------- -----------
Provision for income taxes.................. $ -- $ -- $ 79,000
=========== =========== ===========
</Table>
At December 31, 2000, the Company had net operating loss carryforwards for
income tax reporting purposes of approximately $48,000,000 which will expire
during the years 2001 through 2019. The Internal Revenue Code significantly
limits the amount of acquired net operating loss carryforwards that are
available to offset future taxable income when a change of ownership occurs. As
of December 31, 2000, the Company has approximately $7,800,000 of its net
operating losses that are subject to such limitations, of which, the Company can
utilize $658,000 per year.
As of December 31, 2000, the Company's net operating losses expire as
follows:
<Table>
<Caption>
YEAR AMOUNT
---- -----------
2001.................................................. $ 2,697,685
2007.................................................. 1,661,522
2008.................................................. 264,780
2009.................................................. 1,726,300
2010.................................................. 1,455,967
2012.................................................. 2,207,196
2018.................................................. 18,136,659
2019.................................................. 19,710,242
-----------
$47,860,351
===========
</Table>
Retained earnings as of January 1, 1998 have been restated from previously
issued financial statements due to an increase in the Company's valuation
allowance of $590,742 against the deferred tax asset.
NOTE 12 -- COMMITMENTS AND CONTINGENCIES
Lease commitments
The Company has non-cancelable operating leases covering certain equipment
and buildings. The following is a schedule of future minimum lease payments as
of December 31, 2000:
<Table>
<Caption>
YEARS ENDING DECEMBER 31, AMOUNT
------------------------- ----------
2001................................................... $1,064,091
2002................................................... 227,182
2003................................................... 5,080
----------
$1,296,353
==========
</Table>
Rent expense incurred under operating leases amounted to $836,140,
$2,637,376 and $3,390,383 for the years ended December 31, 1998, 1999 and 2000,
respectively.
F-20
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Lawsuits
The Company is the defendant in several lawsuits filed by companies for
breach of contract with claims and joint interest disputes totaling
approximately $9,285,000. The Company has accrued such amount which is included
in pre-petition liabilities subject to compromise in the accompanying balance
sheet as of December 31, 2000.
The Company is a defendant in various lawsuits arising from normal business
activities. Management has reviewed pending litigation with legal counsel and
believes that these actions are without merit or that the ultimate liability, if
any, resulting from them will not materially affect the Company's financial
position.
Regulatory and environmental contingencies
During 2000, the Company reached a settlement with the MMS resolving a
civil enforcement action related to non-environmental infractions of platform
construction brought against the Company in August 2000 by the MMS. The Company
agreed to pay civil penalties of $506,600 with $25,325 to be paid out initially,
and the remaining $481,175 to be paid out in quarterly installments over a
two-year period. The settlement between the MMS and the Company was not an
admission of liability by the Company with respect to the violations alleged by
the MMS.
The Company, as an owner and operator of oil and natural gas properties, is
subject to various federal, state and local laws and regulations relating to
discharge of materials into, and protection of, the environment. These laws and
regulations may, among other things, impose liability on the lessee under an oil
and natural gas lease for the cost of pollution clean-up resulting from
operations and subject the lessee to liability for pollution damages. The
Company maintains insurance coverage, which it believes, is customary in the
industry, although it is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of
December 31, 2000 which would have a material impact on its financial position
or results of operations. There can be no assurance however, that current
regulatory requirements will not change, or past non-compliance with
environmental laws will not be discovered on the Company's properties.
Other
As of December 31, 2000, the Company expects the future cost of
restoration, dismantlement and abandonment of certain offshore wells and the
decommissioning of offshore platforms to be approximately $14,627,000. In
connection therewith, the Company has provided zero coupon U.S. Treasury Bonds
with a 2019 maturity value of $12,250,000 to be held in trust and pledged to the
MMS for a portion of such estimated costs. At December 31, 1999 and 2000, these
bonds had a carrying value of $3,840,550 and $4,301,948, respectively.
NOTE 13 -- CAPITAL STOCK
Effective June 15, 2001, the Company was authorized to issue two classes of
common stock, class A and class B. The holders of the common stock are entitled
to one vote for each share on all matters voted upon by shareholders, including
the election of directors. Such holders are not entitled to vote cumulatively
for the election of directors. Holders of a majority of the shares of common
stock entitled to vote in any election of directors may elect all of the
directors standing for election, subject to the rights of holders of class B
common stock described below.
F-21
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Holders of class A and class B common stock are together entitled to
participate pro rata in such dividends as may be declared in the discretion of
the board of directors out of funds legally available therefore. Holders of
class A and class B common stock together are entitled to share ratably in the
net assets of the Company upon liquidation after payment or provision for all
liabilities and any preferential rights. Holders of common stock have no
preemptive rights to purchase shares of stock of the Company. Shares of common
stock are not subject to any redemption provisions and are not convertible into
any other securities of the Company, except that each share of class B common
stock is convertible into one share of class A common stock under certain
circumstances.
Special Rights of Class B Common Stock
In addition to the rights of the holders of common stock set forth above,
the holders of a majority of the class B common stock, voting together as a
single class, are entitled to designate one person to serve as a non-voting
advisory observer to the Company's board of directors, and further, at any time,
to cause the Company to increase the size of its board of directors and to
immediately elect to the board of directors a number of directors (having full
voting power) nominated by a majority of the holders of the class B common stock
sufficient to constitute a majority of the board of directors. Until there are
no outstanding shares of class B common stock, the board of directors may not
consist of more than seven directors other than those nominated by the holders
of the class B common stock in accordance with the foregoing. Only the holders
of the class B common stock may remove the directors that such holders are
entitled to designate.
In addition to any vote required by law, all matters submitted to a vote of
the Company's shareholders will require the approval of the holders of a
majority of the issued and outstanding shares of class B common stock, voting
separately as a single class. In addition, any amendment to the Company's Bylaws
will require the approval of the holders of the majority of the issued and
outstanding shares of class B common stock.
NOTE 14 -- SUBSEQUENT EVENTS
(a) During March, 2001, the Company entered into a lease agreement with a
related party, which is owned and controlled by the Company's chief executive
officer, for the lease of its current office facilities. The lease is on a month
to month basis and requires the Company to pay the related party $26,000 per
month.
(b) On June 5, 2001, the Company sold certain oil and natural gas property
for $2.2 million.
(c) On May 23, 2001, TDC's plan of reorganization was confirmed by the
bankruptcy court, pending the completion of the proposed securities offering. In
accordance with this plan, the Company paid all pre-petition liabilities in
full. In addition, the Company paid interest at 6% per annum for all unsecured
pre-petition liabilities subject to compromise, and interest at prime plus 2%
(11.5% at December 31, 2000) on the liability relating to the cancellation of a
fixed-price physical delivery contract. In finalizing the plan, TDC's largest
creditor agreed to a $3,300,000 reduction in its professional fees related to
TDC's bankruptcy filing and a transfer of certain oil and gas properties to the
Company's the sole shareholder and chief executive officer (see 14(d) below), in
return for settlement of a lawsuit filed against the creditor by Tribo, TDC, and
Tribo's then sole shareholder and chief executive officer. The $3,300,000
reduction in the creditor's professional fees was accounted for as a decrease in
the Company's reorganization costs.
(d) As a condition of TDC's plan of reorganization, on May 25, 2001, the
Company agreed to transfer all of the oil and natural gas properties in Texas
that were owned by Tribo Petroleum Corporation with a net book value at December
31, 2000 of approximately $1,098,000 to its affiliate,
F-22
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Atasca Resources, Inc., a company owned by the Company's then sole shareholder
and chief executive officer, at their net book value. Revenues from these
properties totaled $1,142,932, $895,644, $1,777,649, $879,943, and $527,047 for
the years ended December 31, 1998, 1999 and 2000, and the six months ended June
30, 2000 and 2001, respectively. In connection with this transaction, all
balances owing to and from the Company by its affiliates on May 25, 2001 were
forgiven. These balances aggregated to a net receivable from the affiliates of
$1,883,000. As a consequence of these transactions, the Company recorded a
one-time reorganization expense of approximately $1,883,000 in the second
quarter of 2001.
(e) On June 13, 2001, the Company increased its authorized share capital to
445,000 shares of class A common stock and 65,000 shares of class B common
stock. The Company also effected a 238.333:1 stock split of its class A common
stock. The consolidated financial statements give retroactive effect to the
stock split for all periods presented. In connection with the stock split, the
par value of the class A common stock decreased from $1.00 to $0.01 per share.
The par value of the class B common stock is $0.01. The class B common stock is
convertible into class A common stock upon the occurrence of certain events, as
defined.
(f) On June 18, 2001, the Company completed a unit offering of (1) $130
Million of 12.5% senior secured notes due 2006 ("Notes") and (2) 130,000 shares
of class A common stock of Tribo. Each unit consisted of a Note in the principal
amount of $1,000 and one share of class A common stock. The Notes are guaranteed
by TDC.
Notes
The Notes mature on June 1, 2006 and require amortization payments of the
greater of $20 million and 15.3% as of June 1, 2002 and 2003 and an amortization
payment of the greater of $15 million and 11.5% as of June 1, 2004. Interest is
payable semi-annually on June 1 and December 1 of each year.
The Notes were issued at a 5.5% discount from their face amount resulting
in an aggregate discount of $7,150,000 that is being amortized as additional
interest expense over the term of the Notes. The 5.5% discount, together with
value of the class A common stock issued in the offering which was also
accounted for as bond discount, the allocated value of the class B common stock,
and other offering costs aggregating a total of $44,241,000 (see below), make
the effective interest rate on the Notes 21.7%.
At any time prior to June 1, 2003, New TDC may redeem in the aggregate up
to 30% of the then outstanding aggregate principal amount of the Notes with the
Net Cash Proceeds of one or more equity offerings at a redemption price of
112.5% of the Notes, together with accrued and unpaid interest to the redemption
date.
Class A Common Stock
The Company issued 130,000 shares of class A common stock with an estimated
fair value of $17.6 million. This amount was allocated to the value of the class
A common stock from the total proceeds received by the Company in the unit
offering, thereby creating an additional bond discount which is being amortized
to interest expense over the life of the bonds using the effective interest
method.
F-23
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Class B Common Stock
In conjunction with the offering, the Company issued 65,000 shares of class
B common stock to the initial purchaser of the Notes. These shares had a fair
value of $11,000,000 and this value was considered to be offering costs of the
Company's unit offering. Accordingly, $9,427,000 was allocated to the debt
component of the unit offering, and $1,573,000 was allocated to the equity
component of the unit offering. The portion of the offering costs associated
with the issuance of the Notes is being amortized as additional interest expense
over the term of the Notes. The class B common stock has special voting rights
and the ability to control the board of directors of New TDC, subject to certain
limitations (See Note 13).
In addition, the Company incurred other offering costs of $11,709,000. Of
these costs $10,064,000 was allocated to the debt component of the unit
offering, and $1,645,000 was allocated to the equity component of the unit
offering. The portion of the offering costs associated with the issuance of the
Notes is being amortized as additional interest expense over the term of the
Notes.
Effective with the issuance of the class A and class B common stock, the
Company's chief executive officer is no longer the sole shareholder as his
shareholdings were effectively reduced to 55%.
(g) On June 18, 2001, the Company entered into an agreement to hedge
approximately 80% of the Company's projected oil and gas production from proved
developed producing reserves through June 30, 2003 (See Note 9).
(h) On July 27, 2001, New TDC merged with TDC, one of its wholly-owned
subsidiaries. As a result of the merger, the surviving corporation was New TDC.
NOTE 15 -- SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION
Information with respect to the Company's oil and natural gas producing
activities is presented in the following tables. Estimates of reserve
quantities, as well as future production and discounted cash flows before income
taxes, were determined by an independent petroleum engineering firm, as of
December 31, 1998, 1999 and 2000.
Oil and Natural Gas Related Costs
The following table sets forth information concerning costs related to the
Company's oil and gas property acquisition, exploration and development
activities in the United States during the years ended December 31,1998, 1999
and 2000:
<Table>
<Caption>
1998 1999 2000
----------- ----------- -----------
Property acquisition -- proved............ $62,477,242 $ 249,971 $ 408,231
Less -- proceeds from sales of
properties.............................. -- (2,262,300) (389,971)
Development costs......................... 9,514,904 13,322,473 10,080,396
Exploration costs......................... -- -- 389,030
----------- ----------- -----------
$71,992,146 $11,310,144 $10,487,686
=========== =========== ===========
</Table>
F-24
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Results of Operations from Oil and Natural Gas Producing Activities
The following table sets forth the Company's results of operations from oil
and natural gas producing activities for the years ended December 31:
<Table>
<Caption>
1998 1999 2000
------------ ------------ ------------
Revenues................................ $ 25,836,896 $ 36,270,343 $ 73,452,054
Production costs and taxes.............. (18,688,733) (18,657,542) (28,102,775)
Depreciation, depletion and
amortization.......................... (11,782,496) (10,526,878) (12,995,403)
------------ ------------ ------------
Income (loss) from oil and natural gas
producing activities.................. $ (4,634,333) $ 7,085,923 $ 32,353,876
============ ============ ============
Depletion rate per thousand cubic feet
(Mcf) of natural gas equivalent....... $ 0.91 $ 0.76 $ 0.80
============ ============ ============
</Table>
In the presentation above, no deduction has been made for indirect costs
such as corporate overhead or interest expense. No income taxes are reflected
above due to the Company's tax loss carryforwards.
Oil and Natural Gas Reserves (Unaudited)
The following table sets forth the Company's net proved oil and natural gas
reserves at December 31, 1998, 1999 and 2000 and the changes in net proved oil
and natural gas reserves for the years then ended. Proved reserves represent the
estimated quantities of crude oil and natural gas which geological and
engineering data demonstrate with reasonable certainty to be recoverable in the
future years from known reservoirs under existing economic and operating
conditions. The reserve information indicated below requires substantial
judgment on the part of the reserve engineers, resulting in estimates which are
not subject to precise determination. Accordingly, it is expected that the
estimates of reserves will change as future production and development
information becomes available and that revisions in these estimates could be
significant. Reserves
F-25
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
are measured in barrels (Bbls) in the case of oil, and units of one thousand
cubic feet (Mcf) in the case of natural gas.
<Table>
<Caption>
OIL (BBLS) GAS (MCF)
---------- ---------
(AMOUNTS IN
THOUSANDS)
Proved reserves
Balance, December 31, 1997................................ 1,521 79,583
Purchases of reserves in place......................... 9,816 28,542
Discoveries and extensions............................. 940 9,424
Revisions of previous estimates........................ 72 311
Production............................................. (1,030) (6,711)
------ -------
Balance, December 31, 1998................................ 11,319 111,149
Discoveries and extensions............................. 609 21,774
Revisions of previous estimates........................ 5,132 (9,515)
Sale of reserves in place.............................. (64) (6,309)
Production............................................. (1,145) (7,007)
------ -------
Balance, December 31, 1999................................ 15,851 110,092
Discoveries and extensions............................. 644 13,176
Revisions of previous estimates........................ 208 (13,258)
Expiration of leases................................... (244) (11,542)
Sale of reserves in place.............................. (53) (455)
Production............................................. (1,333) (8,314)
------ -------
Balance, December 31, 2000................................ 15,073 89,699
====== =======
Proved developed reserves at December 31, 1998.............. 9,124 58,088
====== =======
Proved developed reserves at December 31, 1999.............. 12,957 58,265
====== =======
Proved developed reserves at December 31, 2000.............. 12,290 45,575
====== =======
</Table>
Of the Company's total proved reserves as of December 31, 1998, 1999 and
2000, approximately 48%, 48% and 57%, respectively, were classified as proved
developed producing, 15%, 18% and 9%, respectively, were classified as proved
developed non-producing and 37%, 34% and 34%, respectively, were classified as
proved undeveloped. All of the Company's reserves are located in the continental
United States.
F-26
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
The standardized measure of discounted future net cash flows from the
Company's proved oil and natural gas reserves is presented in the following
table:
<Table>
<Caption>
DECEMBER 31,
----------------------------------
1998 1999 2000
--------- --------- ----------
(AMOUNTS IN THOUSANDS)
Future cash inflows............................. $ 339,260 $ 733,163 $1,316,621
Future production costs and taxes............... (117,128) (208,427) (275,236)
Future development costs........................ (41,622) (56,621) (57,384)
Future income tax expenses...................... (21,558) (102,553) (249,779)
--------- --------- ----------
Net future cash flows........................... 158,952 365,562 734,222
Discount at 10% for timing of cash flows........ (53,549) (133,998) (261,943)
--------- --------- ----------
Discounted future net cash flows from proved
reserves...................................... $ 105,403 $ 231,564 $ 472,279
========= ========= ==========
</Table>
The following table sets forth the changes in the standardized measure of
discounted future net cash flows from proved reserves during 1998, 1999 and
2000:
<Table>
<Caption>
DECEMBER 31,
------------------------------
1998 1999 2000
-------- -------- --------
(AMOUNTS IN THOUSANDS)
Balance, beginning of year......................... $ 73,938 $105,403 $231,564
Sales, net of production costs and taxes........... (7,148) (17,613) (45,349)
Discoveries and extensions......................... 10,362 41,619 139,327
Purchases and sales of reserves in place........... 50,024 (4,647) (738)
Changes in prices and production costs............. (36,687) 101,748 294,404
Revisions of quantity estimates.................... 582 49,998 (59,897)
Expiration of leases............................... -- -- (21,380)
Net changes in development costs................... (316) (7,582) 4,156
Interest factor -- accretion of discount........... 9,317 11,206 25,959
Net change in income taxes......................... 6,486 (48,183) (96,791)
Changes in production rates and other.............. (1,155) (385) 1,024
-------- -------- --------
Balance, end of year............................... $105,403 $231,564 $472,279
======== ======== ========
</Table>
Estimated future net cash flows represent an estimate of future net
revenues from the production of proved reserves using current sales prices,
along with estimates of the operating costs, production taxes and future
development and abandonment costs (less salvage value) necessary to produce such
reserves. The average prices used at December 31, 1998, 1999 and 2000, were
$11.17, $25.57 and $25.90 per Bbl and $1.86, $2.96 and $10.31 per Mcf,
respectively. No deduction has been made for depreciation, depletion or any
indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs
with respect to producing oil and natural gas properties. Future development
costs are based on the best estimate of such costs assuming current economic and
operating conditions.
F-27
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved, less
applicable carryforwards, for both regular and alternative minimum tax.
The future net revenue information assumes no escalation of costs or
prices, except for oil and natural gas sales made under terms of contracts which
include fixed and determinable escalation. Future costs and prices could
significantly vary from current amounts and, accordingly, revisions in the
future could be significant.
F-28
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 16 -- CONSOLIDATING INFORMATION
CONSOLIDATING BALANCE SHEET
DECEMBER 31, 1999
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ ---------- ------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents.............. $ 1,987,514 $ 402,153 $ 424,329 $ -- $ 2,813,996
Accounts receivable, net............... 8,717,753 214,350 435,806 (210,269) 9,157,640
Marketable securities.................. -- -- 235,000 -- 235,000
Prepaid and other...................... 925,213 -- 1,073 -- 926,286
------------ ---------- ------------ ----------- ------------
Total current assets............ 11,630,480 616,503 1,096,208 (210,269) 13,132,922
------------ ---------- ------------ ----------- ------------
Oil and natural gas properties, net...... 87,932,096 -- 1,708,345 -- 89,640,441
Other assets
Restricted cash and bonds.............. 4,181,507 -- -- -- 4,181,507
Furniture, fixtures and equipment,
net.................................. 198,514 41,131 16,870 -- 256,515
Receivables from affiliates, net....... 1,752,359 1,137,788 (1,697,210) -- 1,192,937
Deferred loan costs, net............... 498,499 -- -- -- 498,499
Investment in subsidiary............... 1,795,372 -- (25,373,174) 23,577,802 --
------------ ---------- ------------ ----------- ------------
Total other assets.............. 8,426,251 1,178,919 (27,053,514) 23,577,802 6,129,458
------------ ---------- ------------ ----------- ------------
$107,988,827 $1,795,422 $(24,248,961) $23,367,533 $108,902,821
============ ========== ============ =========== ============
LIABILITIES AND STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
Current liabilities:
Accounts payable and accrued
liabilities........................ $ 23,595,448 $ 50 $ 26,417 $ (210,269) $ 23,411,646
Accrued interest..................... 4,784,286 -- -- -- 4,784,286
Notes payable........................ 282,267 -- 76,160 -- 358,427
Note payable -- in default............. 104,700,000 -- -- -- 104,700,000
------------ ---------- ------------ ----------- ------------
133,362,001 50 102,577 (210,269) 133,254,359
------------ ---------- ------------ ----------- ------------
Commitments and Contingencies
Stockholder's equity (capital deficit)
Class A common stock................... 1,000 1,000 2,383 (2,000) 2,383
Retained earnings (deficit)............ (25,374,174) 1,794,372 (24,355,724) 23,579,802 (24,355,724)
Accumulated other comprehensive
income............................... -- -- 1,803 -- 1,803
------------ ---------- ------------ ----------- ------------
Total stockholder's equity
(capital deficit)............. (25,373,174) 1,795,372 (24,351,538) 23,577,802 (24,351,538)
------------ ---------- ------------ ----------- ------------
$107,988,827 $1,795,422 $(24,248,961) $23,367,533 $108,902,821
============ ========== ============ =========== ============
</Table>
F-29
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2000
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ ---------- ------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents.............. $ 32,426,157 $ (112,690) $ 676,472 $ -- $ 32,989,939
Accounts receivable, net............... 23,680,382 451,033 618,809 (468,815) 24,281,409
Marketable securities.................. -- -- 472,248 -- 472,248
Prepaid and other...................... 973,632 365,965 438,166 -- 1,777,763
------------ ---------- ------------ ----------- ------------
Total current assets............ 57,080,171 704,308 2,205,695 (468,815) 59,521,359
------------ ---------- ------------ ----------- ------------
Oil and natural gas properties, net...... 85,670,289 386,616 1,075,818 -- 87,132,723
Other assets
Restricted cash and bonds.............. 4,674,546 -- 99 -- 4,674,645
Furniture, fixtures and equipment,
net.................................. 122,391 30,732 22,398 -- 175,521
Receivables from affiliates, net....... 122,459 1,965,510 (1,098,103) -- 989,866
Deferred loan costs, net............... 99,700 -- -- -- 99,700
Investment in subsidiary............... 3,030,900 -- (32,113,482) 29,082,582 --
------------ ---------- ------------ ----------- ------------
Total other assets.............. 8,049,996 1,996,242 (33,189,088) 29,082,582 5,939,732
------------ ---------- ------------ ----------- ------------
$150,800,456 $3,087,166 $(29,907,575) $28,613,767 $152,593,814
============ ========== ============ =========== ============
LIABILITIES AND STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued
liabilities........................ $ 26,790,041 $ 56,266 $ 231,792 $ (468,815) $ 26,609,284
Accrued interest..................... 7,224,477 -- -- -- 7,224,477
Notes payable........................ 333,880 -- -- -- 333,880
------------ ---------- ------------ ----------- ------------
34,348,398 56,266 231,792 (468,815) 34,167,641
------------ ---------- ------------ ----------- ------------
Pre-petition liabilities subject to
compromise:
Note payable -- in default............. 104,323,500 -- -- -- 104,323,500
Accrued interest....................... 6,226,808 -- -- -- 6,226,808
Accounts payable and accrued
liabilities -- unsecured............. 38,015,232 -- -- -- 38,015,232
------------ ---------- ------------ ----------- ------------
Total pre-petition liabilities
subject to compromise......... 148,565,540 -- -- -- 148,565,540
------------ ---------- ------------ ----------- ------------
Commitments and Contingencies
Stockholder's equity (capital deficit):
Class A common stock................... 1,000 1,000 2,383 (2,000) 2,383
Retained earnings (deficit)............ (32,114,482) 3,029,900 (30,141,750) 29,084,582 (30,141,750)
------------ ---------- ------------ ----------- ------------
Total stockholder's equity
(capital deficit)............. (32,113,482) 3,030,900 (30,139,367) 29,082,582 (30,139,367)
------------ ---------- ------------ ----------- ------------
$150,800,456 $3,087,166 $(29,907,575) $28,613,767 $152,593,814
============ ========== ============ =========== ============
</Table>
F-30
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING BALANCE SHEET
JUNE 30, 2001
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ ---------- ----------- ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents............................... $12,159,239 $ 748,213 $ 57,298 -- $ 12,964,750
Restricted cash......................................... 13,566,895 -- -- -- 13,566,895
Accounts receivable, net................................ 20,751,594 829,186 676,583 -- 22,257,363
Marketable securities................................... -- -- 214,728 -- 214,728
Prepaid and other....................................... 1,085,550 133 413,562 -- 1,499,245
Derivative contracts.................................... 1,649,326 -- -- -- 1,649,326
------------ ---------- ----------- ------- ------------
Total current assets.............................. 49,212,604 1,577,532 1,362,171 -- 52,152,307
------------ ---------- ----------- ------- ------------
Oil and natural gas properties, net....................... 79,808,520 191,886 45,658 -- 80,046,064
Other assets
Restricted cash and bonds............................... 5,070,251 25,000 -- -- 5,095,251
Furniture, fixtures and equipment, net.................. 150,221 217,860 70,294 -- 438,375
Receivables from affiliates, net........................ (733,335) 2,527,756 (1,794,421) -- --
Investment in subsidiary................................ 1,000 -- 1,000 (2,000) --
Deferred loan costs, net................................ 19,284,697 -- -- -- 19,284,697
Derivative contracts.................................... 1,937,300 -- -- -- 1,937,300
------------ ---------- ----------- ------- ------------
Total other assets................................ 25,710,134 2,770,616 (1,723,127) (2,000) 26,755,623
------------ ---------- ----------- ------- ------------
$154,731,258 $4,540,034 $ (315,298) $(2,000) $158,953,994
============ ========== =========== ======= ============
LIABILITIES AND STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued
liabilities......................................... $28,187,227 $ (26,095) $ 67,623 -- $ 28,228,755
Accounts payable subject to
renegotiation....................................... 10,119,904 -- -- -- 10,119,904
Accrued interest...................................... 586,806 -- -- -- 586,806
Notes payable......................................... 82,643 -- -- -- 82,643
Current maturities of long-term debt.................. 20,000,000 -- -- -- 20,000,000
------------ ---------- ----------- ------- ------------
58,976,580 (26,095) 67,623 -- 59,018,108
------------ ---------- ----------- ------- ------------
Senior secured notes.................................. 85,512,472 -- -- -- 85,512,472
------------ ---------- ----------- ------- ------------
Commitments and Contingencies
Stockholders' equity (capital deficit):
Class A common stock.................................... 3,683 1,000 1,000 (2,000) 3,683
Class B common stock.................................... 650 -- -- -- 650
Additional paid in capital.............................. 25,380,183 -- -- -- 25,380,183
Retained earnings (deficit)............................. (15,142,310) 4,565,129 (383,921) -- (10,961,102)
------------ ---------- ----------- ------- ------------
Total capital deficit............................. 10,242,206 4,566,129 (382,921) (2,000) 14,423,414
------------ ---------- ----------- ------- ------------
$154,731,258 $4,540,034 $ (315,298) $ (2000) $158,953,994
============ ========== =========== ======= ============
</Table>
F-31
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1998
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ ---------- ------------ ------------ ------------
Revenues and other:
Oil and natural gas
revenues.............. $ 24,011,943 $ 635,154 $ 1,824,953 $ (635,154) $ 25,836,896
Loss on marketable
securities............ -- -- (27,414) -- (27,414)
Other................... 257,358 382,894 46,835 (144,443) 542,644
------------ ---------- ------------ ------------ ------------
Total revenues
and
other.......... 24,269,301 1,018,048 1,844,374 (779,597) 26,352,126
------------ ---------- ------------ ------------ ------------
Expenses:
Lease operating
expense............... 17,263,719 251,688 714,278 (779,597) 17,450,088
Workover expense........ 509,086 6,619 83,985 -- 599,690
Production taxes........ 543,298 139 95,518 -- 638,955
Depreciation, depletion
and amortization...... 11,722,824 -- 674,976 -- 12,397,800
General and
administrative........ 3,253,853 24,323 48,571 -- 3,326,747
Interest expense........ 7,725,395 -- 8,536 -- 7,733,931
------------ ---------- ------------ ------------ ------------
Total expenses... 41,018,175 282,769 1,625,864 (779,597) 42,147,211
------------ ---------- ------------ ------------ ------------
Income (loss) before
income taxes............ (16,748,874) 735,279 218,510 -- (15,795,085)
Provision for income
taxes................... (250,000) 250,000 -- -- --
------------ ---------- ------------ ------------ ------------
Income (loss) from
operations before equity
in net income (loss) of
subsidiaries............ (16,498,874) 485,279 218,510 -- (15,795,085)
Equity in net income
(loss) of
subsidiaries............ 485,279 -- (16,013,595) 15,528,316 --
------------ ---------- ------------ ------------ ------------
Net income (loss)......... $(16,013,595) $ 485,279 $(15,795,085) $ 15,528,316 $(15,795,085)
============ ========== ============ ============ ============
</Table>
F-32
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1999
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- --------- ----------- ------------ ------------
Revenues and other:
Oil and natural gas
revenues.............. $34,754,526 $619,323 $ 1,515,817 $ (619,323) $36,270,343
Other.................... 1,484,854 230,145 10,539 (230,145) 1,495,393
----------- -------- ----------- ----------- -----------
Total revenues
and other...... 36,239,380 849,468 1,526,356 (849,468) 37,765,736
----------- -------- ----------- ----------- -----------
Expenses:
Lease operating expense.. 17,648,597 256,829 405,658 (2,768,807) 15,542,277
Workover expense......... 2,202,197 5,409 202,804 -- 2,410,410
Production taxes......... 645,187 1,071 58,597 -- 704,855
Depreciation, depletion
and amortization...... 10,642,271 -- 397,764 -- 11,040,035
General and
administrative........ 3,237,542 3,095 76,757 1,919,339 5,236,733
Interest expense......... 11,978,893 -- 2,567 -- 11,981,460
----------- -------- ----------- ----------- -----------
Total expenses... 46,354,687 266,404 1,144,147 (849,468) 46,915,770
----------- -------- ----------- ----------- -----------
Income (loss) before income
taxes.................... (10,115,307) 583,064 382,209 -- (9,150,034)
Provision for income
taxes.................... (200,000) 200,000 -- -- --
----------- -------- ----------- ----------- -----------
Income (loss) from
operations before equity
in net income (loss) of
subsidiaries............. (9,915,307) 383,064 382,209 -- (9,150,034)
Equity in net income (loss)
of subsidiaries.......... 383,064 -- (9,532,243) 9,149,179 --
----------- -------- ----------- ----------- -----------
Net income (loss).......... $(9,532,243) $383,064 $(9,150,034) $ 9,149,179 $(9,150,034)
=========== ======== =========== =========== ===========
</Table>
F-33
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- ---------- ----------- ------------ ------------
Revenues and other:
Oil and natural gas
revenues............ $69,711,445 $2,063,554 $ 1,677,055 $ -- $73,452,054
Gain on marketable
securities.......... -- -- 995,180 -- 995,180
Other.................. 118,969 (33,429) 6,622 (63,758) 28,404
----------- ---------- ----------- ----------- -----------
Total revenues
and other.... 69,830,414 2,030,125 2,678,857 (63,758) 74,475,638
----------- ---------- ----------- ----------- -----------
Expenses:
Lease operating
expense............. 20,394,732 279,267 524,861 (1,713,501) 19,485,359
Workover expense....... 6,575,999 8,951 64,124 -- 6,649,074
Production taxes....... 1,865,008 882 102,452 -- 1,968,342
Depreciation, depletion
and amortization.... 12,937,325 260,403 308,749 -- 13,506,477
General and
administrative...... 1,730,939 245,094 702,582 1,649,743 4,328,358
Interest expense....... 12,736,056 -- 21,807 -- 12,757,863
----------- ---------- ----------- ----------- -----------
Total
expenses..... 56,240,059 794,597 1,724,575 (63,758) 58,695,473
----------- ---------- ----------- ----------- -----------
Income before
reorganization costs
and income taxes....... 13,590,355 1,235,528 954,282 -- 15,780,165
Reorganization costs..... 21,487,191 -- -- -- 21,487,191
----------- ---------- ----------- ----------- -----------
Income (loss) before
income taxes........... (7,896,836) 1,235,528 954,282 -- (5,707,026)
Provision for income
taxes.................. 79,000 -- -- -- 79,000
----------- ---------- ----------- ----------- -----------
Income (loss) from
operations before
equity in net income
(loss) of
subsidiaries........... (7,975,836) 1,235,528 954,282 -- (5,786,026)
----------- ---------- ----------- ----------- -----------
Equity in net income
(loss) of
subsidiaries........... 1,235,528 -- (6,740,308) 5,504,780 --
----------- ---------- ----------- ----------- -----------
Net income (loss)........ $(6,740,308) $1,235,528 $(5,786,026) $ 5,504,780 $(5,786,026)
=========== ========== =========== =========== ===========
</Table>
F-34
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2000
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- --------- ---------- ------------ ------------
Revenues and other:
Oil and natural gas
revenues.............. $24,843,405 $385,692 $ 958,166 $ -- $26,187,263
Gain on marketable
securities............ -- -- 902,696 -- 902,696
Other.................... 416,170 14,691 3,136 (14,691) 419,306
----------- -------- ---------- ----------- -----------
Total revenues
and other...... 25,259,575 400,383 1,863,998 (14,691) 27,509,265
----------- -------- ---------- ----------- -----------
Expenses:
Lease operating
expense............... 7,226,627 140,904 248,701 (812,090) 6,804,142
Workover expense......... 1,658,437 5,144 33,317 -- 1,696,898
Production taxes......... 655,784 -- 56,657 -- 712,441
Depreciation, depletion
and amortization...... 5,016,626 5,195 372,501 -- 5,394,322
General and
administrative........ 1,335,483 39,811 274,180 797,399 2,446,873
Interest expense......... 6,723,199 -- 10,051 -- 6,733,250
----------- -------- ---------- ----------- -----------
Total expenses... 22,616,156 191,054 995,407 (14,691) 23,787,926
----------- -------- ---------- ----------- -----------
Income before
reorganization costs..... 2,643,419 209,329 868,591 -- 3,721,339
Reorganization costs....... 914,809 -- -- -- 914,809
----------- -------- ---------- ----------- -----------
Income from operations
before equity in net
income of subsidiaries... 1,728,610 209,329 868,591 -- 2,806,530
Equity in net income of
subsidiaries............. 209,329 -- 1,937,939 (2,147,268) --
----------- -------- ---------- ----------- -----------
Net income................. $ 1,937,939 $209,329 $2,806,530 $(2,147,268) $ 2,806,530
=========== ======== ========== =========== ===========
</Table>
F-35
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE SIX MONTHS ENDED JUNE 30, 2001
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- ---------- ----------- ------------ ------------
Revenues and other:
Oil and natural gas
revenues................. $51,769,096 $2,158,595 $ 738,796 $ -- $54,666,487
Loss on marketable
securities............... -- -- (417,180) -- (417,180)
Gain on derivative
contracts................ 3,586,626 -- -- -- 3,586,626
Other....................... 890,030 27,382 5,333 (25,823) 896,922
----------- ---------- ----------- --------- -----------
Total revenues and
other............. 56,245,752 2,185,977 326,949 (25,823) 58,732,855
----------- ---------- ----------- --------- -----------
Expenses:
Lease operating expense..... 10,988,831 122,820 106,442 (737,664) 10,480,429
Workover expense............ 3,307,246 14,836 18,047 -- 3,340,129
Production taxes............ 1,328,642 47 12,887 -- 1,341,576
Depreciation, depletion and
amortization............. 6,949,968 218,406 93,669 -- 7,262,043
General and
administrative........... 1,593,581 294,639 549,170 711,841 3,149,231
Interest expense............ 6,254,469 -- 21,781 -- 6,276,250
----------- ---------- ----------- --------- -----------
Total expenses...... 30,422,737 650,748 801,996 (25,823) 31,849,658
----------- ---------- ----------- --------- -----------
Income (loss) before
reorganization costs and
income taxes................ 25,823,015 1,535,229 (475,047) -- 26,883,197
Reorganization costs.......... 5,428,119 -- 1,882,989 -- 7,311,108
----------- ---------- ----------- --------- -----------
Income (loss) before income
taxes....................... 20,394,896 1,535,229 (2,358,036) -- 19,572,089
Provision for income taxes.... 391,441 -- -- -- 391,441
----------- ---------- ----------- --------- -----------
Income (loss) from operations
before equity in net loss of
subsidiaries................ 20,003,455 1,535,229 (2,358,036) -- 19,180,648
Equity in net loss of
subsidiaries................ (822,807) -- -- 822,807 --
----------- ---------- ----------- --------- -----------
Net income (loss)............. $19,180,648 $1,535,229 $(2,358,036) $ 822,807 $19,180,648
=========== ========== =========== ========= ===========
</Table>
F-36
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1998
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ --------- ------------ ------------ ------------
Cash flows from operating
activities:
Net income (loss).............. $(16,013,595) $ 485,279 $(15,795,085) $ 15,528,316 $(15,795,085)
Adjustments to reconcile net
income (loss) to net cash
provided by operating
activities:
Equity in undistributed
income of subsidiaries..... (485,279) -- 16,013,595 (15,528,316) --
Depletion, depreciation and
amortization............... 11,722,824 -- 674,976 -- 12,397,800
Loss on sale of marketable
securities................. -- -- 27,414 -- 27,414
Accretion of bond interest... (24,400) -- -- -- (24,400)
Loss on sale of equipment.... 5,373 -- -- -- 5,373
Changes in assets and
liabilities:
Accounts receivable........ (519,573) (90,085) (154,030) 179,591 (584,097)
Prepaid expenses........... (441,030) 2,529 (60,755) -- (499,256)
Receivables from
affiliates.............. (105,828) (193,881) 142,045 -- (157,664)
Accounts payable and
accrued liabilities..... 11,910,830 (477) 67,377 (179,591) 11,798,139
------------ --------- ------------ ------------ ------------
Net cash provided by
operating
activities............ 6,049,322 203,365 915,537 -- 7,168,224
------------ --------- ------------ ------------ ------------
Cash flows from investing
activities:
Proceeds from sales of
marketable securities........ -- -- 319,217 -- 319,217
Additions to oil and natural
gas properties............... (71,063,219) (2,529) (926,398) -- (71,992,146)
Purchase of furniture, fixtures
and equipment................ (276,696) (50,022) -- -- (326,718)
Proceeds from disposal of
equipment.................... 73,905 -- -- -- 73,905
------------ --------- ------------ ------------ ------------
Net cash used in
investing
activities............ (71,266,010) (52,551) (607,181) -- (71,925,742)
------------ --------- ------------ ------------ ------------
Cash flows from financing
activities:
Proceeds from long-term debt... 66,460,000 -- -- -- 66,460,000
Payments of loan fees.......... (1,142,550) -- -- -- (1,142,550)
Decrease in notes payable...... (16,812) -- (147,437) -- (164,249)
------------ --------- ------------ ------------ ------------
Net cash provided by
(used in) financing
activities............ 65,300,638 -- (147,437) -- 65,153,201
------------ --------- ------------ ------------ ------------
Net increase in cash and cash
equivalents.................... 83,950 150,814 160,919 -- 395,683
Cash and cash equivalents --
beginning of year.............. 2,024,154 91,096 161,876 -- 2,277,126
------------ --------- ------------ ------------ ------------
Cash and cash equivalents -- end
of year........................ $ 2,108,104 $ 241,910 $ 322,795 $ -- $ 2,672,809
============ ========= ============ ============ ============
</Table>
F-37
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1999
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ --------- ----------- ------------ ------------
Cash flows from operating activities:
Net income (loss).......................... $ (9,532,243) $ 383,064 $(9,150,034) $ 9,149,179 $ (9,150,034)
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Equity in undistributed income (loss) of
subsidiaries........................... (383,064) -- 9,532,243 (9,149,179) --
Depletion, depreciation and
amortization........................... 10,642,271 -- 397,764 -- 11,040,035
Accretion of bond interest............... (219,478) -- -- -- (219,478)
Changes in assets and liabilities:
Accounts receivable.................... (3,103,376) (29,373) 16,758 30,678 (3,085,313)
Prepaid expenses....................... (298,986) -- 59,682 -- (239,304)
Receivables from affiliates............ (6,071) (204,918) (541,565) -- (752,554)
Accounts payable and accrued
liabilities......................... 14,646,330 50 (82,058) (30,678) 14,533,644
------------ --------- ----------- ----------- ------------
Net cash provided by operating
activities........................ 11,745,383 148,823 232,790 -- 12,126,996
------------ --------- ----------- ----------- ------------
Cash flows from investing activities:
Purchase of marketable securities.......... -- -- (232,268) -- (232,268)
Additions to oil and natural gas
properties............................... (13,599,825) 2,529 24,852 -- (13,572,444)
Purchase of furniture, fixtures and
equipment................................ (45,017) 4,832 -- -- (40,185)
Proceeds from disposal of equipment........ -- 4,059 -- -- 4,059
Proceeds from sales of oil and natural gas
properties............................... 2,262,300 -- -- -- 2,262,300
Purchase of restricted cash and bonds...... (3,664,957) -- -- -- (3,664,957)
Proceeds from restricted marketable
securities............................... 3,300,000 -- -- -- 3,300,000
------------ --------- ----------- ----------- ------------
Net cash provided by (used in)
investing activities.............. (11,747,499) 11,420 (207,416) -- (11,943,495)
------------ --------- ----------- ----------- ------------
Cash flows from financing activities:
Payments of long-term debt................. (300,000) -- -- -- (300,000)
Payments of loan fees...................... (20,927) -- -- -- (20,927)
Increase in notes payable.................. 202,453 -- 76,160 -- 278,613
------------ --------- ----------- ----------- ------------
Net cash provided by (used in)
financing activities.............. (118,474) -- 76,160 -- (42,314)
------------ --------- ----------- ----------- ------------
Net increase (decrease) in cash and cash
equivalents................................ (120,590) 160,243 101,534 -- 141,187
Cash and cash equivalents -- beginning of
year....................................... 2,108,104 241,910 322,795 -- 2,672,809
------------ --------- ----------- ----------- ------------
Cash and cash equivalents -- end of year..... $ 1,987,514 $ 402,153 $ 424,329 $ -- $ 2,813,996
============ ========= =========== =========== ============
</Table>
F-38
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2000
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ ---------- ----------- ------------ ------------
Cash flows from operating activities:
Net income (loss)................................ $ (6,740,308) $1,235,528 $(5,786,026) $ 5,504,780 $ (5,786,026)
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating
activities:
Equity in undistributed income (loss) of
subsidiaries................................. (1,235,528) -- 6,740,308 (5,504,780) --
Depletion, depreciation and amortization....... 12,937,325 260,403 308,749 -- 13,506,477
Gain on sale of marketable securities.......... -- -- (995,179) -- (995,179)
Accretion of bond interest..................... (138,040) -- -- -- (138,040)
Reorganization items........................... 21,487,191 -- -- -- 21,487,191
Changes in assets and liabilities:
Accounts receivable.......................... (14,962,629) (236,683) (183,003) 258,546 (15,123,769)
Prepaid expenses............................. (48,419) (365,965) (437,093) -- (851,477)
Receivables from affiliates.................. 1,629,900 (827,722) (599,107) -- 203,071
Accounts payable and accrued liabilities..... 12,343,523 56,216 205,376 (258,546) 12,346,569
Pre-petition liabilities subject to
compromise................................. 18,043,910 -- -- -- 18,043,910
------------ ---------- ----------- ------------ ------------
Net cash provided by (used in) operating activities
before reorganization items...................... 43,316,925 121,777 (745,975) -- 42,692,727
------------ ---------- ----------- ------------ ------------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid........ (2,536,788) -- -- -- (2,536,788)
Interest earned during bankruptcy................ 538,841 -- -- -- 538,841
------------ ---------- ----------- ------------ ------------
Net cash used in reorganization items............ (1,997,947) -- -- -- (1,997,947)
------------ ---------- ----------- ------------ ------------
Net cash provided by (used in) operating
activities..................................... 41,318,978 121,777 (745,975) -- 40,694,780
------------ ---------- ----------- ------------ ------------
Cash flows from investing activities:
Purchase of marketable securities................ -- -- (1,118,069) -- (1,118,069)
Proceeds from sales of marketable securities..... -- -- 1,874,245 -- 1,874,245
Additions to oil and natural gas properties...... (10,180,040) (636,620) (60,997) -- (10,877,657)
Purchase of furniture, fixtures and equipment.... (20,408) -- (10,872) -- (31,280)
Proceeds from sales of oil and natural gas
properties..................................... -- -- 389,971 -- 389,971
Purchase of restricted cash and bonds............ (355,000) -- -- -- (355,000)
------------ ---------- ----------- ------------ ------------
Net cash provided by (used in) investing
activities..................................... (10,555,448) (636,620) 1,074,278 -- (10,117,790)
------------ ---------- ----------- ------------ ------------
Cash flows from financing activities:
Payments of long-term debt....................... (376,500) -- -- -- (376,500)
Increase (decrease) in notes payable............. 51,613 -- (76,160) -- (24,547)
------------ ---------- ----------- ------------ ------------
Net cash used in financing activities............ (324,887) -- (76,160) -- (401,047)
------------ ---------- ----------- ------------ ------------
Net increase (decrease) in cash and cash
equivalents.................................... 30,438,643 (514,843) 252,143 -- 30,175,943
Cash and cash equivalents -- beginning of year... 1,987,514 402,153 424,329 -- 2,813,996
------------ ---------- ----------- ------------ ------------
Cash and cash equivalents -- end of year......... $ 32,426,157 $ (112,690) $ 676,472 $ -- $ 32,989,939
============ ========== =========== ============ ============
</Table>
F-39
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2000
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- --------- ----------- ------------ ------------
Cash flow from operating activities:
Net income...................................... $1,937,939 $209,329 $ 2,806,530 $(2,147,268) $ 2,806,530
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Equity in undistributed income of
subsidiaries................................ (209,329) -- (1,937,939) 2,147,268 --
Depletion, depreciation and amortization...... 5,016,626 5,195 372,501 -- 5,394,322
Gain on sale of marketable securities......... -- -- (902,696) -- (902,696)
Accretion of bond interest.................... (82,229) -- -- -- (82,229)
Reorganization items.......................... 914,809 -- -- -- 914,809
Changes in assets and liabilities:
Accounts receivable......................... 470,491 60,257 (178,279) -- 352,469
Prepaid expenses............................ 50,047 -- (483,927) -- (433,880)
Receivables from affiliates................. 885,218 (227,723) (431,267) -- 226,228
Accounts payable and accrued liabilities.... 3,457,728 29,089 219,347 -- 3,706,164
Pre-petition liabilities subject to
compromise................................ (1,424,676) -- -- -- (1,424,676)
----------- --------- ----------- ------------ -----------
Net cash provided by (used in) operating
activities before reorganization
items................................... 11,016,624 76,147 (535,730) -- 10,557,041
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid....... (610,710) -- -- -- (610,710)
Interest earned during bankruptcy............... 41,654 -- -- -- 41,654
----------- --------- ----------- ------------ -----------
Net cash used for reorganization items.... (569,056) -- -- -- (569,056)
Net cash provided by (used in) operating
activities.............................. 10,447,568 76,147 (535,730) -- 9,987,985
Cash flow from investing activities:
Purchase of marketable securities............... -- -- (630,321) -- (630,321)
Proceeds from sales of marketable securities.... -- -- 1,181,904 -- 1,181,904
Additions to oil and natural gas properties..... (2,751,068) (328,870) (529,203) -- (3,609,141)
Purchase of furniture, fixtures and equipment... (11,163) -- (6,293) -- (17,456)
Proceeds from sales of oil and natural gas
properties.................................... -- -- 381,500 -- 381,500
Purchase of restricted cash and bonds........... (161,000) -- -- -- (161,000)
----------- --------- ----------- ------------ -----------
Net cash provided by (used in) investing
activities.............................. (2,923,231) (328,870) 397,587 -- (2,854,514)
Cash flows from financing activities:
Payments of long-term debt...................... (381,500) -- -- -- (381,500)
Decrease in notes payable....................... (211,013) -- (76,160) -- (287,173)
----------- --------- ----------- ------------ -----------
Net cash used in financing activities..... (592,513) -- (76,160) -- (668,673)
Net increase (decrease) in cash and cash
equivalents..................................... 6,931,824 (252,723) (214,303) -- 6,464,798
Cash and cash equivalents -- beginning of
period.......................................... 1,987,514 402,153 424,329 -- 2,813,996
----------- --------- ----------- ------------ -----------
Cash and cash equivalents -- end of period....... $8,919,338 $149,430 $ 210,026 $ -- $ 9,278,794
=========== ========= =========== ============ ===========
</Table>
F-40
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30, 2001
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
-------------- ---------- ------------ ------------ -------------
Cash flow from operating activities:
Net income (loss)................................. $ 19,180,648 $1,535,229 $ (2,358,036) $ 822,807 $ 19,180,648
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Equity in undistributed loss of subsidiaries.... 822,807 -- -- (822,807) --
Depletion, depreciation and amortization........ 6,949,967 218,407 93,668 -- 7,262,042
Amortization of bond discount................... 262,472 -- -- -- 262,472
Amortization of deferred loan costs............. 206,291 -- -- -- 206,291
Loss on sale of marketable securities........... -- -- 417,180 -- 417,180
Accretion of bond interest...................... (45,606) -- -- -- (45,606)
Loss on sale of equipment....................... 7,042 -- -- -- 7,042
Reorganization items............................ 7,311,108 -- -- -- 7,311,108
Gain on derivatives contracts................... (3,586,626) -- -- -- (3,586,626)
Changes in assets and liabilities:
Deposit of restricted cash.................... (13,541,895) (25,000) -- -- (13,566,895)
Accounts receivable........................... 3,085,172 (378,152) (57,775) -- 2,649,245
Prepaid expenses.............................. (111,918) 365,831 24,605 -- 278,518
Receivables from affiliates................... (554,783) (562,245) 696,317 -- (420,711)
Accounts payable and accrued liabilities...... (6,523,301) (82,361) 1,033,542 -- (5,572,120)
Accounts payable subject to renegotiation..... 10,119,904 -- -- -- 10,119,904
Pre-petition liabilities subject to
compromise.................................. (44,242,039) -- -- -- (44,242,039)
-------------- ---------- ------------ ------------ -------------
Net cash provided by (used in) operating
activities before reorganization items.... (20,660,757) 1,071,709 (150,499) -- (19,739,547)
-------------- ---------- ------------ ------------ -------------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid......... (5,819,922) -- -- -- (5,819,922)
Interest earned during bankruptcy................. 945,722 -- -- -- 945,722
-------------- ---------- ------------ ------------ -------------
Net cash used for reorganization items...... (4,874,200) -- -- -- (4,874,200)
-------------- ---------- ------------ ------------ -------------
Net cash provided by (used in) operating
activities................................ (25,534,957) 1,071,708 (150,498) -- (24,613,747)
-------------- ---------- ------------ ------------ -------------
Cash flow from investing activities:
Purchase of marketable securities................. -- -- (159,897) -- (159,897)
Proceeds from sales of marketable securities...... -- -- 236 -- 236
Additions to oil and natural gas properties....... (3,072,532) (11,549) (255,121) -- (3,339,202)
Purchase of furniture, fixtures and equipment..... (82,865) (199,256) (53,895) -- (336,016)
Proceeds from disposal of equipment............... 6,500 -- -- -- 6,500
Proceeds from sales of oil and natural gas
properties...................................... 2,225,529 -- -- -- 2,225,529
Purchase of restricted cash and bonds............. (375,000) -- -- -- (375,000)
-------------- ---------- ------------ ------------ -------------
Net cash used in investing activities....... (1,298,368) (210,805) (468,677) -- (1,977,850)
-------------- ---------- ------------ ------------ -------------
Cash flows from financing activities:
Proceeds from unit offering....................... 113,444,294 -- -- -- 113,444,294
Payments of long-term debt........................ (104,323,500) -- -- -- (104,323,500)
Payment of loan fees.............................. (2,303,149) -- -- -- (2,303,149)
Decrease in notes payable......................... (251,237) -- -- -- (251,237)
-------------- ---------- ------------ ------------ -------------
Net cash provided by financing activities... 6,566,408 -- -- -- 6,566,408
-------------- ---------- ------------ ------------ -------------
Net increase (decrease) in cash and cash
equivalents....................................... (20,266,917) 860,903 (619,175) -- (20,025,189)
Cash and cash equivalents -- beginning of period.... 32,426,157 (112,691) 676,473 -- 32,989,939
-------------- ---------- ------------ ------------ -------------
Cash and cash equivalents -- end of period.......... $ 12,159,240 $ 748,212 $ 57,298 $ -- $ 12,964,750
============== ========== ============ ============ =============
</Table>
F-41
WE HAVE NOT AUTHORIZED ANY DEALER, SALESPERSON OR OTHER PERSON TO GIVE ANY
INFORMATION OR REPRESENT ANYTHING TO YOU OTHER THAN THE INFORMATION CONTAINED IN
THIS PROSPECTUS. YOU MUST NOT RELY ON UNAUTHORIZED INFORMATION OR
REPRESENTATIONS. THIS PROSPECTUS DOES NOT OFFER TO SELL OR ASK FOR OFFERS TO BUY
ANY OF THE SECURITIES IN ANY JURISDICTION WHERE IT IS UNLAWFUL, WHERE THE PERSON
MAKING THE OFFER IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON WHO CANNOT LEGALLY
BE OFFERED THE SECURITIES. THE INFORMATION IN THIS PROSPECTUS IS CURRENT ONLY AS
OF THE DATE ON ITS COVER, AND MAY CHANGE AFTER THAT DATE. FOR ANY TIME AFTER THE
COVER DATE OF THIS PROSPECTUS, WE DO NOT REPRESENT THAT OUR AFFAIRS ARE THE SAME
AS DESCRIBED OR THAT THE INFORMATION IN THIS PROSPECTUS IS CORRECT NOR DO WE
IMPLY THOSE THINGS BY DELIVERING THIS PROSPECTUS OR SELLING SECURITIES TO YOU.
---------------------
TABLE OF CONTENTS
<Table>
<Caption>
PAGE
----
Summary.............................. 1
Risk Factors......................... 11
Forward-Looking Statements........... 20
The Company.......................... 21
The Exchange Offer................... 22
Use of Proceeds...................... 31
Capitalization....................... 32
Selected Historical Consolidated
Financial Data..................... 33
Unaudited Condensed Pro Forma
Financial Data..................... 35
Operating Data....................... 37
Reserve Data......................... 37
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 38
Business and Properties.............. 49
Management........................... 67
Principal Stockholders............... 69
Certain Relationships and Related
Transactions....................... 69
Description of the Senior
Secured Notes...................... 71
Plan of Distribution................. 118
Registration Rights.................. 119
Material United States Federal Income
Tax Considerations................. 121
Legal Matters........................ 125
Reserve Engineers.................... 125
Available Information................ 125
Glossary of Oil and Natural Gas
Terms.............................. 127
Index to Financial Statements........ F-1
</Table>
TRI-UNION DEVELOPMENT
CORPORATION
[TRI-UNION DEVELOPMENT CORPORATION LOGO]
OFFER TO EXCHANGE
$130,000,000 REGISTERED
12.5% SENIOR SECURED NOTES
DUE 2006 FOR ALL
OUTSTANDING UNREGISTERED
12.5% SENIOR SECURED NOTES
DUE 2006
PAYMENT UNCONDITIONALLY
GUARANTEED
ON A
SENIOR SECURED BASIS BY
TRI-UNION OPERATING COMPANY
--------
PROSPECTUS
--------
, 2001
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Tri-Union Development Corporation
Article 2.02-1 of the Texas Business Corporation Act ("TBCA") provides that
a corporation may indemnify any director or officer who was, is or is threatened
to be made a named defendant or respondent in a proceeding because he is or was
a director or officer, provided that the director or officer (i) conducted
himself in good faith, (ii) reasonably believed (a) in the case of conduct in
his official capacity, that his conduct was in the corporation's best interests,
and/or (b) in other cases, that his conduct was at least not opposed to the
corporation's best interests, and (iii) in the case of any criminal proceeding,
has no reasonable cause to believe his conduct was unlawful.
Subject to certain exceptions, a director or officer may not be indemnified
if he is found liable to the corporation or if he is found liable on the basis
that he improperly received a personal benefit. Under Texas law, reasonable
expenses incurred by a director or officer may be paid or reimbursed by the
corporation in advance of a final disposition of the proceeding after the
corporation receives a written affirmation by the director or officer of his
good faith belief that he has met the standard of conduct necessary for
indemnification and a written undertaking by or on behalf of the director or
officer to repay the amount if it is ultimately determined that the director or
officer is not entitled to indemnification by the corporation. Texas law
requires a corporation to indemnify a director or officer against reasonable
expenses incurred in connection with the proceeding to which such director or
officer is named defendant or respondent because he is or was a director or
officer if he is wholly successful in defense of the proceeding.
Texas law also permits a corporation to purchase and maintain insurance or
another arrangement on behalf of any person who is or was a director or officer
against any liability asserted against him and incurred by him in such a
capacity or arising out of his status as such a director or officer, whether or
not the corporation would have the power to indemnify him against that liability
under Article 2.02-1 of the TBCA.
Tri-Union's Amended and Restated Articles of Incorporation provide that the
liability of directors for monetary damages for an act or omission in the
director's capacity as a director shall be limited to the fullest extent
permissible under Texas law. Texas law does not permit exculpation of liability
in the case of (i) a breach of the director's duty of loyalty to the corporation
or its shareholders, (ii) an act or omission not in good faith that constitutes
a breach of duty of the director to the corporation or that involves intentional
misconduct or a knowing violation of the law, (iii) a transaction from which a
director received an improper benefit, whether or not the benefit resulted from
an action taken within the scope of the director's office or (iv) an act or
omission for which the liability of the director is expressly provided by
statute.
Pursuant to Tri-Union's bylaws, it has a duty to indemnify directors and
board observers to the fullest extent permitted by Texas law. Tri-Union may
indemnify its officers, employees and agents to the same scope and effect as the
foregoing indemnification of directors and board observers.
In addition, Tri-Union may maintain insurance, at its expense, to protect
itself and any director, officer, employee or agent of us or another
corporations, partnership, joint venture, trust or other enterprise against any
such expense, liability or loss, whether or not Tri-Union would have the power
to indemnify such person against such expense, liability or loss as permitted by
law.
The above discussion is not intended to be exhaustive and is respectively
qualified in its entirety by the TBCA and Tri-Union's Amended and Restated
Articles of Incorporation and bylaws.
Tri-Union Operating Company
Section 145 of the Delaware General Corporation Law ("DGCL") provides that
a Delaware corporation may indemnify any person who is, or is threatened to be
made, a party to any
II-1
threatened, pending or completed action, suit or proceeding, whether civil,
criminal, administrative or investigative (other than an action by or in right
of such corporation), by reason of the fact that such person was an officer,
director, employee or agent of such corporation, or is or was serving at the
request of such corporation as a director, officer, employee or agent of another
corporation or enterprise. The indemnity may include expenses (including
attorneys' fees), judgments, fines and amount paid in settlement actually and
reasonably incurred by such person in connection with such action, suit or
proceeding, provided such person acted in good faith and in a manner he
reasonably believed to be in or not opposed to the corporation's best interests
and, with respect to any criminal action or proceeding, had no reasonable cause
to believe that his conduct was illegal. A Delaware corporation may also
indemnify any person who is, or is threatened to be made, a party to any
threatened, pending or completed action or suit by or in the right of the
corporation by reason of the fact that such person was a director, officer,
employee or agent of such corporation, or is or was serving at the request of
such corporation as a director, officer, employee or agent or another
corporation or enterprise. The indemnity may include expenses (including
attorneys' fees) actually and reasonably incurred by such person in connection
with the defense or settlement of such action or suit, provided such person
acted in a manner he reasonably believed to be in or not opposed to the
corporation's best interests except that no indemnification is permitted without
judicial approval if the officer or director is adjudged to be liable to the
corporation. In addition, where an officer or director is successful on the
merits or otherwise in the defense of any action referred to above, the
corporation must indemnify him against the expenses which such officer or
director has actually and reasonably incurred.
Section 145 of the DGCL also authorizes the corporation to purchase and
maintain insurance on behalf of any person who is or was a director, officer,
employee or agent of such corporation, or is or was serving at the request of
such corporation as a director, officer, employee or agent of another
corporation or enterprise against any liability asserted against him and
incurred by him in any such capacity, or arising out of his status as such,
whether or not the corporation would have the power to indemnify him against
such liability under the provisions of Delaware law.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
The following exhibits are filed as part of this Registration Statement:
<Table>
<Caption>
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.
2.2 Agreement and Plan of Merger between Tribo Petroleum
Corporation and Tri-Union Development Corporation, dated
July 27, 2001.
3.1 Restated Articles of Incorporation for Tri-Union Development
Corporation, as amended through July 2001.
3.2 By-laws of Tri-Union Development Corporation as amended and
restated through June 18, 2001.
3.3 Certificate of Incorporation for Tri-Union Operating Company
dated as of November 1, 1974, as amended through May 30,
1996.
3.4 By-laws of Tri-Union Operating Company as amended and
restated through June 18, 2001.
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.
4.2 Purchase Agreement between Tribo Petroleum Corporation,
Tri-Union Development Corporation, Tri-Union Operating
Company and Jefferies & Company Inc., dated June 18,
2001.
</Table>
II-2
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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.
4.4 Equity Registration Rights Agreement by and between Tribo
Petroleum Corporation and Jefferies & Company, Inc.,
dated June 18, 2001.
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.
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.
4.7 Mortgage, Deed of Trust, Assignment of Production, Security
Agreement and Financing Statement of Tri-Union
Development Corporation, dated June 18, 2001.
4.8 Form of Exchange Note.
*5.1 Opinion of Thompson & Knight LLP, dated July 30, 2001.
*8.1 Opinion regarding Tax Matters (included in Exhibit 5.1).
10.1 Amended and Restated Lease Agreement between Tribo
Production Company, Ltd and Tri-Union Development
Corporation, dated June 18, 2001.
10.2 ISDA Master Agreement by and between Bank of America, N.A.
and Tri-Union Development Corporation, dated June 18,
2001.
12.1 Statements regarding Computation of Ratios.
16.1 Letter from Hildago, Banfill, Zlontnik & Kermali, P.C.
21.1 Subsidiaries of Registrant.
*23.1 Consent of BDO Seidman, LLP.
*23.2 Consent of Hildago, Banfill, Zlontnik & Kermali, P.C.
*23.3 Consent of Huddleston & Co., Inc.
*23.4 Consent of Thompson & Knight LLP (included in Exhibit 5.1).
25.1 Statement of Eligibility of Trustee, Form T-1.
99.1 Form of Letter to DTC Participant.
*99.2 Form of Letter to Beneficial Holders.
99.3 Form of Letter of Transmittal.
99.4 Form of Notice of Guaranteed Delivery.
99.5 Form of Exchange Agent Agreement.
</Table>
* Filed herewith
ITEM 22. UNDERTAKINGS.
(a) The undersigned Registrants hereby undertake:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this Registration Statement:
(i) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after
the effective date of this Registration Statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth
in this Registration Statement. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered (if the total
dollar value of securities offered would not exceed
II-3
that which was registered) and any deviation from the low or high end of
the estimated maximum offering range may be reflected in the form of
prospectus filed with the Commission pursuant to Rule 424(b) if, in the
aggregate, the changes in volume and price represent no more than a 20
percent change in the maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in this effective Registration
Statement; and
(iii) To include any material information with respect to the plan
of distribution not previously disclosed in this Registration Statement
or any material change to such information in this Registration
Statement;
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.
(b) The undersigned Registrants hereby undertake that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
Registrants' Annual Report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in this
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(c) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the Registrants pursuant to the provisions referred to in Item 20 of this
Registration Statement, or otherwise, the Registrants have been advised that in
the opinion of the Securities and Exchange Commission such indemnification is
against public policy as expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by the Registrants of expenses incurred or paid by a director,
officer or controlling person of the Registrants in the successful defense of
any action, suit or proceeding) is asserted by such director, officer or
controlling person in connection with the securities being registered, the
Registrants will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate jurisdiction
the question whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final adjudication of such
issue.
(d) The undersigned Registrants hereby undertake to respond to requests for
information that is incorporated by reference into the prospectus pursuant to
Item 4, 10(b), 11 or 13 of this Form, within one business day of receipt of such
request, and to send the incorporated documents by first class mail or other
equally prompt means. This includes information contained in documents filed
subsequent to the effective date of this Registration Statement through the date
of responding to such request.
(e) The undersigned Registrants hereby undertake to supply by means of a
post-effective amendment all information concerning a transaction, and the
company being acquired involved therein, that was not the subject of and
included in this Registration Statement when it became effective.
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Tri-Union
Development Corporation has duly caused this Amended Registration Statement to
be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Houston, State of Texas, on the 11th day of October, 2001.
TRI-UNION DEVELOPMENT CORPORATION
By: /s/ RICHARD BOWMAN
----------------------------------
Richard Bowman
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Act of 1933, this Amended
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ RICHARD BOWMAN President, Chief Executive October 11, 2001
----------------------------------------------------- Officer, Chief Financial
Richard Bowman Officer and Director
(Principal Executive
Officer)
/s/ SUZANNE R. AMBROSE Vice President, Treasurer October 11, 2001
----------------------------------------------------- and Chief Accounting
Suzanne R. Ambrose Officer (Principal
Accounting Officer)
*/s/ G. BRYAN DUTT Director October 11, 2001
-----------------------------------------------------
G. Bryan Dutt
Director
-----------------------------------------------------
Michel T. Halbouty
*/s/ DONALD W. RIEGLE, JR. Director October 11, 2001
-----------------------------------------------------
Donald W. Riegle, Jr.
Director
-----------------------------------------------------
Oliver G. Richard III
</Table>
---------------
* Pursuant to powers of attorney
II-5
Pursuant to the requirements of the Securities Act of 1933, Tri-Union
Operating Company has duly caused this Amended Registration Statement to be
signed on its behalf by the undersigned, thereunto duly authorized, in the City
of Houston, State of Texas, on the 11th day of October, 2001.
TRI-UNION OPERATING COMPANY
By: /s/ RICHARD BOWMAN
----------------------------------
Richard Bowman
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Act of 1933, this Amended
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ RICHARD BOWMAN President, Chief Executive October 11, 2001
----------------------------------------------------- Officer, Chief Financial
Richard Bowman Officer and Director
(Principal Executive
Officer)
/s/ SUZANNE R. AMBROSE Vice President, Treasurer October 11, 2001
----------------------------------------------------- and Chief Accounting
Suzanne R. Ambrose Officer (Principal
Accounting Officer)
</Table>
II-6
EXHIBIT INDEX
<Table>
<Caption>
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.
2.2 Agreement and Plan of Merger between Tribo Petroleum
Corporation and Tri-Union Development Corporation, dated
July 27, 2001.
3.1 Restated Articles of Incorporation for Tri-Union Development
Corporation, as amended through July 2001.
3.2 By-laws of Tri-Union Development Corporation as amended and
restated through June 18, 2001.
3.3 Certificate of Incorporation for Tri-Union Operating Company
dated as of November 1, 1974, as amended through May 30,
1996.
3.4 By-laws of Tri-Union Operating Company as amended and
restated through June 18, 2001.
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.
4.2 Purchase Agreement between Tribo Petroleum Corporation,
Tri-Union Development Corporation, Tri-Union Operating
Company and Jefferies & Company Inc., dated June 18,
2001.
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.
4.4 Equity Registration Rights Agreement by and between Tribo
Petroleum Corporation and Jefferies & Company, Inc.,
dated June 18, 2001.
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.
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.
4.7 Mortgage, Deed of Trust, Assignment of Production, Security
Agreement and Financing Statement of Tri-Union
Development Corporation, dated June 18, 2001.
4.8 Form of Exchange Note.
*5.1 Opinion of Thompson & Knight LLP, dated July 30, 2001.
*8.1 Opinion regarding Tax Matters (included in Exhibit 5.1).
10.1 Amended and Restated Lease Agreement between Tribo
Production Company, Ltd and Tri-Union Development
Corporation, dated June 18, 2001.
10.2 ISDA Master Agreement by and between Bank of America, N.A.
and Tri-Union Development Corporation, dated June 18,
2001.
12.1 Statements regarding Computation of Ratios.
16.1 Letter from Hildago, Banfill, Zlontnik & Kermali, P.C.
21.1 Subsidiaries of Registrant.
*23.1 Consent of BDO Seidman, LLP.
*23.2 Consent of Hildago, Banfill, Zlontnik & Kermali, P.C.
*23.3 Consent of Huddleston & Co., Inc.
*23.4 Consent of Thompson & Knight LLP (included in Exhibit 5.1).
25.1 Statement of Eligibility of Trustee, Form T-1.
99.1 Form of Letter to DTC Participant.
*99.2 Form of Letter to Beneficial Holders.
99.3 Form of Letter of Transmittal.
99.4 Form of Notice of Guaranteed Delivery.
99.5 Form of Exchange Agent Agreement.
</Table>
* Filed herewith