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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 30, 2001
REGISTRATION NO. 333-
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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<Table>
TRI-UNION DEVELOPMENT CORPORATION TRI-UNION OPERATING COMPANY
(Exact name of registrant as specified in its charter) (Exact name of registrant as specified in its 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)
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copies to:
BARRY DAVIS
WILLIAM T. HELLER IV
THOMPSON & KNIGHT, LLP
1200 SMITH, SUITE 3600
HOUSTON, TEXAS 77002
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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. [ ]
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CALCULATION OF REGISTRATION FEE
<Table>
<Caption>
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PROPOSED PROPOSED
TITLE OF EACH CLASS OF SECURITIES AMOUNT TO BE MAXIMUM OFFERING MAXIMUM AGGREGATE AMOUNT OF
TO BE REGISTERED REGISTERED PRICE PER NOTE OFFERING PRICE(1) REGISTRATION FEE
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12.5% Senior Secured Notes due 2006 of
Tri-Union Development Corporation.... $130,000,000 100% $130,000,000 $32,500
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Guarantee of Tri-Union Operating
Company(2)........................... -- -- -- (3)
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</Table>
(1) Estimated solely for purposes of calculating the registration fee in
accordance with Rule 457(f) of the Securities Act of 1933, as amended.
(2) Represents the separate guarantee of Tri-Union Operating Company, a
wholly-owned subsidiary of Tri-Union Development Corporation.
(3) Pursuant to Rule 457(n).
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.
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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 JULY 30, 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
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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 -- "Certain U.S. Federal Income Tax Considerations -- The Exchange
Offer" on page 124 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.
YOU SHOULD CONSIDER CAREFULLY THE "RISK FACTORS" BEGINNING ON PAGE 14
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.
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[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.]
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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."
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 and, since 1999,
have achieved substantial production growth with a limited capital budget.
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 low-risk development projects that we have
only recently begun to exploit. 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, 66% are proved behind pipe and proved undeveloped projects and
the remainder are behind pipe opportunities in the Sacramento Basin that were
not classified as proved at December 31, 2000. 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.
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.
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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 93 development and exploitation projects in our three core areas
through 2002 for approximately $34.2 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
2002 will be focused on 56 development wells and proved behind pipe objectives
onshore Gulf Coast, 8 proved behind pipe and proved undeveloped objectives
offshore Gulf Coast and 29 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. Additionally, we are currently evaluating 82 development
and exploitation projects, principally consisting of behind pipe opportunities
in the Sacramento Basin.
Maintain our geographic focus and operating control. We will concentrate
our activities in our onshore Gulf Coast, offshore Gulf Coast 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 and gives us a
competitive advantage in acquiring new acreage in our core areas of operations.
Our operated properties currently 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 original offering, we agreed to maintain, on a monthly
basis, a rolling two-year hedge program from the closing of this offering 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 RECAPITALIZATION
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 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.
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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. Our subsidiary continued to operate outside of Chapter 11.
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 a portion of
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.
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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............................... Holders of new notes will not generally
be subject to the transfer restrictions
applicable to the old 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
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affected. Holders of the old notes that
do not exchange their old notes for new
notes will, after 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... We issued the old notes as global
securities in fully registered form
without coupons. Beneficial interests
in the old notes that are held by
direct or indirect participants in The
Depository Trust Company (the "DTC")
through uncertificated depository
interests are shown on, and transfers
of the old notes can be made only
through, records maintained in
book-entry form by the DTC with respect
to its participants. If you are a
holder of an old note held in the form
of a book-entry interest and you wish
to tender your old notes for exchange,
you must transmit to the Exchange Agent
on or prior to the expiration of the
exchange offer either:
- a written or facsimile copy of a
properly completed and executed
letter of transmittal and all other
required documents to the address set
forth on the cover page of the letter
of transmittal; or
- a computer-generated message
transmitted by means of the DTC's
Automated Tender Offer Program system
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.
The Exchange Agent must also receive on
or prior to the expiration of the
exchange offer either:
- a timely confirmation of book-entry
transfer of your old notes into the
exchange agent's account at the DTC,
in accordance with the procedure for
book-entry transfers described in
this prospectus under the heading
"The Exchange Offer -- Exchange Offer
Procedures -- Book-Entry Transfer;"
or
- the documents necessary for
compliance with the guaranteed
delivery procedures described below.
Procedure for Tendering Certificated
Old Notes........................... If you are a holder of book-entry
interests in old notes, you are
entitled to receive, in limited
circumstances, in exchange for your
book-entry interests, certificated
notes which are in principal amounts
equal to your book-entry interests. If
you
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hold or acquire certificated old notes
prior to the expiration of the exchange
offer, you must tender your
certificated old notes in accordance
with the procedures described in this
prospectus under the heading "The
Exchange Offer -- Exchange Offer
Procedures -- Certificated Old Notes."
Special Procedures for Beneficial
Owners.............................. If you are the beneficial owner of old
notes and they are registered in the
name of a broker, dealer, commercial
bank, trust company or other nominee,
and you wish to tender your old notes,
you should promptly contact the person
in whose name your old notes are
registered and instruct that person to
tender on your behalf. If you wish to
tender on your own behalf, you must,
prior to completing and executing the
letter of transmittal and delivering
your old notes, either make appropriate
arrangements to register ownership of
the old notes in your name or obtain a
properly completed bond power from the
person in whose name your old notes are
registered. The transfer of registered
ownership may take considerable time
and it may not be possible to complete
prior to the expiration date.
Guaranteed Delivery Procedures...... Holders of old notes who wish to tender
their old notes and whose old notes are
not immediately available or who cannot
deliver their old notes, the letter of
transmittal or any other documents
required by the letter of transmittal
to the Exchange Agent prior to the
expiration date, or who cannot complete
the procedures for book-entry transfer
on a timely basis, must tender their
old notes according to the guaranteed
delivery procedures set forth under the
heading "The Exchange Offer -- Exchange
Offer Procedures -- Guaranteed Delivery
Procedures."
Use of Proceeds..................... We will not receive any cash proceeds
from the issuance of new notes.
Exchange Agent...................... is serving as the exchange
agent in connection with the exchange
offer (the "Exchange Agent").
United States Federal Income Tax
Consequences...................... The exchange of old notes should not be
a taxable event for United States
federal income tax purposes.
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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 will 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 on such old notes, 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 will
be 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,
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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 "Certain United
States Federal Tax Considerations."
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;
- merge or consolidate with any other
person or sell or otherwise dispose
of all of our assets;
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- 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.
Notes Registration Rights; Exchange
Offer............................... Under the terms of the registration
rights agreement between us and
Jeffries & Company, Inc., we agreed to:
- file a registration statement within
60 days after the issuance of the old
notes, enabling the holders of the
old notes to exchange the old notes
for publicly registered notes with
substantially identical terms;
- use our best efforts to cause the
registration statement to become
effective within 120 days after the
issuance of the old notes;
- consummate the exchange offer within
60 days after the effective date of
our registration statement;
- file a shelf registration statement
for the resale of the old notes if we
cannot effect an exchange offer
within the time periods stated above
and in some other circumstances;
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- use our best efforts to cause the
shelf registration statement to be
declared effective;
- use our best efforts to keep the
shelf registration statement effective
until the earlier of two years from
the date of the effectiveness of the
shelf registration statement or the
time when all of the notes covered by
the shelf registration statement have
been sold or when they may be sold
pursuant to Rule 144(k) under the
Securities Act, subject to certain
exceptions; and
- pay additional interest on the old
notes if we do not comply with
certain of our obligations under the
registration rights agreement.
The exchange offer for the old notes is
intended to satisfy our obligations
contained in the registration rights
agreement.
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 14, as well as all other
information set forth in this prospectus.
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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 March 31, 2001 and for the
three months ended March 31, 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 three months ended March 31, 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 balance sheet data as of
March 31, 2001 illustrate the impact that the original offering and our plan
would have had if they had been consummated on such date. 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, THREE MONTHS ENDED MARCH 31,
---------------------------------------- -----------------------------
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 $13,013 $32,139 $32,139
Expenses:
Lease operating.............. 17,450 15,542 19,485 19,485 3,890 5,452 5,452
Workover..................... 600 2,410 6,649 6,649 1,134 1,621 1,621
Production taxes............. 639 705 1,968 1,968 308 769 769
Depreciation, depletion and
amortization.............. 12,398 11,040 13,506 13,506 2,767 3,738 3,738
General and administrative... 3,327 5,237 4,328 4,328 1,186 1,642 1,642
Interest..................... 7,734 11,981 12,758 27,740 3,327 3,112 6,494
-------- ------- ------- -------- ------- ------- -------
Total expenses....... 42,147 46,916 58,695 73,677 12,613 16,335 19,717
Income (loss) before
reorganization costs and
income taxes................. (15,795) (9,150) 15,780 798 400 15,804 12,422
Reorganization costs........... -- -- 21,487 21,487 402 723 723
-------- ------- ------- -------- ------- ------- -------
Income (loss) before income
taxes........................ (15,795) (9,150) (5,707) (20,689) (2) 15,081 11,699
Provision for income taxes..... -- -- 79 -- -- 300 232
-------- ------- ------- -------- ------- ------- -------
Net income (loss).............. $(15,795) $(9,150) $(5,786) $(20,689) $ (2) $14,781 $11,467
======== ======= ======= ======== ======= ======= =======
OTHER FINANCIAL DATA:
Capital expenditures -- oil and
natural gas properties....... $ 71,992 $13,572 $10,878 $ 10,878 $ 1,217 $ 1,381 $ 1,381
Earnings to fixed charges(1)... NM 0.31x 0.60x 0.28x 1.00x 5.33x 2.73x
EBITDA(2)...................... 4,337 13,871 42,045 42,045 6,494 22,654 22,654
EBITDA to cash interest(3)..... 0.56x 1.16x 3.30x 2.59x 1.95x 7.28x 5.58x
</Table>
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<Table>
<Caption>
AT MARCH 31,
----------------------
PRO FORMA
2001 2001
--------- ----------
(IN THOUSANDS, EXCEPT
RATIO DATA)
CONSOLIDATED BALANCE SHEET DATA:
Net property and equipment.................................. $ 85,249 $ 84,111
Total assets................................................ 175,017 139,167
Stockholders' equity (capital deficit)...................... (15,359) 1,684
ACNTA(4).................................................... 607,899 609,329
Notes payable, including current maturities and net of bond
discounts................................................. 104,488 105,414
ACNTA to indebtedness....................................... 5.82x 5.78x
</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. Fixed charges represent interest expense (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
$20.7 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, impairment of oil and natural gas properties and
reorganization costs. 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 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." ACNTA is
calculated using oil and natural gas prices utilized in our year end reserve
report.
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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" 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
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.
SUMMARY HISTORICAL OPERATING DATA
The following table sets forth summary information with respect to our
consolidated operations for the periods shown.
<Table>
<Caption>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
--------------------------- -----------------
1998 1999 2000 2000 2001
------- ------- ------- ------- -------
Production volumes:
Oil and condensate (MBbls).............. 1,030 1,145 1,333 279 353
Natural gas (MMcf)...................... 6,711 7,007 8,314 1,778 2,352
Total (MMcfe)................... 12,890 13,874 16,313 3,452 4,470
Average daily production:
Oil and condensate (Bbls)............... 2,821 3,136 3,643 3,069 3,923
Natural gas (Mcf)....................... 18,387 19,196 22,716 19,539 26,129
Total (Mcfe).................... 35,314 38,011 44,574 37,953 49,667
Average realized prices:(1)
Oil and condensate (per Bbl)............ $ 12.43 $ 17.27 $ 28.95 $ 28.91 $ 29.01
Natural gas (per Mcf)................... 1.94 2.36 4.19 2.49 9.43
Per Mcfe........................ 2.00 2.61 4.50 3.62 7.25
Expenses (per Mcfe):
Lease operating (excluding workover
expense and production taxes)........ $ 1.35 $ 1.12 $ 1.19 $ 1.13 $ 1.22
Workover................................ 0.05 0.17 0.41 0.33 0.36
Production taxes........................ 0.05 0.05 0.12 0.09 0.17
Depreciation, depletion and
amortization......................... 0.96 0.80 0.83 0.80 0.84
General and administrative, net......... 0.26 0.38 0.27 0.34 0.37
</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."
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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
Old notes not exchanged for new notes will continue to be subject to
restrictions on transfer.
Holders of old notes who do not exchange their old notes for new notes will
continue to be subject to the restrictions on transfer of their old notes. In
general, these restrictions require that old notes not be offered or sold unless
registered under the Securities Act or under an exemption from, or in a
transaction not subject to, the Securities Act and applicable state securities
laws. We are not required to, and we do not currently anticipate that we will,
register the old notes under the Securities Act.
Restrictions and conditions may apply to the transfer of new notes under
certain circumstances.
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 pursuant to
the exchange offer in exchange 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 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 such holder's business and such holder has no arrangement with any
person to participate in the distribution of such 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. If any holder is an affiliate of ours, 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 pursuant to the exchange
offer, such 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 pursuant to the
exchange offer must acknowledge that it will 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, pursuant to the
registration rights agreement and subject to certain specified limitations
therein, 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.
Your old notes may not be accepted for exchange if you fail to timely transmit
a letter of transmittal in accordance with the terms of the exchange offer.
To participate in the exchange offer and avoid the restrictions on transfer
of the old notes, holders of old notes must transmit a properly completed letter
of transmittal, including all other documents required by such letter of
transmittal, to the Exchange Agent at one of the addresses set forth below under
"The Exchange Offer -- Exchange Agent" on or prior to the expiration date.
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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. There can be no assurance that you will be able 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" and "Possession, Use and Release of Collateral -- Release."
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.
There can be no assurances that the proceeds obtained from a foreclosure would
be sufficient 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 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."
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." 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."
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.
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Our principal stockholder owns a majority of our class A common stock, which
may prevent new investors from influencing corporate decisions.
Richard Bowman, our principal stockholder and Chief Executive Officer, owns
approximately 55% of our outstanding common stock. 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 common stock in a manner that may
adversely affect you.
Jefferies & Company, Inc. owns a substantial amount of our outstanding common
stock 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.
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.
No assurance can be given as to the liquidity of the trading market that
may develop for the notes, the ability of holders of the notes to sell their
notes or the price at which holders would be able to sell the 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, which if not cured or waived could have a material
adverse effect on us. 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."
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The guarantee by our subsidiary and any guarantees by future subsidiary
guarantors raise certain fraudulent conveyance considerations.
Our obligations under the notes will be fully and unconditionally
guaranteed by our wholly-owned subsidiary, Tri-Union Operating Company, and, in
general, by our future subsidiaries. Tri-Union Operating Company represents less
than 5% of our consolidated net proved oil and natural gas reserves. Various
fraudulent conveyance laws could be utilized by a court to subordinate or avoid
the guarantee. 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.
To the extent that a court were to find that, at the time the guarantees
were entered into, either:
- the guarantee was incurred by our subsidiary 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;
then the court could, among other things, avoid all or a portion of the
guarantee of the notes, 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 of the notes.
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 significant leverage and lack of capital resources may affect our ability
to successfully operate and service our debt obligations.
Our level of indebtedness on a pro forma basis for the original offering as
of March 31, 2001, was $105.4 million (net of bond discounts), as compared to
adjusted EBITDA on a pro forma basis for the year ended December 31, 2000 of
$42.0 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;
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- causing us to be unable to satisfy our amortization payments due on the
notes on June 1, 2002, 2003 and 2004 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 originally
issued, reduced by any amortization payments made prior to the payment
date, together with accrued and unpaid interest to the date of payment;
- causing us to be unable to repurchase, upon a change of control, all of
the outstanding notes at a repurchase price equal to 101% of the
principal amount of the 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 as described in "Description of the
Senior Secured Notes -- Certain Covenants -- Limitation on Sales of
Assets" and "-- 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 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. There can be no assurance that our
operating results and cash flow will be sufficient for payment of the notes and
our other indebtedness and to fund our working capital needs.
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. No assurance can be given that we
will 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," 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
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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
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, the 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 or at 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;
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- 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 have a material adverse effect on our
financial condition, results of operations and reserves.
In order to reduce our exposure to price risks in the sale of oil and
natural gas, we enter into hedging arrangements from time to time. The hedging
arrangements, however, only generally apply to a portion of our production and
provide only limited price protection against fluctuations in the oil and
natural gas markets. Please read "-- Hedging transactions may limit our
potential profits from operations."
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. We cannot assure you that the new wells
we drill will be productive or that we will 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, it will adversely effect our financial results. 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,
subject to certain conditions, to enter into oil and
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natural gas price hedging arrangements with respect to a portion of our expected
production. Our hedging arrangements may include futures contracts on the NYMEX.
While intended to reduce the effects of volatile oil and natural gas prices,
such 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. 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 expenses and required amortization payments while the notes
are outstanding. 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.
Potential inability to adequately replace our reserves may adversely impact
our ability to sustain production and our long-term financial performance.
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 above 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.
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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 currently maintain insurance coverage that we consider adequate and
customary in the oil and natural gas industry. However, 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, it could adversely effect our financial
condition and operations. Also, we cannot predict the continued availability of
insurance at premium levels that, in our sole discretion, justify its purchase.
Our industry is extremely competitive and many of our competitors have
superior resources.
The energy industry is extremely competitive. This is especially true with
regard to exploration for, and development and production of, new sources of oil
and natural gas. As an independent producer of oil and natural gas, we encounter
substantial competition in acquiring properties suitable for exploration, in
contracting for drilling equipment and other services, in marketing oil and
natural gas and in securing trained personnel. We frequently compete against
companies that have substantially larger financial resources, staffs and
facilities. If we directly compete against one of those larger companies in a
desired acquisition of oil and natural gas properties or in the hiring of
experienced and skilled personnel, we may not have the resources available to
obtain the desired result. Therefore, we must carefully select our acquisition
prospects and personnel.
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, R. Kelly
Plato, Jeffrey T. Janik and Suzanne R. Ambrose. The loss of the services of
these key personnel could have a material adverse effect on our operations. We
do not currently have employment contracts with these key personnel and do not
currently maintain key man life insurance on their lives. We intend to enter
into employment agreements with our key personnel in the near future. 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.
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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. In
addition, the production, handling, storage, transportation and disposal of oil
and natural gas, their by-products and other substances and wastes generated,
produced or used in connection with oil and natural gas operations are regulated
under federal, state and local laws and regulations relating to the protection
of health and the environment. These laws and regulations may impose
increasingly strict requirements for water and air pollution control, spill
cleanups and solid waste management. Our failure to meet any of the foregoing
requirements could result in a suspension of our operations, as well as
administrative, civil, and even criminal, penalties.
We may not be able to profitably sell all of the oil and natural gas we
produce.
The marketability of our oil and natural gas production depends upon the
availability and capacity of natural gas gathering systems, pipelines and
processing facilities. If such capacity is not available, we might have to
shut-in 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.
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" 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;
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- 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.
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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
("Reunion"). Tri-Union Operating Company, our wholly-owned subsidiary, is a
Delaware corporation that has only limited assets, with 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.
On March 14, 2000, we filed for bankruptcy protection under Chapter 11 of
the U.S. Bankruptcy Code. Our subsidiary continued to operate outside of Chapter
11. 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.
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.
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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., which then sold a portion of 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."
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 identical in all
material respects to the terms of the old notes, except that the new notes will
not
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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."
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."
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
(the "Exchange Agent") and by timely public announcement communicated,
unless otherwise required by applicable law or regulation, by making
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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.
General Procedures. A holder of an old note may tender the same by
properly completing and signing the letter of transmittal or a copy of the
letter of transmittal and delivering the same, together with the certificate or
certificates representing the old notes being tendered and any required
signature guarantees or a timely confirmation of a book-entry transfer pursuant
to the procedure described below, to the Exchange Agent at its address set forth
below under "-- Exchange Agent" on prior to the expiration date or by complying
with the guaranteed delivery procedures described below.
If tendered old notes are registered in the name of the signer of the
letter of transmittal and the new notes to be issued in exchange are to be
issued (and any untendered old notes are to be reissued) in the name of the
registered holder, the signature of the signer need not be guaranteed. In any
other case, the tendered old notes must be endorsed or accompanied by written
instruments of transfer in form satisfactory to us and duly executed by the
registered holder and the signature on the endorsement or instrument of transfer
must be guaranteed by a firm (an "Eligible Institution") that is a member of a
recognized signature guarantee medallion program within the meaning of Rule
17Ad-15 under the Exchange Act. 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 on 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
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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 establish an account with respect to the book-entry
interests at the DTC for purposes of the exchange offer promptly after the date
of this prospectus. 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.
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
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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."
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.
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.
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
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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.
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
31
35
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.
EXCHANGE AGENT
has been appointed as the Exchange Agent of the exchange
offer. All executed letters of transmittal should be directed to the Exchange
Agent at one of the addresses 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: By Registered or Certified Mail:
- ----------------------------------------------------- -----------------------------------------------------
- ----------------------------------------------------- -----------------------------------------------------
- ----------------------------------------------------- -----------------------------------------------------
Attn: Attn:
</Table>
Via Facsimile:
Confirm by telephone:
For Information Call:
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
32
36
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 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." 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.
33
37
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
- ---------------------------------------------
(IN MILLIONS)
<Table>
Proceeds from sale of units......... $122.9
Estimated cash...................... 66.7
------
Total sources............. $189.6
======
</Table>
USES OF FUNDS
- ---------------------------------------------
(IN MILLIONS)
<Table>
Repayment of note payable........... $104.3
Repayment of other obligations...... 32.6
Payment of accrued interest......... 20.5
Segregated funds for disputed
claims(1)......................... 11.4
Offering fees and expenses.......... 9.6
Development drilling program and
working capital................... 11.2
------
Total uses................ $189.6
======
</Table>
- ---------------
(1) To the extent claims are resolved for less than the full amount, the balance
will be remitted to us.
34
38
CAPITALIZATION
The following table sets forth our consolidated indebtedness and
capitalization at March 31, 2001. The pro forma data gives effect to the
original offering and the application of the proceeds as set forth under "Use of
Proceeds" as if the offering and the consummation of our amended plan of
reorganization had occurred on March 31, 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 MARCH 31, 2001
-----------------------
ACTUAL PRO FORMA(2)
-------- ------------
(IN THOUSANDS)
Long-term debt, including current maturities:
Notes payable, net of bond discounts...................... $104,324 $105,250
Other debt(1)............................................. 164 164
-------- --------
Total debt........................................ 104,488 105,414
-------- --------
Stockholders' equity (capital deficit)
Class A Common stock, $0.01 par value, 445,000 shares
authorized, 238,333 and 368,333 shares issued and
outstanding............................................ 2 4
Class B Common stock, $0.01 par value, 65,000 shares
authorized, 0 and 65,000 shares issued and
outstanding............................................ -- 1
Additional paid in capital................................ -- 25,648
Deficit................................................... (15,361) (23,968)
-------- --------
Total stockholders' equity (capital deficit)...... (15,359) 1,684
-------- --------
Total capitalization.............................. $ 89,129 $107,098
======== ========
</Table>
- ---------------
(1) Represents an unsecured financing of well control insurance policy premiums,
scheduled to be repaid by August 31, 2001.
(2) The pro forma data does not include disputed claims totaling $5.1 million
that are included in "Use of Proceeds."
35
39
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>
THREE MONTHS ENDED
YEARS ENDED DECEMBER 31, MARCH 31,
--------------------------------------------------- -------------------
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 $ 13,013 $ 32,139
Expenses:
Lease operating.......................... 1,829 4,845 17,450 15,542 19,485 3,890 5,452
Workover................................. 136 687 600 2,410 6,649 1,134 1,621
Production taxes......................... 160 305 639 705 1,968 308 769
Depreciation, depletion and
amortization........................... 838 3,037 12,398 11,040 13,506 2,767 3,738
General and administrative............... 239 2,276 3,327 5,237 4,328 1,186 1,642
Interest................................. 836 1,410 7,734 11,981 12,758 3,327 3,112
------- -------- -------- -------- -------- -------- --------
Total expenses.................... 4,038 12,560 42,147 46,916 58,695 12,613 16,335
Income (loss) before reorganization costs
and income taxes......................... 1,018 736 (15,795) (9,150) 15,780 400 15,804
Reorganization costs....................... -- -- -- -- 21,487 402 723
------- -------- -------- -------- -------- -------- --------
Income (loss) before income
taxes.................................... 1,018 736 (15,795) (9,150) (5,707) (2) 15,081
Provision for income taxes................. 352 925 -- -- 79 -- 300
------- -------- -------- -------- -------- -------- --------
Net income (loss).......................... $ 666 $ (189) $(15,795) $ (9,150) $ (5,786) $ (2) $ 14,781
======= ======== ======== ======== ======== ======== ========
Net income (loss) per share -- basic and
diluted.................................. $ 2.79 $ (0.79) $ (66.27) $ (38.39) $ (24.28) $ (0.01) $ 62.02
======= ======== ======== ======== ======== ======== ========
Weighted average shares outstanding........ 238,333 238,333 238,333 238,333 238,333 238,333 238,333
======= ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
Capital expenditures -- oil and natural gas
properties............................... $ 1,431 $ 20,457 $ 71,992 $ 13,572 $ 10,878 $ 1,217 $ 1,381
EBITDA(1).................................. 2,692 5,183 4,337 13,871 42,045 6,494 22,654
EBITDA to cash interest(2)................. 3.22x 3.68x 0.56x 1.16x 3.30x 1.95x 7.28x
Earnings to fixed charges(3)............... 2.18x 1.44x NM 0.31x 0.60x 1.00x 5.33x
Cash flows from operating activities....... $ 1,731 $ 2,516 $ 7,168 $ 12,127 $ 40,695 $ 4,447 $ 21,642
Cash flows from investing activities....... (9,544) (24,196) (71,926) (11,943) (10,118) (1,545) (1,747)
Cash flows from financing activities....... 8,439 23,324 65,153 (42) (401) (218) (170)
</Table>
<Table>
<Caption>
AT DECEMBER 31,
--------------------------------------------------- AT MARCH 31,
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 $ 85,249
Total assets............................ 14,904 41,831 104,130 108,903 152,594 175,017
Stockholder's equity (capital
deficit).............................. 710 592 (15,203) (24,352) (30,139) (15,359)
ACNTA(4)................................ NM 101,050 116,319 283,562 617,387 607,899
Notes payable, including current
maturities............................ 11,300 35,184 101,480 105,058 104,657 104,488
ACNTA to indebtedness................... NM 2.87x 1.15x 2.70x 5.90x 5.82x
</Table>
(footnotes on following page)
36
40
- ---------------
(1) EBITDA means earnings before interest expense, income taxes, depreciation,
depletion and amortization, impairment of oil and natural gas properties and
reorganization costs. 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 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. Fixed charges represent interest expense (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."
37
41
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 three months ended March 31, 2001, and our
unaudited condensed pro forma consolidated balance sheet as of March 31, 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 as if they had been consummated as of January 1,
2000 for purposes of the statement of operations data and as of March 31, 2001
for purposes of the balance sheet data. 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 THREE MONTHS ENDED MARCH 31, 2001
--------------------------------------- ---------------------------------------
HISTORICAL ADJUSTMENTS(1) PRO FORMA HISTORICAL ADJUSTMENTS(1) PRO FORMA
---------- -------------- --------- ---------- -------------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AND RATIO DATA)
Total revenues............... $74,476 $ 74,476 $32,139 $32,139
------- -------- ------- -------
Expenses:
Lease operating............ 19,485 19,485 5,452 5,452
Workover................... 6,649 6,649 1,621 1,621
Production taxes........... 1,968 1,968 769 769
Depreciation, depletion and
amortization............ 13,506 13,506 3,738 3,738
General and
administrative.......... 4,328 4,328 1,642 1,642
Interest................... 12,758 $ 14,982(2) 27,740 3,112 $ 3,382(2) 6,494
------- -------- -------- ------- ------- -------
Total expenses..... 58,695 14,982 73,677 16,335 3,382 19,717
Income (loss) before
reorganization costs and
income taxes............... 15,780 (14,982) 798 15,804 (3,382) 12,422
Reorganization costs......... 21,487 21,487 723 723
------- -------- -------- ------- ------- -------
Income (loss) before income
taxes...................... (5,707) (14,982) (20,689) 15,081 (3,382) 11,699
Provision for income taxes... 79 (79)(3) -- 300 (68)(3) 232
------- -------- -------- ------- ------- -------
Net income (loss)............ $(5,786) $(14,903) $(20,689) $14,781 $(3,314) $11,467
======= ======== ======== ======= ======= =======
Net income (loss) per share
-- basic and diluted....... $(24.28) $ (47.74) $ 62.02 $ 26.46
======= ======== ======= =======
Weighted average shares
outstanding................ 238,333 433,333 238,333 433,333
======= ======== ======= =======
Other Financial Data:
EBITDA(4).................... $ 42,045 $22,654
EBITDA to cash interest(6)... 2.59x 5.58x
Earnings to fixed
charges(5)................. 0.28x 2.73x
======== =======
</Table>
- ---------------
(1) The pro forma consolidated statements of operations do not include one time
adjustments totaling $7.5 million for additional interest, bank charges and
professional fees called for in our plan. These charges will be recorded in
the historical financial statements during the quarter ended June 30, 2001.
These amounts are reflected in our calculation of uses of funds in the "Use
of Proceeds" shown on page 34.
(2) To adjust for additional interest at 12.5% on the notes and record
amortization of bond discounts and bond issuance costs.
(3) To adjust for the estimated current federal income tax liability.
38
42
(4) EBITDA means earnings before interest expense, income taxes, depreciation,
depletion and amortization, impairment of oil and natural gas properties and
reorganization costs. 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 EBITDA may not
be identical to similarly entitled measures used by other companies.
(5) Earnings were insufficient to cover fixed charges by $20.7 million on a pro
forma basis for the year ended December 31, 2000. NM means not measured.
(6) 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.
39
43
UNAUDITED CONDENSED PRO FORMA CONSOLIDATED BALANCE SHEET
<Table>
<Caption>
AT MARCH 31, 2001
-------------------------------------------
HISTORICAL ADJUSTMENTS(1) PRO FORMA
---------- -------------- ---------
(IN THOUSANDS)
ASSETS:
Current Assets:
Cash and cash equivalents................................... $ 52,715 $ 113,225(2)
-- (39,672)(3)
-- (124,020)(4) $ 2,248(8)
Accounts receivable......................................... 30,054 (907)(3) --
-- (662)(5) 28,485
Marketable securities....................................... 264 264
Prepaid and other........................................... 1,637 1,637
-------- --------- --------
Total current assets............................... 84,670 (52,036) 32,634
Oil and gas properties -- full cost method, net............. 84,822 (1,138)(5) 83,684
Other assets................................................ 5,524 8,249(2) --
-- (351)(5) --
-- 9,427(6) 22,849
-------- --------- --------
Total assets....................................... $175,017 $ (35,849) $139,167
======== ========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY (CAPITAL DEFICIT):
Current Liabilities:
Accounts payable and accrued liabilities.................... $ 41,646 $ (9,576)(4) $ 32,069
Bank fee.................................................... -- 37(7) --
-- (37)(4) --
Accrued bank interest....................................... -- 2,693(7) --
-- (2,693)(4) --
Bank professional fees...................................... -- 428(7) --
-- (428)(4) --
Pre-petition interest....................................... -- 2,649(8) --
-- (2,649)(3) --
Success fees................................................ -- 650(8) --
-- (650)(3) --
Notes payable............................................... 164 164
-------- --------- --------
41,810 (9,576) 32,233
Pre-petition liabilities subject to compromise:
Notes payable -- in default................................. 104,324 (104,324)(4) --
Accrued interest............................................ 6,227 (6,227)(4) --
Other....................................................... 38,015 (37,280)(3) --
-- (735)(4) --
-------- --------- --------
Total pre-petition liabilities subject to
compromise....................................... 148,566 (148,566) --
-------- --------- --------
Senior Secured Notes........................................ -- 130,000(2) 130,000
Bond Discount............................................... -- (7,150)(2)
(17,600)(2) (24,750)
Stockholders' Equity (Capital Deficit):
Class A Common stock, $0.01 par value, 445,000 shares
authorized; 238,333 and 368,333 shares issued and
outstanding............................................. 2 2(2) 4
Class B common stock, $0.01 par value, 65,000 shares
authorized, 0 and 65,000 shares issued and
outstanding............................................. -- 1(6) 1
Additional paid in capital................................ -- (1,376)(2)
17,598(2)
10,999(6)
(1,573)(6) 25,648
Deficit................................................... (15,361) (3,158)(7) --
-- (3,299)(8) --
-- (2,151)(5) (23,968)
-------- --------- --------
Total stockholders' equity (capital deficit)....... (15,359) 17,043 1,684
-------- --------- --------
Total liabilities and stockholders' equity (capital
deficit)......................................... $175,017 $ (35,849) $139,167
======== ========= ========
</Table>
(footnotes on following page)
40
44
- ---------------
(1) The unaudited condensed pro forma consolidated balance sheet does not
include disputed claims totaling $5.1 million that are included in the use
of proceeds and will be considered restricted cash.
(2) To record the receipt of the proceeds from the original offering and the
issuance of the class A common stock:
<Table>
<Caption>
(IN THOUSANDS)
Senior secured notes................................... $ 130,000
Class A common stock -- par value...................... 2
Additional paid in capital............................. 17,598
Less:
Issue discount....................................... (7,150)
Discount allocated to class A common stock........... (17,600)
Offering costs -- debt............................... (8,249)
Offering costs -- equity............................. (1,376)
--------------
Net proceeds........................................... $ 113,225
==============
(3) To record the effects of the payment of unsecured claims:
Interest on pre-petition liabilities................... $ 2,649
Success fees........................................... 650
Pre-petition liabilities -- other...................... 37,280
Accounts receivable offset............................. (907)
--------------
$ 39,672
==============
(4) To record the effects of the payment of bank debt:
Accounts payable and accrued expenses.................. $ 9,576
Letters of credit fees................................. 37
Additional bank interest............................... 2,693
Additional professional fees........................... 428
Principal balance...................................... 104,324
Pre-petition interest.................................. 6,227
Pre-petition liabilities -- other...................... 735
--------------
$ 124,020
==============
(5) To record the effects of shareholder transactions:
Accounts receivable.................................... $ (662)
Other assets........................................... (351)
Oil and natural gas properties......................... (1,138)
--------------
Capital deficit........................................ $ (2,151)
==============
(6) To record the issuance of the Class B common stock:
Class B common stock -- par value...................... $ 1
Additional paid in capital............................. 10,999
Offering costs -- debt................................. (9,427)
Offering costs -- equity............................... (1,573)
--------------
$ --
==============
(7) To record the effects of fees associated with bank debt:
Letters of credit fees................................. $ 37
Additional bank interest............................... 2,693
Additional professional fees........................... 428
--------------
$ 3,158
==============
</Table>
41
45
(IN THOUSANDS)
(8) To record the effects of other charges as part of our plan:
Interest on pre-petition liabilities................... $ 2,649
Success fees........................................... 650
--------------
$ 3,299
==============
(9) This information is as of March 31, 2001 and excludes funds segregated for
disputed claims. Immediately prior to closing, our cash and cash equivalents
were approximately $66.7 million, and $11.2 million after giving effect to
the original offering and the consummation of our amended plan of
reorganization.
OPERATING DATA
The following table sets forth information with respect to our consolidated
operations for the periods shown.
<Table>
<Caption>
THREE MONTHS
YEARS ENDED DECEMBER 31, ENDED MARCH 31,
--------------------------- -----------------
1998 1999 2000 2000 2001
------- ------- ------- ------- -------
Production volumes:
Oil and condensate (MBbls)........................ 1,030 1,145 1,333 279 353
Natural gas (MMcf)................................ 6,711 7,007 8,314 1,778 2,352
Total (MMcfe).............................. 12,890 13,874 16,313 3,452 4,470
Average daily production:
Oil and condensate (Bbls)......................... 2,821 3,136 3,643 3,069 3,923
Natural gas (Mcf)................................. 18,387 19,196 22,716 19,539 26,129
Total (Mcfe)............................... 35,314 38,011 44,574 37,953 49,667
Average realized prices:(1)
Oil and condensate (per Bbl)...................... $ 12.43 $ 17.27 $ 28.95 $ 28.91 $ 29.01
Natural gas (per Mcf)............................. 1.94 2.36 4.19 2.49 9.43
Per Mcfe................................... 2.00 2.61 4.50 3.62 7.25
Expenses (per Mcfe):
Lease operating (excluding workover expense and
production taxes)............................... $ 1.35 $ 1.12 $ 1.19 $ 1.13 $ 1.22
Workover.......................................... 0.05 0.17 0.41 0.33 0.36
Production taxes.................................. 0.05 0.05 0.12 0.09 0.17
Depreciation, depletion and amortization.......... 0.96 0.80 0.83 0.80 0.84
General and administrative, net................... 0.26 0.38 0.27 0.34 0.37
</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
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.
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46
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.
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 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 and 2002 to $34.2 million, to complete 93 development
drilling, exploitation and recompletion projects.
On July 27, 2001, we were the surviving corporation in a merger with our
parent corporation, Tribo Petroleum Corporation. As a consequence of this
merger, we assumed all of the rights and obligations of Tribo, including those
under the indenture. 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
43
47
natural gas reserves. Proceeds from all other sales or dispositions are treated
as reductions to capitalized costs.
RESULTS OF OPERATIONS
Three Months Ended March 31, 2001 Compared to Three Months Ended March 31,
2000
For the three months ended March 31, 2001, consolidated net income was
$14,780,715, an improvement over a consolidated net loss of $1,857 for the three
months ended March 31, 2000.
Oil and Natural Gas Revenues. Oil and natural gas revenues increased
$19,912,445, or 159%, to $32,407,222 for the three months ended March 31, 2001,
from $12,494,777 for the three months ended March 31, 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 three months ended March 31,
2001 and 2000:
<Table>
<Caption>
THREE MONTHS ENDED MARCH 31,
-----------------------------
2000 2001 % CHANGE
------- ------- ---------
Oil production volumes (MBbls).......................... 279 353 27%
Gas production volumes (MMcf)........................... 1,778 2,352 32
Total (MMcfe)................................. 3,452 4,470 29
Average oil price (per Bbl)............................. $28.91 $29.01 --
Average gas price (per Mcf)............................. 2.49 9.43 279%
Per Mcfe...................................... 3.62 7.25 100
</Table>
Gain or Loss on Marketable Securities. We recognized $326,363 in losses on
marketable securities for the three months ended March 31, 2001, as compared to
gains of $441,632 at March 31, 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 decreased $18,850, or 25%, to $57,767 for the
three months ended March 31, 2001 from $76,617 for the three months ended March
31, 2000. The decrease was primarily the result of a reclassification of
interest income received during 2001 as reorganization costs in accordance with
Statement of Position 90-7 ("SOP 90-7"). SOP 90-7 requires that interest income
earned by an entity operating in bankruptcy that would not have been earned
outside of bankruptcy be reported as a reorganization item. This change in
reporting became effective on March 14, 2000.
Lease Operating Expense. Lease operating expense increased $1,562,672, or
40%, to $5,452,439 for the three months ended March 31, 2001 from $3,889,767 for
the three months ended March 31, 2000. Lease operating expense was $1.22 per
Mcfe for the three months ended March 31, 2001, an increase of 8% from $1.13 per
Mcfe for the three months ended March 31, 2000. The increase in lease operating
expense is primarily the result of higher electricity and fuel costs, an
increase in the number of our producing wells and MMS compliance work at our
Matagorda Island A-4 and Brazos 104 facilities.
Workover Expense. Workover expense increased $486,438, or 43%, to
$1,620,834 for the three months ended March 31, 2001 from $1,134,396 for the
three months ended March 31, 2000. Workover expense was $0.36 per Mcfe for the
three months ended March 31, 2001, an increase of 9% from $0.33 per Mcfe for the
three months ended March 31, 2000. During the first quarter of 2000 and
immediately preceding our bankruptcy filing, workover spending was minimized.
During the remainder of 2000 and the first quarter of 2001, a workover program
was completed that included
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48
normal recurring workovers and a backlog of workovers from 1998 and 1999. During
the first quarter of 2001, workover repairs were completed on several wells
which will provide long-term cost savings due to a reduced requirement for
pulling jobs in the future and fewer production interruptions from associated
downtime.
Production Taxes. Production taxes increased $460,542, or 149%, to
$768,897 for the three months ended March 31, 2001 from $308,355 for the three
months ended March 31, 2000. Production taxes were $0.17 per Mcfe for the three
months ended March 31, 2001, an increase of 89% from $0.09 per Mcfe for the
three months ended March 31, 2000. Increases in oil and natural gas production
and revenues during the three months ended March 31, 2001 resulted in an
increase in the amount of production taxes paid during the period.
Depreciation, Depletion and Amortization Expense ("DD&A"). DD&A increased
$970,913, or 35%, to $3,738,112 for the three months ended March 31, 2001 from
$2,767,199 for the three months ended March 31, 2000. DD&A was $0.84 per Mcfe
for the three months ended March 31, 2001, an increase of 5% from $0.80 per Mcfe
for the three months ended March 31, 2000. Increased oil and natural gas
production during the three months ended March 31, 2001 resulted in an increase
in the amount of depletion computed on those volumes.
General and Administrative Expense ("G&A"). G&A increased $456,009, or
38%, to $1,642,246 for the three months ended March 31, 2001 from $1,186,237 for
the three months ended March 31, 2000. G&A was $0.37 per Mcfe for the three
months ended March 31, 2001, an increase of 9% from $0.34 per Mcfe for the three
months ended March 31, 2000. The increase was primarily the result of an
increase in legal fees incurred during the first three months of 2001.
Interest Expense. Interest expense decreased $215,046, or 6%, to
$3,111,975 for the three months ended March 31, 2001 from $3,327,021 for the
three months ended March 31, 2000. The decrease was primarily the result of our
decision, at the inception of the bankruptcy filing, to accrue interest on the
outstanding borrowings of the credit facility at 12%.
Reorganization Costs. We filed a voluntary petition for relief under the
U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of
Texas, Houston Division on March 14, 2000. We incurred reorganization costs of
$723,408 for the three months ended March 31, 2001, an 80% increase from
$401,908 for the three months ended March 31, 2000. These reorganization costs
primarily consist of legal and accounting professional fees incurred in
bankruptcy proceedings. Additionally, for the three months ended March 31, 2001
and 2000, interest income in the amounts of $519,340 and $6,229, respectively,
have been recorded as offsets to reorganization costs as prescribed by SOP 90-7.
Provision for Income Taxes. A $300,000 provision for income tax was made
for the three months ended March 31, 2001, primarily as a result of alternative
minimum tax requirements. No provision for federal income tax was required for
the three months ended March 31, 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.
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49
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 expenses 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
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50
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 executory contract -- The bankruptcy court approved a
motion to reject an executory contract. A claim was filed by the damaged
party resulting in a liability of $17,559,272 and this amount 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.
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51
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
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52
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, we acquired certain onshore Texas oil and natural gas
properties from Apache 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.
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 March 31, 2000 balance sheets
as "liabilities subject to compromise." Additional claims (liabilities subject
to compromise) arose subsequent to the bankruptcy filing date from the rejection
of executory contracts or unexpired leases by the bankruptcy court or by
agreement of the parties in interest, from allowed claims for contingencies and
other disputed claims. Claims secured against our assets were also stayed. The
proceeds of the original offering and our available cash balances allowed us to
pay all allowed secured and unsecured creditor claims in full or to segregate
funds for the payment in full of claims that we dispute and to exit bankruptcy
on June 18, 2001.
During the three months ended March 31, 2001, we increased our cash
balances by $19,725,423 to $52,715,362 from $32,989,939 for the year ended
December 31, 2000.
Net cash provided by operating activities before reorganization costs was
$21,602,479 for the three months ended March 31, 2001. The increase is the
result of net income of $14,780,715 after reorganization costs of $723,408, when
compared to a net loss of $1,857 after reorganization costs of $401,908 for the
three months ended March 31, 2000. Additionally, an increase in accounts payable
and accrued liabilities increased cash flows provided by operating activities.
Increases in accounts payable were partially offset by an increase in accounts
receivable.
Net cash used in investing and financing activities remained consistent
when comparing the three month periods ended March 31, 2001 and 2000.
Net cash flow provided by operating activities before reorganization costs
for the years ended December 31, 2000 and 1999 was $42,692,727 and $12,126,996,
respectively. The increase was primarily the result of an increase in
pre-petition liabilities subject to compromise and reorganization
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53
costs related to the Chapter 11 filing. These increases were offset by an
increase in accounts receivable and gains on sales of marketable securities.
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 expended 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 years ended December 31, 1998, 1999 and 2000 and the three
months ended March 31, 2001:
<Table>
<Caption>
YEARS ENDED DECEMBER 31, THREE MONTHS
--------------------------- ENDED
1998 1999 2000 MARCH 31, 2001
------- ------- ------- --------------
(IN THOUSANDS)
Property acquisition -- proved......... $62,477 $ 250 $ 408 --
Development costs...................... 9,515 13,322 10,080 $1,381
Exploration costs...................... -- -- 389 --
------- ------- ------- ------
Total costs incurred......... $71,992 $13,572 $10,878 $1,381
======= ======= ======= ======
</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.
CAPITAL REQUIREMENTS
Historically, our principal sources of capital have been cash flow from
operations, short-term reserve-based bank loans and proceeds from asset sales.
Our principal uses for capital have been the acquisition and development of oil
and natural gas properties.
On a pro forma basis, after giving effect to the original offering, our
cash balance was approximately $11.2 million. Our budget for 2001 includes
capital expenditures of $17.1 million, representing an increase of 57% over our
total capital expenditures for 2000 and a 118% increase over our development
drilling and recompletion 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.
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.
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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 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. 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 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 our financial
statements; however it may have a significant impact on us in the future
depending on the nature of our anticipated hedging program.
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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.
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 quarter of 2001, these fields produced approximately
40 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 quarter of 2001, these fields produced
approximately 10 MMcfe per day.
We have a large inventory of low-risk development projects that we have
only recently begun to exploit. 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, 66% are proved behind pipe and proved undeveloped projects and
the remainder are behind pipe opportunities in the Sacramento Basin that were
not classified as proved at December 31, 2000. We have allocated $14.9 million
of our capital budget for the second half of 2001 and $19.3 million for 2002 for
these 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
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
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$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 93 development and exploitation projects in our three core areas
through 2002 for approximately $34.2 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
2002 will be focused on 56 development wells and proved behind pipe objectives
onshore Gulf Coast, 8 proved behind pipe and proved undeveloped objectives
offshore Gulf Coast and 29 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.
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.
<Table>
<Caption>
FOR THE PERIOD JUNE 1, 2001
THROUGH DECEMBER 31, 2002
---------------------------
BUDGETED BUDGETED
DEVELOPMENT COST
AREA OF OPERATION PROJECTS (IN MILLIONS)
- ----------------- ----------- -------------
Onshore Gulf Coast.......................................... 56 $22.1
Offshore Gulf Coast......................................... 8 3.7
California.................................................. 29 8.4
-- -----
Total............................................. 93 $34.2
== =====
</Table>
Additionally, we are currently evaluating 82 development and exploitation
projects, principally consisting of behind pipe opportunities in the Sacramento
Basin.
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 and gives us a competitive advantage
in acquiring new acreage in our core areas of operations. Our operated
properties currently 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.
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57
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 RECAPITALIZATION
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache 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
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.
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. Our subsidiary 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% 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
Corporation, with which we merged on July 27, 2001. The units were sold to
Jefferies & Company, Inc., as initial purchaser. The initial purchaser sold a
portion of 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 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.
Our onshore Gulf Coast properties accounted for 64% of our proved reserves
at December 31, 2000 and 66% of our production for the quarter ended March 31,
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 decline curves are relatively shallow 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
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58
area. Each of these nine top value properties are operated by us and, in
aggregate, accounted for approximately 86% of the area's production for the
quarter ended March 31, 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 14% of our production for the quarter ended March 31,
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 and a significant amount of probable and possible 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 3% of the
production from the area for the quarter ended March 31, 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 20% of our production for the quarter ended March 31,
2001. At December 31, 2000, our proved reserves in the area were distributed
among 16 fields. The majority of these reserves are further 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 37% of the production
from the area for the quarter ended March 31, 2001 and 82% of our proved
reserves in the area at the end of 2000. In addition to our proved reserves, our
California properties also have significant probable and possible reserve
potential. 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 yield additional proved undeveloped
and probable locations 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.
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The following table and discussion provides proved reserves, PV-10 Values,
first quarter 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 63% of our total oil and natural gas
production in the first quarter of 2001, which averaged 50 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 25.0% 29.4%
Constitution................... 11,684 60,348 16.8 6.5
Word........................... 7,405 36,140 1.2 4.1
AWP............................ 7,189 32,112 2.0 4.0
Clear Branch................... 5,470 28,324 0.8 3.0
Sour Lake...................... 5,192 8,829 2.2 2.9
Scott.......................... 3,063 22,095 3.9 1.7
North Alvin.................... 3,031 7,984 1.2 1.7
South Liberty.................. 2,708 6,654 2.0 1.5
Other.......................... 15,972 42,928 11.1 8.8
------- -------- ----- -----
Subtotal............... 114,587 298,975 66.2 63.6
Offshore Gulf Coast:
South Pass 27.................. 5,542 14,325 0.4 3.1
Eugene Island 277.............. 3,077 11,543 -- 1.7
Other.......................... 13,274 75,622 13.5 7.4
------- -------- ----- -----
Subtotal............... 21,893 101,490 13.9 12.2
California:
Sutter Buttes.................. 28,493 153,391 3.7 15.8
Grimes......................... 4,155 21,457 2.6 2.3
Greeley........................ 3,344 7,939 0.6 1.9
Other.......................... 7,665 46,750 13.0 4.2
------- -------- ----- -----
Subtotal............... 43,657 229,537 19.9 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 three months ended March 31, 2001.
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.
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Net daily production from the Hastings Complex during the first quarter of 2001
averaged 12,431 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 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. It also led to one probable location. Net daily
production from the Constitution field during the first quarter 2001 was 8,324
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 quarter
2001 averaged 585 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 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
working interests in the field that 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 quarter 2001 averaged
approximately 988 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.
Clear Branch Field. We acquired our interest 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 quarter 2001 averaged approximately 388 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 who discovered the
field. We own 100% of the mineral estate in fee under 930 acres in the field.
Our largest contiguous lease
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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 quarter 2001 averaged approximately 1,112 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 quarter 2001 averaged approximately
1,948 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 quarter 2001 averaged approximately 585 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 quarter 2001 averaged approximately 1,005 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 Louisiana in approximately 120 feet of water.
Net daily production from the field during the first quarter 2001 averaged
approximately 188 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. At December 31, 2000, we had
proved reserves of 3,077 MMcfe.
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
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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 quarter 2001
averaged 1,846 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 quarter 2001 averaged 1,523 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 quarter 2001 averaged 302
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.
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
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.
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.
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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.
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>
THREE MONTHS ENDED
YEARS ENDED DECEMBER 31, MARCH 31,
--------------------------- -------------------
1998 1999 2000 2000 2001
------- ------- ------- -------- --------
Production Volumes:
Oil and condensate (MBbls)................ 1,030 1,145 1,333 279 353
Natural gas (MMcf)........................ 6,711 7,007 8,314 1,778 2,352
Total (MMcfe)..................... 12,890 13,874 16,313 3,452 4,470
Average Daily Production:
Oil and condensate (Bbls)................. 2,821 3,136 3,643 3,069 3,923
Natural gas (Mcf)......................... 18,387 19,196 22,716 19,539 26,129
Total (Mcfe)...................... 35,314 38,011 44,574 37,953 49,667
Average Realized Prices:(1)
Oil and condensate (per Bbl).............. $ 12.43 $ 17.27 $ 28.95 $ 28.91 $ 29.01
Natural gas (per Mcf)..................... 1.94 2.36 4.19 2.49 9.43
Per Mcfe.......................... 2.00 2.61 4.50 3.62 7.25
Expenses (per Mcfe):
Lease operating (excluding workover
expenses and production taxes)......... $ 1.35 $ 1.12 $ 1.19 $ 1.13 $ 1.22
Workover.................................. 0.05 0.17 0.41 0.33 0.36
Production taxes.......................... 0.05 0.05 0.12 0.09 0.17
Depletion, depreciation and
amortization........................... 0.96 0.80 0.83 0.80 0.84
General and administrative, net........... 0.26 0.38 0.27 0.34 0.37
</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."
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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>
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
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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 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
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"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 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,
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rendering a person liable for environmental damages and cleanup costs without
regard to negligence or fault on the part of such person. Other laws, rules and
regulations may restrict the rate of oil and natural gas production below the
rate that would otherwise exist. In addition, state laws often require various
forms of remedial action to prevent pollution, such as closure of inactive pits
and plugging of abandoned wells. The regulatory burden on the oil and natural
gas industry increases our cost of doing business and consequently affects our
profitability. We believe that we are in substantial compliance with current
applicable environmental laws, rules and regulations, that we have no material
commitments for capital expenditures to comply with existing environmental
requirements and that continued compliance with existing requirements will not
have a material adverse impact on our operations. However, environmental laws,
rules and regulations have been subject to frequent changes over the years, and
the imposition of more stringent requirements could have a material adverse
effect upon our capital expenditures, earnings or competitive position as well
as those of the oil and gas industry in general.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund Law," and analogous state laws impose
liability without regard to fault or the legality of the original conduct on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the current or former owner or operator of the site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Under CERCLA, such persons may be
subject to joint and several liability for the costs of investigating and
cleaning up hazardous substances that have been released into the environment,
for damages to natural resources and for the costs of certain health studies. In
addition, companies that incur liability frequently also confront third party
claims because it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and other wastes associated with the
exploration, development or production of oil and natural gas from regulation as
"hazardous waste." Disposal of such non-hazardous oil and natural gas
exploration, development and production wastes usually are regulated by state
law. Other wastes handled at exploration and production sites or generated in
the course of providing well services may not fall within this exclusion.
Moreover, stricter standards for waste handling and disposal may be imposed on
the oil and natural gas industry in the future. From time to time legislation is
proposed in Congress that would revoke or alter the current exclusion of
exploration, development and production wastes from the RCRA definition of
"hazardous wastes" thereby potentially subjecting such wastes to more stringent
handling, disposal and cleanup requirements. State initiatives to further
regulate the disposal of oil and natural gas wastes and naturally occurring
radioactive materials could have a similar impact on us. If such legislation
were enacted it could have a significant impact on our operating costs, as well
as those of the oil and natural gas industry in general. The impact of future
revisions to environmental laws and regulations cannot be predicted.
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.
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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 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.
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.
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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.
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
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Lyonnais filed a counterclaim against us seeking repayment of monies loaned by
Credit Lyonnais to us, interest and attorney's fees.
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.
Aviara Energy Corporation
On November 10, 1999, Aviara Energy Corporation filed suit against us in
the 129th Judicial District Court of Harris County, Texas, alleging that we owe
approximately $1.8 million in joint interest expenses under a participation and
operating agreement. Aviara subsequently filed an amended proof of claim to add
post-petition administrative expenses and interest of approximately $1.0 million
to its claim. No action on this suit was taken during our bankruptcy. This
dispute will be resolved by the bankruptcy court.
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
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. We intend 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.
Subsequently, Linda Barnhill joined as a plaintiff. The suit alleges that we owe
additional royalties on oil and natural gas produced from February 1987 to date
as to certain completions in oil and natural gas properties located in Alvin,
Texas, that oil and natural gas was drained from approximately 18 acres in which
they claim interests and seeks the recovery of attorneys' fees. As to certain of
the plaintiffs' claims, we have obtained a favorable decision from the Texas
Railroad Commission. An appeal of the decision by the plaintiffs is currently
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pending. We believe the decision will be affirmed and that, if affirmed, it
could result in the full avoidance of all of the plaintiffs' claims. Even if the
decision is not affirmed, we believe we have other defenses that could result in
the full avoidance of the claims. We have filed a partial summary judgment on
limitations and other defenses that is currently pending. We intend to continue
to vigorously defend this suit. Funds in the amount of approximately $1.0
million have been segregated in accordance with our plan pending the resolution
of this dispute by the bankruptcy court. We believe these funds are sufficient
to cover our net interest in the full proof of claim filed in the amount of $3.0
million.
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 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.
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MANAGEMENT
Our director, principal executive officers and those persons who we expect
to serve as our directors are:
<Table>
<Caption>
NAME AGE POSITION
---- ---- --------
Richard Bowman....................... 36 Founder, President, Chief Executive
Officer and Director
R. Kelly Plato....................... 31 Vice President and Chief Financial
Officer
Jeffrey T. Janik..................... 48 Vice President, Operations
Suzanne R. Ambrose................... 41 Vice President, Treasurer and Chief
Accounting Officer
G. Bryan Dutt........................ 42 Director nominee
Michel T. Halbouty................... 91 Director nominee
Donald W. Riegle, Jr. ............... 63 Director nominee
Oliver G. Richard III................ 48 Director nominee
</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
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.
R. Kelly Plato has served in various management roles with us since January
1999, most recently as Vice President and Chief Financial Officer. Prior to
joining us, Mr. Plato served as Vice President, Capital Services of Koch
Producer Services, Inc., from September 1997 to October 1998, and Director,
Business Development of Merit Energy Company, from August 1996 to August 1997.
From August 1992 to August 1996, Mr. Plato was employed in various petroleum
engineering positions with Fina Oil & Chemical Company.
Jeffery T. Janik has served in various management roles with us since June
1998, most recently as Vice President, Operations. Prior to joining us, Mr.
Janik served as Vice President of Operations at Baker-MO Services, Inc., from
April 1993 to June 1998, and as Operations Manager at KP Exploration, from
February 1984 to April 1993.
Suzanne R. Ambrose has served in various management roles with us since
November 1998, most recently as 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., from May 1996 to November
1998, and HLS Offshore, L.L.C., from January 1998 through May 1998. Ms. Ambrose
served as controller of Offshore Petroleum Divers, Inc., a wholly-owned
subsidiary of Offshore Pipeline, Inc., from March 1989 through November 1995.
G. Bryan Dutt founded Ironman Energy Capital, L.P. in 1999 and serves as
Chairman of the Board. Mr. Dutt served as managing partner of Centennial Energy
Partners from 1985 to 1995. Previously, he was an energy analyst at Howard,
Weil, Labouisse, Friedrichs Inc. He is a past president of the New Orleans
Financial Analyst Society and was a director of Aurion Technologies, LLC from
1995 to 1999.
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Michel T. Halbouty has been Chairman of the Board and Chief Executive
Officer of Michel T. Halbouty Energy Co. 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. He is currently Chairman of Government Relations for APCO Worldwide, a
global public affairs and strategic communications firm headquartered in
Washington, D.C. Following his retirement from the Senate, Mr. Riegle joined
Shandwick, a component of the Interpublic Group of Companies, in January 1995
where he served for six years.
Oliver G. Richard III served as Chairman, President and Chief Executive
Officer of Columbia Energy Group until its acquisition in November 2000. From
1987 to 1991 Mr. Richard 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.
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>
- ---------------
(1) Amount includes automobiles furnished by us and premium payments we made for
health, dental, disability and life insurance policies for the referenced
individuals.
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(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 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 intend to enter into employment agreements with each of our other
executive officers on terms that are reflective of current market conditions.
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, all transactions with affiliates must be
conducted on an arm's length basis in accordance with its terms.
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,
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which has approximately 9,355 square feet of office space. We currently occupy
this space at a 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.
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 March 31, 2001, we allocated $5,000 per month to
Atasca for the rendering of such services.
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. At March 31, 2001, we owed Atasca $142,871 in the
aggregate. Under the terms of the indenture, all transactions with Atasca must
be conducted on an arm's length basis in accordance with its terms.
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 $14,200 from the three months ended March 31, 2001, reducing the
balance owed to us from these entities to $364,667 at December 31, 2000 and
$350,467 at March 31, 2001. Under the terms of the indenture, all transactions
with affiliated entities must be conducted on an arm's length basis in
accordance with its terms.
OTHER TRANSACTIONS WITH RICHARD BOWMAN
The total amount owed to us by Mr. Bowman for travel and other business
expenses was $625,199 at December 31, 2000 and $662,251 at March 31, 2001. We do
not intend to advance to Mr. Bowman any material amounts for travel and other
business expenses. In addition, under the terms of the indenture, all
transactions with Mr. Bowman must be conducted on an arm's length basis in
accordance with its terms.
SATISFACTION OF CERTAIN RELATED PARTY TRANSACTIONS
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. In return for this assignment, promptly following the
closing of the original offering, we transferred to Atasca certain minor oil and
natural gas properties (totaling approximately 1.2 Bcfe, or 0.7% of our proved
reserves, as of December 31, 2000) owned by Tribo Petroleum Corporation and
assign to Atasca the
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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 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 approximately $2,151,000.
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. You cannot
understand this description of these notes without first reading and
understanding the definitions that are used in this description. 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 old notes have been, and the new notes will be, issued under an
indenture (the "Indenture") among Tri-Union, as issuer, and Firstar Bank,
National Association, as trustee (the "Trustee"). Upon effectiveness of this
registration statement the Indenture will be subject to and governed by the
Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"). The
following summaries of certain material provisions of the Indenture, the
Guaranty Agreement and the Security Documents do not purport to be complete and
are subject to, and are qualified in their entirety by reference to, all of the
provisions of the Indenture, the Guaranty Agreement and the Security Documents,
including the definition of certain terms contained therein and those terms that
are made a part of the Indenture by reference to the Trust Indenture Act. A copy
of the form of Indenture, the Guaranty Agreement or any Security Document may be
obtained from us. We urge you to read the Indenture, the Guaranty Agreement and
the Security Documents because they, not this description, define your rights as
a Holder.
GENERAL
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 (which
guarantees 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
Guarantors).
Tri-Union may issue the 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 "Original 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
Original Notes) for all purposes
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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 "Exchange Notes") that may be issued in exchange
for either the Original 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 Original Notes, the Exchange Notes and any Tack-On Senior Secured Notes are
collectively referred to as the "Notes" in this Description of Senior Secured
Notes.
Any Notes that remain outstanding after the completion of the exchange
offer, together with the Exchange 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. Please read "-- Amortization
Payments." The Notes bear interest at the rate of 12.5% per annum from the
Closing Date, payable semiannually to Holders of record at the close of business
on the May 15 or November 15 immediately preceding the interest payment date 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 such 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
thereon 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 and (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 and (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 and (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
Except as set forth in the following paragraph, the Notes will not be
redeemable at the option of Tri-Union prior to June 1, 2004. Thereafter, the
Notes will be redeemable, at Tri-Union's option, in whole or in part, at any
time or from time to time, upon not less than 30 nor more than 60 days' prior
notice by first-class mail to each Holder's registered address, at 104.0% of the
stated principal amount thereof, together with accrued and unpaid interest
thereon to the redemption date (subject to the right of Holders of record on the
relevant record date to receive interest due on the relevant interest payment
date), if redeemed on or after June 1, 2004, or at 100% of the stated principal
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amount thereof, together with accrued and unpaid interest thereon to the
redemption date, if redeemed on or after June 1, 2005.
In addition, at any time and from time to 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 thereof, together with accrued and unpaid interest thereon to the
redemption date (subject to the right of Holders of record on the relevant
record date to receive interest due on the relevant interest payment date);
provided, however, that the redemption occurs within 60 days after the
consummation of such Equity Offering and at least 70% of the then outstanding
aggregate principal amount of the Notes must remain outstanding after each such
redemption.
In the case of any partial redemption, selection of the Notes for
redemption will be made by the Trustee on a pro rata basis, by lot or by such
other method as the Trustee in its sole discretion shall deem to be fair and
appropriate, although no Note of $1,000 in original principal amount or less
shall be redeemed in part. If any Note is to be redeemed in part only, the
notice of redemption relating to such Note shall state the portion of the
principal amount thereof to be redeemed. A new Note in principal amount equal to
the unredeemed portion thereof will be issued in the name of the Holder thereof
upon cancellation of the original Note.
GUARANTEES
Tri-Union's Obligations are guaranteed (all such obligations guaranteed by
the Guarantors being herein called the "Guaranteed Obligations" and each such
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, as primary obligor and not merely as surety,
will irrevocably and unconditionally guarantee, on a joint and several basis,
the performance and the punctual payment when due, whether at their Stated
Maturity, by acceleration, by redemption or otherwise, of all the Obligations of
Tri-Union under the Indenture and the Notes. Each Subsidiary Guarantee will be
limited to an amount not to exceed the maximum amount that can, after giving
effect to all other contingent and fixed liabilities of the respective
Subsidiary Guarantor, be guaranteed by such Subsidiary Guarantor without
rendering such Subsidiary Guarantee voidable under applicable law relating to
fraudulent transfer or fraudulent conveyance or similar laws affecting the
rights of creditors generally. The Guarantors will agree to pay, in addition to
the amount stated above, any and all expenses (including reasonable counsel fees
and expenses) incurred by the Trustee and the Holders in enforcing any rights
under the Guarantee.
The Guarantee is a continuing guarantee and shall (a) remain in full force
and effect until payment in full in cash of all the Guaranteed Obligations, (b)
be binding upon the relevant Subsidiary Guarantor and (c) inure to the benefit
of and be enforceable by the Trustee, the Holders and their successors,
transferees and assigns as provided in the Indenture. Please read "-- Defaults."
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 (a) immediately after giving effect to such transaction, no Default or
Event of Default exists, and (b) immediately after giving effect to such
transaction on a pro forma basis, Tri-Union would be able to Incur an additional
$1.00 of Indebtedness pursuant to paragraph (a) of the covenant described under
the heading "-- Limitation on Indebtedness"; provided, however, that if such
Person is not Tri-Union or a Subsidiary Guarantor, such guarantor's obligations
under the Guaranty Agreement must be expressly assumed by such other Person.
However, upon the sale or disposition (by merger or otherwise) of any Subsidiary
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Guarantor to a Person permitted by the Indenture, such 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 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
by 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; provided
however that, with respect to any property securing Acquired Indebtedness,
Tri-Union's and each Subsidiary Guarantor's obligation to provide Liens to the
Collateral Agent on such property will be limited to the extent that granting a
Lien on such property is not prohibited by the terms of the instruments creating
such Acquired Indebtedness (including any Refinancing thereof); and provided
further that such Lien securing the Obligations and the Guaranteed Obligations,
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, including, but not limited to, foreclosing upon the Collateral 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. Holders of the Notes may not 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 as set forth in the Intercreditor Agreement:
(i) first: to the ratable payment and reimbursement of all fees,
expenses and indemnities owed to the Collateral Agent (including the
reasonable legal fees and expenses of its agents and counsel) pursuant to
the Security Documents;
(ii) second: to the payment to (a) the Approved Hedge Counterparties
under Approved Hedge Agreements for which an early termination date has
been designated of (I) the net amount due such Approved Hedge Counterparty
under all such terminated Approved Hedge Agreements to which it was a party
(whether as settlement amounts or unpaid amounts) and (II) all accrued and
unpaid interest thereon and all fees, expenses, cash collateralization
amounts, indemnities and other amounts owed to such Approved Hedge
Counterparty in respect thereof, (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 agent(s) or representative(s), if any, all cash collateralization
amounts, principal, interest, fees, expenses and indemnities owed to such
Hedge Liquidity Providers under their Hedge Liquidity Agreement; provided
that if such moneys shall not be sufficient to pay in full the entire
amount then outstanding, then to make pro rata payments, without any
preference or priority, to all such Approved Hedge Counterparties or Hedge
Liquidity Providers, as applicable;
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(iii) third: to the payment and reimbursement of all fees, expenses
and indemnities owed to the Trustee under or provided for under the
Indenture;
(iv) fourth: to the payment of accrued and unpaid interest on the
Notes payable under the Indenture, and if such moneys shall not be
sufficient to pay in full the entire amount then outstanding, then to make
pro rata payments, without any preference or priority, to each Holder;
(v) fifth: to the ratable payment of the outstanding principal balance
of the Notes (including any premium then due); and if such moneys shall not
be sufficient to pay in full the entire amount then outstanding, then to
make pro rata payments, without any preference or priority, to each Holder;
(vi) sixth: 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 such time as it determines that
all such obligations have been paid in full or pay any other amounts which
may be then due and owing thereunder or under any Security Document; and
(vii) seventh: to the payment of the remainder, if any, to Tri-Union
or as a court of competent jurisdiction may otherwise direct.
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 (as defined in the Intercreditor Agreement), 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, including,
but not limited to, the determination of whether to foreclose on the Collateral;
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, such 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, respectively, 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
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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
(a) Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
Incur, directly or indirectly, any Indebtedness; provided, however, that
Tri-Union or a Restricted Subsidiary may Incur Indebtedness if, on the date of
such Incurrence and after giving effect thereto, both (1) the Consolidated
Coverage Ratio equals or exceeds 2.5 to 1.0 and (2) Adjusted Consolidated Net
Tangible Assets equals or exceeds 150% of the aggregate consolidated
Indebtedness of Tri-Union and the Restricted Subsidiaries.
(b) Notwithstanding the preceding paragraph (a), Tri-Union and any
Restricted Subsidiary may Incur the following Indebtedness:
(1) 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;
(2) Indebtedness owed to and held by Tri-Union or a Wholly Owned
Subsidiary; provided, however, 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, in each case, to constitute the Incurrence of such
Indebtedness by the issuer thereof;
(3) the Notes (other than the Tack-On Senior Secured Notes), the
Indenture, the Security Documents and the Subsidiary Guarantees;
(4) Indebtedness outstanding on the Closing Date, to the extent not
discharged in Tri-Union's bankruptcy case;
(5) Refinancing Indebtedness in respect of Indebtedness Incurred
pursuant to paragraph (a) or pursuant to clause (3) or (4) above or clause
(6) below;
(6) Indebtedness of Tri-Union or a Restricted Subsidiary represented
by Capital Lease Obligations, mortgage financings or purchase money
obligations, in each case 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 in each case Incurred no
later than 365 days after the date of such acquisition or the date of
completion of such construction or improvement; provided, however, that the
principal amount of all such Indebtedness at any one time outstanding shall
not exceed $5,000,000;
(7) 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;
(8) 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 under the covenant 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 as margin in lieu of the collateral to secure excess
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market exposure and settlement and related amounts due on early termination
under the Approved Hedge Agreement and Security Documents;
(9) Non-Recourse Indebtedness;
(10) 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
(11) 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 such Incurrence (other
than Indebtedness permitted by clauses (1) through (10) above or paragraph
(a)) does not exceed $5,000,000.
(c) Notwithstanding the preceding, Tri-Union and the Restricted
Subsidiaries shall not Incur any Indebtedness pursuant to the preceding
paragraph (b) if the proceeds thereof are used, directly or indirectly, to
Refinance any Subordinated Obligations unless such Indebtedness shall be
subordinated to the Notes to at least the same extent as such Subordinated
Obligations.
(d) For purposes of determining compliance with the preceding covenant, (i)
in the event that 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 such item of Indebtedness and only be required to include the
amount and type of such Indebtedness in one of the above clauses and (ii) an
item of Indebtedness may be divided and classified in more than one of the types
of Indebtedness described above.
Limitation on Restricted Payments
(a) Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
directly or indirectly, make a Restricted Payment unless, at the time of such
Restricted Payment:
(1) no Default or Event of Default shall have occurred and be
continuing or would occur as a consequence thereof;
(2) immediately after giving effect thereto on a pro forma basis,
Tri-Union could incur at least $1.00 of additional Indebtedness under
clause (a) of the covenant described under the heading "-- Limitation on
Indebtedness"; and
(3) such 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 the following:
(A) 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 such Restricted
Payment (or, if such Consolidated Net Income for such period is a
deficit, less 100% of such deficit), plus
(B) 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, such Capital Stock (other than any such 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
(C) 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 (1) the cash return
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of capital with respect to such Permitted Investment (less the cost of
disposition, if any) and (2) the initial amount of such Permitted
Investment, plus
(D) in the event that any Unrestricted Subsidiary is redesignated
as a Restricted Subsidiary, the lesser of (1) an amount equal to the
fair market value of the Investments in such Subsidiary previously made
by Tri-Union and its Restricted Subsidiaries as of the date of such
redesignation and (2) the amount of such Investments, plus
(E) $1,000,000.
(b) The provisions of the preceding paragraph (a) shall not prohibit:
(1) the payment of any dividend within 60 days after the date of
declaration of such dividend if the dividend would have been permitted on
the date of declaration;
(2) 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 Subsidiary, either (A)
solely in exchange for shares of Capital Stock of Tri-Union (other than
Disqualified Stock) or (B) 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;
(3) 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 (A) solely in exchange for shares of Capital Stock (other
than Disqualified Stock) of Tri-Union, (B) 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 (C) through Refinancing Indebtedness that also
constitutes Subordinated Obligations; or
(4) 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 (if applicable);
(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 (if
applicable) (each such encumbrance or restriction, a "Payment
Restriction").
The preceding will not apply, however, to encumbrances or restrictions
existing under or by reason of the following (which are excluded from the term
"Payment Restriction"):
(1) applicable law;
(2) the Indenture or any Security Document;
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(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 such
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;
(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 such 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, to the extent and only
to the extent such instrument restricts the transfer or other disposition
of assets subject to such 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, however,
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 such clause (2), (4) or (5); and
(9) any instrument governing a Working Capital Revolver, to the extent
and only to the extent such instrument restricts the transfer or other
disposition of accounts receivable, related general intangibles and related
proceeds of Tri-Union and the Restricted Subsidiaries securing such Working
Capital Revolver.
Limitation on Sales of Assets
(a) Tri-Union will not, and will not cause or permit any of the Restricted
Subsidiaries to, consummate an Asset Disposition unless:
(1) Tri-Union or the relevant Restricted Subsidiary, as the case may
be, receives consideration at the time of such Asset Disposition 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
(2) at least 70% of the consideration received by Tri-Union or such
Restricted Subsidiary, as the case may be, from such Asset Disposition
shall be in the form of cash or Temporary Cash Investments and is received
at the time of such disposition.
Within 270 days after an Asset Disposition, Tri-Union or such Restricted
Subsidiary shall apply or cause to be applied the Net Available Cash of such
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 such Net Available Cash is applied to, within 270 days of
such Asset Disposition, (i) an Investment or Investments in Additional Assets,
(ii) an Investment or Investments in properties or assets that replace the
properties or assets that were the subject of such Asset Disposition (the
"Replacement Assets"), and the assets constituting such Additional Assets or
Replacement Assets and any non-cash consideration received
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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 (iii) to the extent such 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 such Asset
Disposition together with a concomitant permanent reduction in the amount of
such Indebtedness so repaid; provided, however, that such 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 such Major Asset Sale at
a purchase price equal to 100% of the stated principal amount of such Notes,
together with accrued interest (if any) 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 will be mailed
to the Holders as shown on the register of Holders not less than 30 days nor
more than 60 days before the payment date for the Excess Proceeds Offer or Major
Asset Sale Offer, as the case may be, with a copy to the Trustee, and 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). An Excess Proceeds Offer or
Major Asset Sale Offer shall remain open for a period of 20 Business Days or
such longer periods as may be required by law.
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
thereunder in the event that it is required to make an Excess Proceeds Offer or
a Major Asset Sale Offer as described above. 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.
(b) 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 that is permitted by the covenant described
under the heading "-- Merger and Consolidation," the Successor Company shall be
deemed to have sold the properties and assets of Tri-Union not so transferred
for purposes of this covenant, and shall comply with the provisions of this
covenant with respect to such 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.
(c) All Net Available Cash shall constitute Trust Moneys and shall be
delivered by Tri-Union, as applicable, to the Collateral Agent and shall be
deposited in the Collateral Account in accordance
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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
(a) Tri-Union shall not, and shall not permit any Restricted Subsidiary to,
enter into or permit to exist any transaction (including the purchase, sale,
lease or exchange of any stock, property, employee compensation arrangements or
the rendering of any service) with any Affiliate of Tri-Union (an "Affiliate
Transaction") unless the terms thereof (1) are no less favorable to Tri-Union or
such Restricted Subsidiary than those that could be obtained at the time of such
transaction in arm's-length dealings with a Person who is not such an Affiliate,
(2) if such Affiliate Transaction involves an amount between $500,000 and
$3,000,000, are certified in an officers' certificate to the effect that such
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 such Affiliate Transaction or (3) if such Affiliate
Transaction involves an amount in excess of $3,000,000, are certified in an
officers' certificate to the effect that such 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 such 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.
(b) The provisions of the preceding paragraph (a) shall not prohibit (i)
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;
(ii) transactions exclusively between or among the Restricted Subsidiaries;
provided, however, that such transactions are not otherwise prohibited by the
Indenture; and (iii) 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 such Holder's Notes at a purchase
price in cash equal to 101% of the stated principal amount thereof, 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 such Holder has the right to require Tri-Union to
purchase such Holder's Notes at a purchase price in cash equal to 101% of the
stated principal amount thereof, 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 such Change of Control (including
information with respect to pro forma historical income, cash flow and
capitalization after giving effect to such Change of Control); (3) the
repurchase date (which shall be no earlier than 30 days nor later than 60 days
from the date such 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
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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 the Initial Purchaser. 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 under the Indenture, but that
could increase the amount of Indebtedness outstanding at such 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, however, 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 (i) makes such offer in the
manner, at the times and otherwise in compliance with the requirements set forth
in the Indenture relating to Tri-Union's obligations to make such an offer and
(ii) purchases all Notes validly tendered and not withdrawn under such 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 (i) to Tri-Union or a Wholly Owned
Subsidiary, (ii) if all shares of Capital Stock of such Restricted Subsidiary
(other than Tri-Union) are sold or otherwise disposed of or (iii) to the extent
such 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 (ii), 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, such 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
(i) Tri-Union or such Restricted Subsidiary would be entitled to Incur
Indebtedness in an amount equal to the Attributable Debt with respect to such
Synthetic Lease pursuant to the covenant described under the heading
"-- Limitation on Indebtedness," (ii) the net cash proceeds received by
Tri-Union or any Restricted Subsidiary in connection with such Synthetic Lease
are at least equal to the fair value (as determined by the Board of Directors of
Tri-Union) of such property and (iii) Tri-Union or such Restricted Subsidiary
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shall apply or cause to be applied the proceeds of such transaction in
compliance with the covenant described under the heading "-- Limitation on Sales
of Assets."
Future Subsidiary Guarantors
From and after the Closing Date, Tri-Union shall cause each of its
Subsidiaries which is or becomes a Restricted Subsidiary to execute an
Assumption Agreement in the form of Annex 1 to 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 (i) Tri-Union shall be the
resulting, surviving or transferee corporation (the "Successor Company"), (ii)
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; (iii) immediately
after giving effect to such transaction on a pro forma basis (and, treating any
Indebtedness which becomes an obligation of the Successor Company as a result of
such transaction as having been issued by such Person at the time of such
transaction), no Default shall have occurred and be continuing; (iv) immediately
after giving effect to such transaction, the Successor Company would be able to
Incur an additional $1.00 of Indebtedness pursuant to paragraph (a) of the
covenant described under the heading "-- Limitation on Indebtedness"; (v)
immediately after giving effect to such 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 such transaction; and (vi) Tri-Union
delivers to the Trustee an officers' certificate and an opinion of counsel, each
stating that such consolidation, merger or transfer and such 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 (i) 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" that describes the financial condition and results of
operations of Tri-Union and its Subsidiaries, determined on a consolidated basis
in accordance with GAAP, (showing in reasonable detail, either on the face of
the financial statements or in the footnotes thereto and in "Management's
Discussion and Analysis of Financial Condition and Results of Operations," the
financial conditions and results of operations of Tri-Union and the Restricted
Subsidiaries separate from the financial condition and results of operations of
the Unrestricted Subsidiaries) and, with respect to the annual information only,
a report thereon by Tri-Union certified independent accountants, and (ii) all
current reports that would be required to be filed with the SEC on Form 8-K if
Tri-Union were required to file such reports, in each case within 15 days after
the time periods specified for such filings in the SEC's rules and regulations;
provided, however, 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 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
such annual and quarterly reports and such information, documents and other
reports specified in Sections 13 and 15(d) of the Exchange Act.
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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
(a) If, after the Closing Date, Tri-Union or any of the Restricted
Subsidiaries shall (i) acquire any (x) Oil and Gas Assets or (y) other assets as
non-cash consideration for any Asset Disposition or (ii) 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 such 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 such new assets.
(b) Without limitation of clause (a), 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 such Acquired
Indebtedness, a junior Lien), on such portion of such assets as is necessary to
ensure that the Lien of the Indenture and the Security Documents covers
substantially all of such assets received in exchange or trade or on such
interests in such Permitted Joint Venture.
(c) In connection with any Security Documents executed and filed under
clause (a) or (b), Tri-Union shall, and shall cause each Restricted Subsidiary
to, comply with the terms of the Trust Indenture Act to the extent applicable.
(d) 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 preceding January 1st to ascertain
whether substantially all of such 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 such Oil and Gas Assets may be
excluded to the extent the instruments securing such Acquired Indebtedness
prohibit the Incurrence of a Lien on such assets. If
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substantially all of such 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 such Acquired Indebtedness,
a junior Lien), as is necessary or appropriate to encumber substantially all
such assets.
Reserve Reports
(a) Not later than March 15 of each year, commencing March 15, 2002,
Tri-Union shall furnish to the Trustee a Reserve Report that (i) evaluates the
Oil and Gas Assets of Tri-Union and the Restricted Subsidiaries as of the
immediately preceding January 1st, and (ii) 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 such 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.
(b) With the delivery of each March 15 Reserve Report, Tri-Union shall
provide to the Trustee, an officers' certificate certifying that, in all
material respects: (i) the information contained in the Reserve Report and any
other information delivered in connection therewith is true and correct, (ii)
Tri-Union and/or a Restricted Subsidiary owns good and defensible title to the
Oil and Gas Assets evaluated in such Reserve Report and such properties are free
of all Liens except for Permitted Liens, (iii) except as set forth on an exhibit
to the certificate, on a net basis there are no gas imbalances, take or pay or
other prepayments with respect to the Oil and Gas Assets evaluated in such
Reserve Report which would require Tri-Union or a Restricted Subsidiary to
deliver hydrocarbons produced from such Oil and Gas Assets at some future time
without then or thereafter receiving full payment therefor, (iv) none of the Oil
and Gas Assets have been sold since the date of the last Reserve Report except
as set forth on an exhibit to the certificate, which certificate shall list all
of its Oil and Gas Assets sold, (v) attached to the certificate is a list of the
Oil and Gas Assets added to and deleted from the immediately prior Reserve
Report and a list of all Persons disbursing proceeds to Tri-Union or a
Restricted Subsidiary from the Oil and Gas Assets, (vi) except as set forth on a
schedule attached to the certificate all of the Oil and Gas Assets evaluated by
such Reserve Report are subject to the Lien created by the Security Documents
and showing calculations to demonstrate compliance with clause (d) of the
covenant "-- Lien on Additional Collateral" and (vii) any change in working
interest or net revenue interest in its Oil and Gas Assets occurring and the
reason for such change.
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 from the first day of the month
following the month in which the Closing Date occurs (subject to the
availability of hedge contracts) to July 1, 2006, Tri-Union and/or a Restricted
Subsidiary will have a
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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:
(i) 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;
(ii) 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 (iv)
below or (B) a replacement Oil and Gas Hedging Contract with an Approved
Hedge Counterparty is entered into such that, after giving effect to such
termination and the execution and delivery of such replacement Oil and Gas
Hedging Contract, the Hedged Revenue Ratio is not less than 3.0 to 1.0,
subject to clause (i) of this covenant;
(iii) 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 such Make-Up Period, and as soon thereafter as
available hedge prices for such Make-Up Period or any month during such
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 (i) of this covenant; and
(iv) 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 such asset
reflected in the most recently delivered Reserve Report) as of the first
day of the month during which such 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 such
Hedge Period or (B) terminate one or more Oil and Gas Hedging Contracts
such that after giving effect to such 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.
For the avoidance of doubt, it is the intention of the parties under this
covenant 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
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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 established in clause (i) 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 such 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
thereof, plus accrued interest, if any, to the date of purchase; provided that
the amount required to be paid by Tri-Union to repurchase such Notes shall be
limited to an amount equal to 50% of such 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 such 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 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 thereof tendered pro rata or by such other
method as may be required by law.
If an Excess Cash Flow Offer is required by the terms of the Indenture,
Tri-Union shall commence such offer by mailing to the Trustee and each Holder,
at such Holder's last registered address, a notice, which shall govern the terms
of the Excess Cash Flow Offer and shall state:
(1) that the Excess Cash Flow Offer is being made pursuant to this
covenant "Excess Cash Flow Offer," the principal amount of Notes which
shall be accepted for payment and that all Notes validly tendered for which
the Holders thereof have requested prepayment shall be accepted for payment
on a pro rata basis (or by such other method as may be required by law);
(2) the purchase price and the date of purchase;
(3) that any Notes not tendered or accepted for payment pursuant to
the Excess Cash Flow Offer shall continue to accrue interest;
(4) that, unless Tri-Union defaults in the payment of the purchase
price with respect to any Notes tendered, Notes accepted for payment
pursuant to the Excess Cash Flow Offer shall cease to accrue interest after
the Excess Cash Flow Payment Date;
(5) that Holders electing to have Notes purchased pursuant to an
Excess Cash Flow Offer shall be required to surrender their Notes, with the
form entitled "Option of Holder to Elect Purchase" on the reverse of the
Note completed, to Tri-Union prior to the close of business on the third
Business Day immediately preceding the Excess Cash Flow Payment Date;
(6) that Holders shall be entitled to withdraw their election if
Tri-Union receives, not later than the close of business on the second
Business Day preceding the Excess Cash Flow Payment Date, a telegram,
facsimile transmission or letter setting forth the name of the Holder, the
principal amount of Notes the Holder delivered for purchase and a statement
that such Holder is withdrawing his election to have such Notes purchased;
(7) that 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, Tri-Union and its
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Restricted Subsidiaries may use the remaining Excess Cash Flow for general
corporate purposes not prohibited by the terms of the Indenture;
(8) that Holders whose Notes are purchased only in part shall be
issued Notes representing the unpurchased portion of the Notes surrendered,
provided that each Note purchased and each new Note issued shall be in
principal amount of $1,000 or whole multiples thereof; and
(9) the instructions that Holders must follow in order to tender their
Notes.
On or before the Excess Cash Flow Payment Date, Tri-Union shall (i) accept
for payment, on a pro rata basis to the extent necessary (unless some other
method is required by law), the Notes or portions thereof tendered pursuant to
the Excess Cash Flow Offer, (ii) deposit with the Paying Agent money sufficient
to pay the purchase price of all Notes or portions thereof so accepted and (iii)
deliver to the Trustee the Notes so accepted, together with an Officers'
Certificate stating that the Notes or portions thereof tendered to Tri-Union are
accepted for payment. The Paying Agent shall promptly mail to each Holder of
Notes so accepted payment in an amount equal to the purchase price of such
Notes, including accrued and unpaid interest, and Tri-Union shall issue new
Notes, and the Trustee shall promptly authenticate and mail such new Notes to
such Holders, in a principal amount equal to the unpurchased portion of the Note
surrendered.
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.
For the purposes of this covenant, the Trustee shall act as the Paying Agent.
Each Excess Cash Flow Offer shall be conducted in compliance with all
applicable laws, including without limitation, Regulation 14E of the Exchange
Act and the rules thereunder and all other applicable federal and state
securities laws. 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.
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 such composition of the Board of Directors shall be
maintained so long as any of the Notes remain outstanding. Until such time as 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 & Company, Inc. shall have the right to require that
Tri-Union cause to be appointed to its Board of Directors a person designated by
Jefferies & Company, Inc. 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 (i) a default in the
payment of interest on the Notes when due, continued for 30 days, (ii) 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,
(iii) the failure by Tri-Union to comply with its obligations described under
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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," (iv) 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," (v) 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, (vi) 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 Subsidiary in excess of $5,000,000
and the maturity thereof is accelerated by the holders thereof (the "cross
acceleration provision"), (vii) certain events of bankruptcy, insolvency or
reorganization of Tri-Union or a Restricted Subsidiary (the "bankruptcy
provisions"), (viii) 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 such judgment and is not
discharged, waived or stayed within 10 days after notice from the Trustee or any
Holder (the "judgment default provision"), (ix) the Guaranty Agreement or any
Security Document ceases to be in full force and effect (other than in
accordance with the terms of such Guaranty Agreement or such 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 such default continues for a period of 10 days after notice from
the Trustee or any Holder thereof to Tri-Union, or (x) 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
(iv), (v), (viii) and (x) 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 Guarantor does not
cure such default within the time specified after receipt of such 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, such 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 such 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 (i) such Holder has
previously given the Trustee notice that an Event of Default is continuing, (ii)
Holders of at least 25% in principal amount of the outstanding Notes have
requested the Trustee to pursue the remedy, (iii) such Holders have offered the
Trustee reasonable security or indemnity
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against any loss, liability or expense, (iv) the Trustee has not complied with
such request within 60 days after the receipt thereof and the offer of security
or indemnity and (v) the Holders of a majority in principal amount of the
outstanding Notes have not given the Trustee a direction inconsistent with such
request within such 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 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.
The Indenture provides that 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 thereof knows of
any Default that occurred during such 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, (i) reduce the amount of Notes whose Holders must consent to an
amendment, (ii) reduce the rate of or extend the time for payment of interest on
any Note, (iii) reduce the principal of or extend the Stated Maturity of any
Note, (iv) reduce the premium payable upon the redemption of any Note or change
the time at which any Note may be redeemed, (v) make any Note payable in any
currency other than that stated in the Note, (vi) impair the right of any Holder
to receive payment of principal of and interest and any additional interest on
such 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 such
Holder's Notes, (vii) make any change in the amendment provisions which require
each Holder's consent or in the waiver provisions, (viii) make any change in any
Subsidiary Guarantee or any Security Document that could adversely affect such
Holder, or (ix) 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 such 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, however, that (i) the
provisions of the Intercreditor Agreement governing application of proceeds (and
the defined terms used therein) 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), (ii) 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
(iii) no Security Document may be amended if the effect thereof 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 such amendment. However, the failure to give such
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 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 below 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 Released Interests (as defined below) from the
Lien of the Security Documents and reconvey the Released Interests to Tri-Union
or the relevant Restricted
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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 (the "Released
Interests") upon compliance with the condition that Tri-Union deliver to the
Collateral Agent and the Trustee the following:
(1) a notice from Tri-Union requesting the release of Released
Interests:
(A) describing the proposed Released Interests,
(B) specifying the value, as reasonably determined by Tri-Union, of
such Released Interests on a date within 60 days of such notice from
Tri-Union,
(C) stating that the purchase price or other property to be
received in consideration for such Released Interests is at least equal
to the fair market value of the Released Interests,
(D) stating that the release of such Released Interests will not
interfere with the Collateral Agent's ability to materially realize the
value of the remaining Collateral and will not materially impair the
maintenance and operation of the remaining Collateral,
(E) confirming the sale, lease, transfer or other disposition of,
or an agreement to sell, lease, transfer or dispose of, such Released
Interests in a bona fide transaction to a Person that is not an
Affiliate of Tri-Union or, in the event that such disposition is to a
Person that is an Affiliate, confirming that such disposition is made in
compliance with the provisions described under the heading "-- Certain
Covenants -- Limitation on Affiliate Transactions," to the extent
applicable, and
(F) in the event there is to be a substitution of property for the
Collateral subject to the sale, lease, transfer or other disposition,
specifying the property intended to be substituted for the Collateral to
be disposed of;
(2) an officers' certificate of Tri-Union stating that:
(A) such sale, lease, transfer or other disposition complies with
the terms and conditions of the Approved Hedging Agreements, the Hedge
Liquidity Agreements (if applicable), and Indenture with respect to
Asset Dispositions, Restricted Payments and sales of Capital Stock of
Restricted Subsidiaries to the extent applicable,
(B) all Net Available Cash from such sale, lease, transfer or other
disposition will be applied pursuant to the provisions of the Hedge
Liquidity Agreements, Approved Hedge Agreements and the Indenture to the
extent applicable,
(C) there is no Event of Default or Triggering Event or Termination
Event under any of the Principal Agreements that is in effect or
continuing on the date thereof or the date of such sale, lease, transfer
or other disposition,
(D) the release of the Collateral will not result in an Event of
Default under the Approved Hedging Agreements, the Hedge Liquidity
Agreements (if applicable) and the Indenture, and
(E) upon the delivery of such officers' certificate, all conditions
precedent in the Approved Hedging Agreements, the Hedge Liquidity
Agreements (if applicable) and the Indenture relating to the release in
question will have been complied with; and
(3) all other documentation required by the Trust Indenture Act, if
any, prior to the release of Collateral and, in the event there is to be a
contemporaneous substitution of property for the Collateral subject to the
sale, lease, transfer or other disposition, all documentation necessary to
effect the substitution of such new Collateral.
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Upon compliance by Tri-Union and the Restricted Subsidiaries, with the
conditions set forth below in respect of any instrument governing a Working
Capital Revolver, to the extent and only to the extent such 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 Released Working Capital
Revolver Interests (as defined below) from the Lien of the Indenture and the
Security Documents and reconvey the Released Working Capital Revolver Interests
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 such 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 "Released Working
Capital Revolver Interests") upon compliance with the condition that Tri-Union
deliver to the Collateral Agent and the Trustee the following:
(1) a notice from Tri-Union requesting the release of the Released
Working Capital Revolver Interests:
(A) describing the proposed Released Working Capital Revolver
Interests,
(B) specifying the value, as determined by Tri-Union, of such
Released Working Capital Revolver Interests on a date within 60 days of
the notice from Tri-Union,
(C) stating that the release of such Released Working Capital
Revolver Interests will not interfere with the Collateral Agent's or the
Trustee's ability to materially realize the value of the remaining
Collateral and will not materially impair the maintenance and operation
of the remaining Collateral, and
(D) confirming that the Incurrence of the Working Capital Revolver
and the Lien on the Released Working Capital Revolver Interests is in
compliance with the covenants described under the headings "-- Certain
Covenants -- Limitation on Indebtedness" and "-- Limitation on Liens" to
the extent applicable;
(2) an officers' certificate of Tri-Union stating that:
(A) such release complies with the terms and conditions of the
Approved Hedge Agreements, the Hedge Liquidity Agreements (if
applicable) and Indenture with respect to the covenants described under
the headings "-- Certain Covenants -- Limitations on Indebtedness" and
"Limitations on Liens" to the extent applicable,
(B) there is no Event of Default or Triggering Event or Termination
Event under any of the Principal Agreements or the Intermediation
Agreement in effect or continuing on the date thereof or the date of
such Incurrence of Indebtedness under the Working Capital Revolver,
(C) the release of the Collateral will not result in an Event or
Termination Event under any of the Principal Agreements of Default under
the Approved Hedging Agreements, the Hedge Liquidity Agreements (if
applicable) and Indenture, and
(D) upon the delivery of such officers' certificate, all conditions
precedent in the Approved Hedging Agreements, the Hedge Liquidity
Agreements (if applicable) and Indenture relating to the release in
question will have been complied with; and
(3) all other documentation required by the Trust Indenture Act, if
any, prior to the release of Collateral.
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
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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
such 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 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
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 such 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 such funds will be applied in accordance with such
covenant, or (B) if such Trust Moneys do not represent Net Available Cash,
subject to the covenant described under the heading "-- Certain
Covenants -- Limitation on Sales of Assets," that such 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
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(4) all documentation required by the Trust Indenture Act, if any,
prior to the release of such Trust Moneys has been delivered to the
Collateral Agent and the Trustee.
Notwithstanding the preceding, (A) 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 (B) 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.
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 in clauses (iv) and (v) of the first paragraph and (iii)
and (iv) of the second paragraph 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 (iv), (v), (vi), (vii) (with respect only
to Restricted Subsidiaries) or (viii) under the heading "-- Defaults" above or
because of the failure to comply with clause (iv) or (v) of the first paragraph
or (iii) or (iv) of the second paragraph 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 such deposit and defeasance and will
be subject to federal income tax on the same
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amount and in the same manner and at the same times as would have been the case
if such 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. The Indenture provides
that if an Event of Default occurs (and is not cured), the Trustee will be
required, in the exercise of its power, to 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 such 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.
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 such nominee, as the case may be, will be considered the
sole owner or holder of the Notes represented by such 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 thereof.
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 such 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 such 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 such customers. Such payments will be the responsibility of such
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.
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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 such portion of
the aggregate principal amount of any Note as to which such 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 such procedures, and
such 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 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 thereof 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 (b)(6) of the
covenant described under the heading "-- Certain Covenants -- Limitation on
Indebtedness."
"Additional Assets" means (i) any property or assets (other than cash or
cash equivalents, Indebtedness and Capital Stock) used or useful in the Oil and
Gas Business; or (ii) the Capital Stock of a Person that becomes a Restricted
Subsidiary as a result of the acquisition of such Capital Stock by Tri-Union or
a Restricted Subsidiary; provided, however, that any such Restricted Subsidiary
described in clause (ii) above is primarily engaged in the Oil and Gas Business.
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"Adjusted Consolidated Net Tangible Assets" means (without duplication), as
of the date of determination,
(a) the sum of:
(i) 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 (A)
estimated proved oil and gas reserves of Tri-Union and any Restricted
Subsidiaries attributable to any material acquisition consummated since
the date of such year-end reserve report, and (B) 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 such year-end reserve
report which would, in the case of determinations made pursuant to
clauses (A) and (B), 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 such
year-end reserve report), and decreased by, as of the date of
determination, the discounted future net revenues of (C) estimated
proved oil and gas reserves of Tri-Union and any Restricted Subsidiaries
produced or disposed of since the date of such year-end reserve report
and (D) reductions in the estimated proved oil and gas reserves of
Tri-Union and any Restricted Subsidiaries since the date of such
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 such year-end reserve report which
would, in the case of determinations made pursuant to clauses (C) and
(D), in accordance with standard industry practice, result in such
determinations, in each case calculated in accordance with SEC
guidelines (utilizing the prices utilized in such year-end reserve
report); provided that, in the case of each of the determinations made
pursuant to clauses (A) through (D), such increases and decreases shall
be as estimated by Tri-Union's engineers unless, if as a result of such
acquisitions, dispositions, discoveries, extensions or revisions, there
is a Material Change, then such increases and decreases in the
discounted future net revenue shall be confirmed in writing by an
independent petroleum engineer;
(ii) 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;
(iii) the Net Working Capital on a date no earlier than the date of
Tri-Union's latest annual or quarterly financial statements; and
(iv) 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 such assets if no such appraisal
has been performed); minus
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(b) the sum of:
(i) minority interests;
(ii) any gas balancing liabilities of Tri-Union and any Restricted
Subsidiaries reflected in Tri-Union's latest audited financial
statements;
(iii) 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;
(iv) 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
(v) 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
specified in the immediately preceding clause (a)(i) (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 such specified Person, and if such Person is an individual, any
family member of such Person within four degrees of consanguinity and spouses of
such 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
such 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 such term under the heading
"-- Certain Covenants -- Limitation on Affiliate Transactions."
"Approved Hedge Agreement" means (A) any Oil and Gas Hedging Contract with
Bank of America, N.A., (B) any Oil and Gas Hedging Contract with any other
Approved Hedge Counterparty (i) which designates in the confirmation or other
transaction statement pursuant to which such 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 (ii) a
copy of which has been delivered to the Collateral Agent and the Trustee, in
case of either (A) or (B) until (a) the Approved Hedge Counterparty ceases to be
an Approved Hedge Counterparty under the Intercreditor Agreement or (b) the
Approved Hedge Counterparty specifies in writing to the Collateral Agent, the
Trustee and Tri-Union that such contract ceased to be an Approved Hedge
Agreement, and (C) 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 such contract, neither Tri-Union nor any Restricted Subsidiary will have
any liability other than the payment of an initial premium price.
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"Approved Hedge Counterparties" means (A) Bank of America, N.A., unless it
has ceased to be an Approved Hedge Counterparty, (B) any other Person that (i)
executes an Oil and Gas Hedging Contract with Tri-Union or a Restricted
Subsidiary, (ii) 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., (iii) is designated as such by Tri-Union in writing to
the Trustee and the Collateral Agent and (iv) if no Hedge Liquidity Provider is
then (or thereafter) providing letters of credit as collateral for the Hedging
Obligations owed to such Person or such 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 (C) for purposes of
the covenant "-- Hedging Obligations" and the definition of "Hedged Revenues"
only, the Persons in Clauses (A) and (B) above and any Person who meets the
requirement set forth in subclause (B)(ii) above and who enters into any Oil and
Gas Hedging 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 such 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 (i) 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), (ii) all or substantially all the assets of any division
or line of business of Tri-Union or any Restricted Subsidiary or (iii) any other
assets of Tri-Union or any Restricted Subsidiary outside of the ordinary course
of business of Tri-Union or such 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, however, that at the time of such sale or transfer such 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 such 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 such 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 such Restricted Subsidiary's pro rata
Investment in such Person shall represent a reasonably equivalent value of
proved reserves and (B) such Person is or becomes by virtue of such 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 such
Synthetic Lease (including any period for which such 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 (i) the sum
of the products of numbers of years from the date of determination to the dates
of each successive scheduled principal payment of such Indebtedness or
redemption or similar payment with respect to such Preferred Stock multiplied by
the amount of such payment by (ii) the sum of all such payments.
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"Board of Directors" means with respect to any Person, the board of
directors of such Person or any committee thereof duly authorized to act on
behalf of such 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 such
obligation shall be the capitalized amount of such 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 such lease prior to the first
date upon which such 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 such Person, including any Preferred
Stock, but excluding any debt securities convertible into such equity and any
warrants or options granted to directors, officers or employees of such 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:
(a) 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 (a) such person shall
be deemed to have "beneficial ownership" of all shares that such person has
the right to acquire, whether such 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, however,
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 (a),
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 (a)), directly, or
indirectly, of more than 35% of the voting power of the Voting Stock of
such parent corporation and the Permitted Holders beneficially own (as
defined in this proviso), directly or indirectly, in the aggregate a lesser
percentage of the voting power of the Voting Stock of such 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 such parent corporation);
(b) during any period of two consecutive years from and after the
Closing Date, individuals who at the beginning of such period constituted
the Board of Directors of Tri-Union (together with any new directors whose
election by such 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 such 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
(c) 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 such 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,
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unless pursuant to such transaction such securities are changed into or
exchanged for, in addition to any other consideration, securities of the
surviving corporation that represent immediately after such 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 such 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 (i) 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 such determination to (ii) Consolidated Interest Expense
for such four fiscal quarters; provided, however, that (1) if Tri-Union or any
Restricted Subsidiary has Incurred any Indebtedness since the beginning of such
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 such period shall be
calculated after giving effect on a pro forma basis to such Indebtedness as if
such Indebtedness had been Incurred on the first day of such period and the
discharge of any other Indebtedness repaid, repurchased, defeased or otherwise
discharged with the proceeds of such new Indebtedness as if such discharge had
occurred on the first day of such period, (2) if Tri-Union or any Restricted
Subsidiary has repaid, repurchased, defeased or otherwise discharged any
Indebtedness since the beginning of such 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 such period shall be
calculated on a pro forma basis as if such discharge had occurred on the first
day of such period and as if Tri-Union or such Restricted Subsidiary has not
earned the interest income actually earned during such period in respect of cash
or Temporary Cash Investments used to repay, repurchase, defease or otherwise
discharge such Indebtedness, (3) if since the beginning of such 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 such 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 such period and Consolidated
Interest Expense for such 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 such Asset Disposition for such period (or, if
the Capital Stock of any Restricted Subsidiary is sold, the Consolidated
Interest Expense for such period directly attributable to the Indebtedness of
such Restricted Subsidiary to the extent Tri-Union and the continuing Restricted
Subsidiaries are no longer liable for such Indebtedness after such sale), (4) if
since the beginning of such 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 such period shall be
calculated after giving pro forma
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effect thereto (including the Incurrence of any Indebtedness) as if such
Investment or acquisition occurred on the first day of such period and (5) if
since the beginning of such 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 such period) shall have made any Asset
Disposition, any Investment or acquisition of assets that would have required an
adjustment pursuant to clause (3) or (4) above if made by Tri-Union or a
Restricted Subsidiary during such period, EBITDA and Consolidated Interest
Expense for such period shall be calculated after giving pro forma effect
thereto as if such Asset Disposition, Investment or acquisition occurred on the
first day of such 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 such 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 such Indebtedness
if such 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 such period, determined
on a consolidated basis in accordance with GAAP, plus, to the extent not
included in such total interest expense, without duplication, (i) interest
expense attributable to capital leases and imputed interest with respect to
Attributable Debt, (ii) capitalized interest, (iii) non-cash interest expenses,
(iv) commissions, discounts and other fees and charges owed with respect to
letters of credit and bankers' acceptance financing, (v) 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, (vi) 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 such dividends would
result in a bankruptcy of the issuer thereof and (vii) interest accruing on any
Indebtedness of any other Person to the extent such 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 such Indebtedness
constitutes Indebtedness of Tri-Union or any Restricted Subsidiary (whether or
not such guarantee or Lien is called upon); provided, however, "Consolidated
Interest Expense" shall not include any (x) 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, (y)
amortization of debt discount to the extent it relates to revaluations of
financial instruments recognized in connection with the consolidation, and (z)
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 such caps or options.
"Consolidated Net Income" means, for any period, the net income of
Tri-Union and the consolidated Subsidiaries; provided, however, that there shall
not be included in such Consolidated Net Income any of the following (without
duplication): (i) any net income of any Person (other than Tri-Union) if such
Person is not a Restricted Subsidiary, except that (A) subject to the exclusion
contained in clause (iv) below, Tri-Union's equity in the net income of any such
Person for such period shall be included in such Consolidated Net Income up to
the aggregate amount of cash actually distributed by such Person during such
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 (iii) below) and
(B) Tri-Union's equity in a net loss of any such Person for such period shall be
included in determining such Consolidated Net
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Income; (ii) 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 such acquisition; (iii) any net income of any
Restricted Subsidiary if such Restricted Subsidiary is subject to restrictions,
directly or indirectly, on the payment of dividends or the making of
distributions by such Restricted Subsidiary, directly or indirectly, to
Tri-Union, except that (A) subject to the exclusion contained in clause (iv)
below, Tri-Union's equity in the net income of any such Restricted Subsidiary
for such period shall be included in such Consolidated Net Income up to the
aggregate amount of cash actually distributed by such Restricted Subsidiary
during such 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 any such Restricted
Subsidiary for such period shall be included in determining such Consolidated
Net Income; (iv) 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; (v)
extraordinary gains or losses; and (vi) 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 (i) the par or stated value of all outstanding
Capital Stock of the Person plus (ii) paid-in capital or capital surplus
relating to such Capital Stock plus (iii) 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 (i) matures or is mandatorily redeemable pursuant to a sinking fund
obligation or otherwise, (ii) is convertible or exchangeable for Indebtedness or
Disqualified Stock or (iii) is redeemable, in whole or in part, at the option of
the holder thereof, in each case described in this clause (iii) and in the
immediately preceding clauses (i) and (ii), on or prior to the Stated Maturity
of the Notes; provided, however, that any Capital Stock that would not
constitute Disqualified Stock but for provisions thereof giving holders thereof
the right to require such Person to repurchase or redeem such 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 such Capital Stock
are not more favorable to the holders of such 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 such
period, Consolidated Interest Expense for such period, and each of the following
(without duplication) to the extent deducted in calculating such Consolidated
Net Income for such period: (a) provision for taxes based on income or profits,
(b) depletion and depreciation expense, (c) amortization expense, (d)
exploration costs, (e) reorganization costs and (f) 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 prepaid
cash expense that was paid in a prior period except such amounts as Tri-Union
determines in good faith are nonrecurring), and less, to the extent included in
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calculating such Consolidated Net Income and in excess of any costs or expenses
attributable thereto and deducted in calculating such Consolidated Net Income,
the sum of (x) the amount of deferred revenues that are amortized during such
period and are attributable to reserves that are subject to Volumetric
Production Payments and (y) 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 such 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 such
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 such
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 such 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 such term under the heading
"-- Defaults."
"Excess Cash Flow" means for any fiscal quarter, EBITDA for Tri-Union and
the Restricted Subsidiaries for such quarter, minus each of the following: (i)
interest expense of Tri-Union and the Restricted Subsidiaries determined in
accordance with GAAP and (ii) all Capital Expenditures made during such quarter
by Tri-Union and the Restricted Subsidiaries.
"Excess Proceeds" has the meaning given such term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Excess Proceeds Offer" has the meaning given such term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Excess Proceeds Payment" has the meaning given such term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Exchange Act" means the Securities Exchange Act of 1934, as amended.
"Exchange Notes" has the meaning given such term under the heading
"-- General."
"GAAP" means generally accepted accounting principles in the United States
as in effect from time to time, including those set forth in (i) the opinions
and pronouncements of the Accounting Principles Board of the American Institute
of Certified Public Accountants, (ii) statements and pronouncements of the
Financial Accounting Standards Board, (iii) such other statements by such other
entity as approved by a significant segment of the accounting profession, and
(iv) 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 such term in the section "-- Guarantees."
"Guaranteed Obligations" has the meaning given such term in the section
"-- Guarantees."
"Guarantor" means the Subsidiary Guarantors.
"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
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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 (b)(8)
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 such 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 (i) Hedged Revenues for such
period to (ii) Projected Consolidated Interest Expense for such 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 (A) 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 such Hedge Period hedged therein and the fixed price for such
month, plus (B) 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 such Hedge Period hedged therein and the fixed price floor for such
month, minus (C) both (i) the sum of each premium for any Oil and Gas Hedging
Contract for which a premium has been paid during such Hedge Period by Tri-Union
or any Restricted Subsidiary and (ii) 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 such 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.
"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 such Person's home (other than a
domestic servant).
"Incur" means issue, assume, guarantee, incur or otherwise become liable
for, provided, however, that any Indebtedness, Capital Stock or Lien of a Person
existing at the time such Person becomes a Subsidiary (whether by merger,
consolidation, acquisition or otherwise) shall be deemed to be Incurred by such
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), (i) the principal of and premium (if any)
in respect of (A) indebtedness of such Person for money borrowed and (B)
indebtedness evidenced by notes, debentures, bonds or other similar instruments
for the payment of which such Person is responsible or liable; (ii) all Capital
Lease Obligations of such Person and all Attributable Debt of such Person; (iii)
all obligations of such 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 such property), including all obligations of such
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); (iv) all
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obligations of such 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 (i) through (iii) above) entered into in the ordinary
course of business of such Person to the extent such letters of credit are not
drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no
later than the tenth Business Day following receipt by such Person of a demand
for reimbursement following payment on the letter of credit); (v) the amount of
all obligations of such Person with respect to the redemption, repayment or
other repurchase of any Disqualified Stock or, with respect to any Subsidiary of
such Person the liquidation preference with respect to, any Preferred Stock (but
excluding, in each case, any accrued dividends); (vi) all obligations of such
Person relating to any Production Payment or in respect of production imbalances
(but excluding production imbalances arising in the ordinary course of
business); (vii) all obligations of the type referred to in clauses (i) through
(vi) of other Persons and all dividends of other Persons for the payment of
which, in either case, such 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 such Person with respect to such
Production Payment but excluding other contractual obligations of such Person
with respect to such Production Payment); (viii) all obligations of the type
referred to in clauses (i) through (vii) of other Persons secured by any Lien on
any property or asset of such first-mentioned Person (whether or not such
obligation is assumed by such first-mentioned Person), the amount of such
obligation being deemed to be the lesser of the value of such property or assets
or the amount of the obligation so secured and (ix) to the extent not otherwise
included in this definition, Hedging Obligations of such Person.
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.
It is understood that none of the following shall constitute Indebtedness:
(i) 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 such 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 such business, assets or Subsidiary for the purpose of financing
such acquisition; (ii) any trade payables and other accrued current liabilities
incurred in the ordinary course of business (including as the deferred purchase
price of property), (iii) obligations arising from guarantees to suppliers,
lessors, licensees, contractors, franchisees or customers incurred in the
ordinary course of business; (iv) 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, (v) obligations in respect of performance bonds
provided by Tri-Union or its Subsidiaries in the ordinary course of business and
refinancings thereof; (vi) 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,
however, that such obligation is extinguished within two business days of its
incurrence; and (vii) 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: (i) Persons employed
by Tri-Union or any of the Restricted Subsidiaries or other Affiliates of the
foregoing during the current year or any
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of the three past years; (ii) 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; (iii) 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 (iv) 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.
"Initial Purchaser" means Jefferies & Company, Inc.
"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 the
terms thereof.
"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 such 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," (i) "Investment" shall include
the portion (proportionate to Tri-Union's equity interest in such Subsidiary) of
the fair market value of the net assets of any Subsidiary of Tri-Union at the
time that such Subsidiary is designated an Unrestricted Subsidiary; provided,
however, that upon a redesignation of such 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 (x) Tri-Union's "Investment" in such Subsidiary at the time of such
redesignation less (y) the portion (proportionate to Tri-Union's equity interest
in such Subsidiary) of the fair market value of the net assets of such
Subsidiary at the time of such redesignation; and (ii) any property transferred
to or from an Unrestricted Subsidiary shall be valued at its fair market value
at the time of such 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 such term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Major Asset Sale Offer" has the meaning given such term under the heading
"-- Certain Covenants -- Limitation on Sales of Assets."
"Make-Up Period" has the meaning ascribed such term in clause (iii) 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
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accordance with clause (a) (i) of the definition of Adjusted Consolidated Net
Tangible Assets; provided, however, that the following will be excluded from the
calculation of Material Change: (i) 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 such engineers exist
and (ii) any disposition of properties existing at the beginning of such 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 such properties or assets or received in any other noncash form) in each case
net of (i) 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 such Asset Disposition, (ii) 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 such
Asset Disposition, in accordance with the terms of any Lien upon or other
security agreement of any kind with respect to such assets, or which must by its
terms, or in order to obtain a necessary consent to such Asset Disposition, or
by applicable law, be repaid out of the proceeds from such Asset Disposition,
(iii) all distributions and other payments required to be made to minority
interest holders in Subsidiaries or joint ventures as a result of such Asset
Disposition and (iv) 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 such Asset Disposition and retained by
Tri-Union or any Restricted Subsidiary after such Asset Disposition.
"Net Cash Proceeds" means, with respect to any Equity Offering, the cash
proceeds of such 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 such issuance or
sale and net of taxes paid or payable as a result thereof.
"Net Working Capital" means (a) all current assets of Tri-Union and its
Restricted Subsidiaries minus (b) all current liabilities of Tri-Union and its
Restricted Subsidiaries, except current liabilities included in Indebtedness,
determined in accordance with GAAP.
"Non-Recourse Indebtedness" with respect to any Person means Indebtedness
of such Person for which (i) the sole legal recourse for collection of
principal, premium, if any, and interest on such Indebtedness is against the
specific property identified in the instruments evidencing or securing such
Indebtedness and such property was acquired with the proceeds of such
Indebtedness or such Indebtedness was incurred within 90 days after the
acquisition of such property and (ii) no other assets of such Person may be
realized upon in collection of principal or interest on such Indebtedness;
provided, however, that any such Indebtedness shall not cease to be
"Non-Recourse Indebtedness" solely as a result of the instrument governing such
Indebtedness containing terms pursuant to which such Indebtedness becomes
recourse upon (a) fraud or misrepresentation by the Person in connection with
such Indebtedness, (b) such Person failing to pay taxes or other charges
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that result in the creation of liens on any portion of the specific property
securing such Indebtedness or failing to maintain any insurance on such property
required under the instruments securing such Indebtedness, (c) the conversion of
any of the collateral for such Indebtedness, (d) such Person failing to maintain
any of the collateral for such Indebtedness in the condition required under the
instruments securing the Indebtedness, (e) any income generated by the specific
property securing such Indebtedness being applied in a manner not otherwise
allowed in the instruments securing such Indebtedness, (f) 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 (g) the rights of the holder of such Indebtedness
to the specific property becoming impaired, suspended or reduced by any act,
omission or misrepresentation of such Person; provided, further, however, that
upon the occurrence of any of the foregoing clauses (a) through (g) above, any
such Indebtedness which shall have ceased to be "Non-Recourse Indebtedness"
shall be deemed to have been Indebtedness incurred by such Person at such time.
"Notes" has the meaning given such 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.
"Original Notes" has the meaning given such term under the heading
"-- General."
"Oil and Gas Assets" means, in respect of any Person, all proved oil and
gas reserves and natural gas processing facilities of such Person.
"Oil and Gas Business" means the business of the exploration for, and
exploitation, development, acquisition, production, processing (but not
refining), marketing, storage and transportation of, hydrocarbons, and other
related energy and natural resource businesses.
"Oil and Gas Hedging Contract" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed to
provide protection against oil and gas price fluctuations.
"Payment Restrictions" has the meaning given such 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 (i) ownership interests in oil and gas properties, processing
facilities, gathering systems or ancillary real property interests and (ii)
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 (i) Richard Bowman, (ii) any Affiliates of
Richard Bowman or Tri-Union, (iii) 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 (iv) Jefferies &
Company, Inc. and its Affiliates.
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"Permitted Investment" means an Investment by Tri-Union or any Restricted
Subsidiary in (i) a Restricted Subsidiary or a Person that will, upon the making
of such Investment, become a Restricted Subsidiary; provided, however, that the
primary business of such Restricted Subsidiary is an Oil and Gas Business; (ii)
another Person if as a result of such Investment such 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, however, that such
Person's primary business is an Oil and Gas Business; (iii) Temporary Cash
Investments; (iv) 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, however, that
such trade terms may include such concessionary trade terms as Tri-Union or any
such Restricted Subsidiary deems reasonable under the circumstances; (v)
payroll, travel and similar advances to cover matters that are expected at the
time of such advances ultimately to be treated as expenses for accounting
purposes and that are made in the ordinary course of business; (vi) loans or
advances to employees made in the ordinary course of business; (vii) 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; (viii) any Person to the extent such 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 (ix) 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 such Person's constituent
documents, Incur or guarantee Indebtedness.
"Permitted Liens" means, with respect to any Person:
(a) pledges or deposits by such 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 such Person is a party, or
deposits to secure public, statutory or regulatory obligations of such
Person or deposits of cash or United States government bonds to secure
surety or appeal bonds to which such 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;
(b) 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;
(c) Liens for property taxes not yet subject to penalties for
non-payment or which are being contested in good faith and by appropriate
proceedings;
(d) 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 such 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 such Person;
(e) Liens securing Indebtedness Incurred under clause (b) (6) of the
covenant described under the heading "-- Certain Covenants -- Limitation on
Indebtedness"; provided, however, that the Lien may not extend to any other
property owned by such 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;
(f) Liens existing on the Closing Date;
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(g) Liens securing Indebtedness or other obligations of a Subsidiary
of such Person owing to such Person or a wholly owned Subsidiary of such
Person (or, in the case of Tri-Union, a Wholly Owned Subsidiary);
(h) Liens securing Hedging Obligations pursuant to any Interest Rate
Agreement so long as such 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 such Hedging
Obligations;
(i) 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;
(j) 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;
(k) Liens arising in the ordinary course of business in favor of the
United States, any state thereof, 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;
(l) Liens on pipeline or pipeline facilities which arise out of
operation of law;
(m) Liens reserved in oil and gas mineral leases for bonus or rental
payments and for compliance with the terms of such leases;
(n) 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;
(o) Liens arising out of judgments or awards against such Person with
respect to which such Person shall then be proceeding with an appeal or
other proceedings for review; and
(p) 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 such Person over shares
of Capital Stock of any other class of such 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
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then current Hedge Period, equal to the pro forma Consolidated Interest Expense
of Tri-Union and the Restricted Subsidiaries for such Hedge Period, calculated
based upon the following assumptions: (i) 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 such Hedge Period, except
that all scheduled amortization of such obligations will be paid when due; (ii)
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 such obligations); and (iii) 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 such
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 such Oil and Gas
Assets calculated before income 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, such Indebtedness (including an
Incurrence pursuant to clause (ii) of the second paragraph of 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 clause (ii) of the
first or second paragraph of the covenant described under the heading
"-- Certain Covenants -- Merger and Consolidation," provided, however, that (i)
such Refinancing Indebtedness has a Stated Maturity no earlier than the Stated
Maturity of the Indebtedness being Refinanced, (ii) such Refinancing
Indebtedness has an Average Life at the time such Refinancing Indebtedness is
Incurred that is equal to or greater than the Average Life of the Indebtedness
being Refinanced and (iii) such 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,
however, that Refinancing Indebtedness shall not include (x) Indebtedness of a
Subsidiary (other than a Subsidiary Guarantor) that Refinances Indebtedness of
Tri-Union or another Subsidiary or (y) Indebtedness of Tri-Union or a Restricted
Subsidiary that Refinances Indebtedness of an Unrestricted Subsidiary.
"Replacement Assets" has the meaning given such 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."
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"Restricted Payment" with respect to any Person means (i) 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 such Person) or similar payment to the direct or
indirect holders of its Capital Stock (other than (x) 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 (z) 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)), (ii) 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), (iii) 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 (iv) 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 such security as the fixed date on which the final payment of principal of
such security is due and payable, including pursuant to any mandatory redemption
provision (but excluding any provision providing for the repurchase of such
security at the option of the holder thereof upon the happening of any
contingency unless such 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 that
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 (i) such Person,
(ii) such Person and one or more Subsidiaries of such Person or (iii) one or
more Subsidiaries of such 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 such 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
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taxes, if the lessee in respect thereof is obligated to either purchase for an
amount in excess of, or pay upon early termination an amount in excess of, 80%
of the residual value of the property subject to such operating lease upon
expiration or early termination of such 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 (a) of the covenant described under the heading
"-- Certain Covenants -- Limitation on Indebtedness."
"Temporary Cash Investments" means any of the following: (i) any investment
in direct obligations of the United States or any agency thereof or obligations
guaranteed by the United States or any agency thereof having maturities not more
than 180 days from the date of acquisition, (ii) 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 thereof 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, (iii) repurchase obligations with a term of not more than 30 days
for underlying securities of the types described in clause (i) above entered
into with a bank meeting the qualifications described in clause (ii) above, (iv)
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 (v) 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 thereof, 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, however, 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.
"United States Government Obligations" means direct obligations (or
certificates representing an ownership interest in such obligations) of the
United States (including any agency or instrumentality thereof) 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.
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"Unrestricted Subsidiary" means (i) 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 (ii) 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 such 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, however, that immediately after giving effect to such
designation (x) Tri-Union could Incur $1.00 of additional Indebtedness under
paragraph (a) of the covenant described under the heading "-- Certain
Covenants -- Limitation on Indebtedness" and (y) 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 such action. For the avoidance of doubt, on the
date any Restricted Subsidiary is redesignated to be an Unrestricted Subsidiary,
such 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 such designation and
an officers' certificate certifying that such 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 such
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 such 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
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
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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 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
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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 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
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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.
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
The following is a general discussion of certain U.S. federal income tax
considerations relevant 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.
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.
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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 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
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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.
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
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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.
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. There was no disagreement
between us and Hidalgo 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 report.
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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 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.
INCORPORATION BY REFERENCE
We undertake to provide without charge to each person, including any
beneficial owner, to whom a copy of this prospectus has been delivered, upon the
written or oral request of such person, a copy of any or all of the information
that has been incorporated by reference in this prospectus (not including
exhibits to the information that is incorporated by reference unless such
exhibits are specifically incorporated by reference in such information).
Requests for such copies should be directed to the Secretary of Tri-Union at 530
Lovett Boulevard, Houston, Texas 77006; (713) 533-4000.
125
129
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.
126
130
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.
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.
127
131
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.
128
132
INDEX TO FINANCIAL STATEMENTS
<Table>
<Caption>
PAGE
----
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 and March 31, 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 Three Months Ended
March 31, 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 Three Months Ended March
31, 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
Three Months Ended March 31, 2000 and 2001
(unaudited)............................................ F-7
Notes to Consolidated Financial Statements................ F-8
</Table>
F-1
133
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Stockholder and Board of Directors
Tribo Petroleum Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheet of 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 Tribo
Petroleum Corporation and subsidiaries at December 31, 2000, and the results of
their operations and their cash flow 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
Note 13 which is as of
July 30, 2001
F-2
134
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
Director and Stockholder
Tribo Petroleum Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheet of 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 Tribo
Petroleum 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
Note 13 which is as of July 30, 2001
F-3
135
TRIBO PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
AT DECEMBER 31,
--------------------------- AT MARCH 31,
1999 2000 2001
------------ ------------ ------------
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents.............................. $ 2,813,996 $ 32,989,939 $ 52,715,362
Accounts receivable net of allowance for doubtful
accounts of $867,864, $351,505 and $336,668......... 9,497,602 24,906,608 30,054,332
Marketable securities.................................. 235,000 472,248 264,270
Prepaid and other...................................... 926,286 1,777,763 1,636,510
------------ ------------ ------------
Total current assets........................... 13,472,884 60,146,558 84,670,474
------------ ------------ ------------
Oil and natural gas properties -- full cost method,
net.................................................... 89,640,441 87,132,723 84,822,035
Other assets
Restricted cash and bonds.............................. 4,181,507 4,674,645 4,747,405
Furniture, fixtures and equipment, net................. 256,515 175,521 426,564
Receivables from affiliates, net....................... 852,975 364,667 350,467
Deferred loan costs.................................... 498,499 99,700 --
------------ ------------ ------------
Total other assets............................. 5,789,496 5,314,533 5,524,436
------------ ------------ ------------
$108,902,821 $152,593,814 $175,016,945
============ ============ ============
LIABILITIES AND CAPITAL DEFICIT
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued liabilities............ $ 23,411,646 $ 26,609,284 $ 33,284,553
Accrued interest.................................... 4,784,286 7,224,477 8,361,310
Notes payable....................................... 358,427 333,880 164,194
Notes payable -- in default......................... 104,700,000 -- --
------------ ------------ ------------
133,254,359 34,167,641 41,810,057
------------ ------------ ------------
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 (Notes 1, 3, 8, 9, 12 and
13)
Capital deficit:
Class A common stock, $0.01 par value, 445,000 shares
authorized; 238,333 shares issued and outstanding... 2,383 2,383 2,383
Class B common stock, $0.01 par value, 65,000 shares
authorized; none issued or outstanding.............. -- -- --
Deficit................................................ (24,355,724) (30,141,750) (15,361,035)
Accumulated other comprehensive income................. 1,803 -- --
------------ ------------ ------------
Total capital deficit.......................... (24,351,538) (30,139,367) (15,358,652)
------------ ------------ ------------
$108,902,821 $152,593,814 $175,016,945
============ ============ ============
</Table>
See accompanying notes to consolidated financial statements.
F-4
136
TRIBO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
<Table>
<Caption>
THREE MONTHS ENDED
YEARS ENDED DECEMBER 31, MARCH 31,
---------------------------------------- -------------------------
1998 1999 2000 2000 2001
------------ ----------- ----------- ----------- -----------
(UNAUDITED)
Revenues and other:
Oil and natural gas
revenues.................... $ 25,836,896 $36,270,343 $73,452,054 $12,494,777 $32,407,222
Gain (loss) on marketable
securities.................. (27,414) -- 995,180 441,632 (326,363)
Other......................... 542,644 1,495,393 28,404 76,617 57,767
------------ ----------- ----------- ----------- -----------
Total revenues and
other................ 26,352,126 37,765,736 74,475,638 13,013,026 32,138,626
------------ ----------- ----------- ----------- -----------
Expenses:
Lease operating expenses...... 17,450,088 15,542,277 19,485,359 3,889,767 5,452,439
Workover expense.............. 599,690 2,410,410 6,649,074 1,134,396 1,620,834
Production taxes.............. 638,955 704,855 1,968,342 308,355 768,897
Depreciation, depletion and
amortization................ 12,397,800 11,040,035 13,506,477 2,767,199 3,738,112
General and administrative.... 3,326,747 5,236,733 4,328,358 1,186,237 1,642,246
Interest expense (contractual
interest during 2000 of
$13,100,000)................ 7,733,931 11,981,460 12,757,863 3,327,021 3,111,975
------------ ----------- ----------- ----------- -----------
Total expenses......... 42,147,211 46,915,770 58,695,473 12,612,975 16,334,503
------------ ----------- ----------- ----------- -----------
Income (loss) before
reorganization costs and
income taxes.................. (15,795,085) (9,150,034) 15,780,165 400,051 15,804,123
Reorganization costs............ -- -- 21,487,191 401,908 723,408
------------ ----------- ----------- ----------- -----------
Income (loss) before income
taxes......................... (15,795,085) (9,150,034) (5,707,026) (1,857) 15,080,715
Provisions for income taxes..... -- -- 79,000 -- 300,000
------------ ----------- ----------- ----------- -----------
Net income (loss)............... (15,795,085) (9,150,034) (5,786,026) (1,857) 14,780,715
Other comprehensive income:
Unrealized gains on
available-for-sale
securities.................. 97 1,803 (1,803) (1,803) --
------------ ----------- ----------- ----------- -----------
Comprehensive income (loss)..... $(15,794,988) $(9,148,231) $(5,787,829) $ (3,660) $14,780,715
============ =========== =========== =========== ===========
Net income (loss) per share --
basic and diluted............. $ (66.27) $ (38.39) $ (24.28) $ (0.01) $ 62.02
============ =========== =========== =========== ===========
Weighted average shares
outstanding................... 238,333 238,333 238,333 238,333 238,333
============ =========== =========== =========== ===========
</Table>
See accompanying notes to consolidated financial statements.
F-5
137
TRIBO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
<Table>
<Caption>
ACCUMULATED
RETAINED OTHER
COMMON EARNINGS COMPREHENSIVE
STOCK (DEFICIT) INCOME (LOSS) TOTAL
------ ------------ ------------- ------------
FOR THE YEARS ENDED DECEMBER 31, 1998,
1999 AND 2000:
Balance, January 1, 1998.............. $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............ 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............ 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............ $2,383 $(30,141,750) $ -- $(30,139,367)
====== ============ ======= ============
FOR THE THREE MONTHS ENDED MARCH 31,
2000 AND 2001 (UNAUDITED):
Balance, January 1, 2000.............. $2,383 $(24,355,724) $ 1,803 $(24,351,538)
Net loss (unaudited)................ -- (1,857) -- (1,857)
Change in unrealized gains on
available-for-sale securities.... -- -- (1,803) (1,803)
------ ------------ ------- ------------
Balance, March 31, 2000 (unaudited)... $2,383 $(24,357,581) $ -- $(24,355,198)
====== ============ ======= ============
Balance, January 1, 2001.............. $2,383 $(30,141,750) $ -- $(30,139,367)
Net income (unaudited).............. -- 14,780,715 -- 14,780,715
------ ------------ ------- ------------
Balance, March 31, 2001 (unaudited)... $2,383 $(15,361,035) $ -- $(15,358,652)
====== ============ ======= ============
</Table>
See accompanying notes to consolidated financial statements.
F-6
138
TRIBO PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<Table>
<Caption>
THREE MONTHS ENDED
YEARS ENDED DECEMBER 31, MARCH 31,
------------------------------------------ --------------------------
1998 1999 2000 2000 2001
------------ ------------ ------------ ------------ -----------
(UNAUDITED)
Cash flows from operating activities:
Net income (loss).................................. $(15,795,085) $ (9,150,034) $ (5,786,026) $ (1,857) $14,780,715
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depletion, depreciation and amortization......... 12,397,800 11,040,035 13,506,477 2,767,199 3,738,112
Loss (gain) on sale of marketable securities..... 27,414 -- (995,179) (441,632) 326,363
Accretion of bond interest....................... (24,400) (219,478) (138,040) (34,154) (22,859)
Loss on sale of equipment........................ 5,373 -- -- -- --
Reorganization costs............................. -- -- 21,487,191 401,908 723,408
Changes in assets and liabilities:
Accounts receivable............................ (584,097) (3,425,275) (15,409,006) 1,278,898 (5,147,724)
Prepaid expenses............................... (499,256) (239,304) (851,477) (718,227) 141,254
Receivable from affiliates..................... (157,664) (412,592) 488,308 242,827 14,200
Accounts payable and accrued liabilities....... 11,798,139 14,533,644 12,346,569 2,765,082 7,049,010
Pre-petition liabilities subject to
compromise................................... -- -- 18,043,910 (1,424,676) --
------------ ------------ ------------ ------------ -----------
Net cash provided by operating activities
before reorganization items................ 7,168,224 12,126,996 42,692,727 4,835,368 21,602,479
------------ ------------ ------------ ------------ -----------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid.......... -- -- (2,536,788) (400,860) (479,716)
Interest earned during bankruptcy.................. -- -- 538,841 12,032 519,400
------------ ------------ ------------ ------------ -----------
Net cash provided by (used for) reorganization
items............................................ -- -- (1,997,947) (388,828) 39,684
------------ ------------ ------------ ------------ -----------
Net cash provided by operating activities.... 7,168,224 12,126,996 40,694,780 4,446,540 21,642,163
------------ ------------ ------------ ------------ -----------
Cash flows from investing activities
Purchase of marketable securities.................. -- (232,268) (1,118,069) (248,854) (335,755)
Proceeds from sale of marketable securities........ 319,217 -- 1,874,245 2,205 217,469
Additions to oil and natural gas properties........ (71,992,146) (13,572,444) (10,877,657) (1,216,933) (1,381,446)
Purchase of furniture, fixtures and equipment...... (326,718) (40,185) (31,280) (6,695) (197,322)
Proceeds from disposal of equipment................ 73,905 4,059 -- -- --
Proceeds from sales of oil and natural gas
properties....................................... -- 2,262,300 389,971 -- --
Purchase of restricted cash and bonds.............. -- (3,664,957) (355,000) (75,000) (50,000)
Proceeds from restricted marketable securities..... -- 3,300,000 -- -- --
------------ ------------ ------------ ------------ -----------
Net cash used in investing activities........ (71,925,742) (11,943,495) (10,117,790) (1,545,277) (1,747,054)
------------ ------------ ------------ ------------ -----------
Cash flows from financing activities:
Proceeds from long-term debt....................... 66,460,000 -- -- -- --
Payments of long-term debt......................... -- (300,000) (376,500) -- --
Payments of loan fees.............................. (1,142,550) (20,927) -- -- --
Increase (decrease) in notes payable............... (164,249) 278,613 (24,547) (217,942) (169,686)
------------ ------------ ------------ ------------ -----------
Net cash provided by (used in) financing
activities................................. 65,153,201 (42,314) (401,047) (217,942) (169,686)
------------ ------------ ------------ ------------ -----------
Net increase in cash and cash equivalents............ 395,683 141,187 30,175,943 2,683,321 19,725,423
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 $ 5,497,317 $52,715,362
============ ============ ============ ============ ===========
Supplemental disclosures of cash flow information
Interest paid during the period.................... $ 4,684,493 $ 7,100,562 $ 4,039,520 $ 1,255,580 $ 1,950,000
Net 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 --
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
139
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- BASIS OF PRESENTATION
Basis of Presentation
Tribo Petroleum Corporation ("Tribo") was incorporated in the state of
Texas in September, 1992. Tribo 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 Tribo and its
wholly-owned subsidiary Tri-Union Development Corporation ("TDC") and TDC's
wholly-owned subsidiary Tri-Union Operating Company ("TOC"). All significant
intercompany accounts and transactions have been eliminated in consolidation.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Interim Presentation
The accompanying unaudited consolidated interim financial statements and
disclosures for the three months ended March 31, 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 three
months ended March 31, 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 three months ended March
31, 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 Mineral and
Management Service for the plugging and abandonment of certain wells and the
decommissioning of offshore platforms. At 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
F-8
140
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 costs of unproved
properties are excluded from amortization until the properties are evaluated,
subject to an annual assessment of whether impairment has occurred. 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.
F-9
141
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 consists of
accounts receivable. The receivables are primarily from companies in the oil and
natural gas industry or from individual oil and natural gas investors. During
1998, 1999 and 2000, the Company had three customers that represented 58%, 64%
and 48% of total revenues, respectively. 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.
Hedging Transactions
The Company periodically enters into contracts to hedge the risk of future
crude oil and natural gas price fluctuations. Such contracts may either fix or
support crude oil and natural gas prices or limit the impact of price
fluctuations with respect to the Company's sales of crude oil and natural gas.
Gains and losses on such hedging activities are recognized in oil and gas
production revenues when hedged production is sold.
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.
F-10
142
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 SEC ("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. 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 operation.
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 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 Company's financial
statements; however, it may have a significant impact on the Company in the
future depending on the nature of its anticipated hedging program.
NOTE 3 -- BANKRUPTCY
In March 1998, the Company acquired certain oil and natural gas properties
with the proceeds from a short-term bank loan (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.
F-11
143
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During February 2000, due to the Company's violations of 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.
Reorganization Costs -- As a result of TDC filing for protection under
Chapter 11 of the U.S. Bankruptcy Code, the Company has incurred certain
reorganization costs totaling $21,487,191 which include the following:
Amended Rejection of hedging contract -- The bankruptcy court approved
a motion to reject a hedging contract. A claim has been filed by the
damaged party resulting in a liability of $17,559,272 (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.
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 $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 have been 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 hedging contract.......................... $17,059,272 $ --
Professional fees and other............................... 860,000 1,059,753
Retention................................................. -- 855,000
</Table>
The plan of reorganization also requires the Company to pay additional bank
charges and interest of $7.7 million, and additional professional fees of $4.0
million. The additional professional fees will be reduced by $3.3 million upon
completion of the proposed offering. These costs have not been accrued by the
Company due to their contingent nature.
F-12
144
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
At December 31, 1999, the Company held available-for-sale securities, as
follows:
<Table>
<Caption>
UNREALIZED
------------------
COST GAINS LOSSES FAIR VALUE
-------- ------- -------- ----------
Common stock............................. $140,721 $31,779 $ -- $172,500
Common stock warrants.................... 91,547 -- (29,047) 62,500
-------- ------- -------- --------
$232,268 $31,779 $(29,047) $235,000
======== ======= ======== ========
</Table>
At December 31, 2000, the Company held trading securities, as follows:
<Table>
<Caption>
UNREALIZED
-------------------
COST GAINS LOSSES FAIR VALUE
-------- -------- -------- ----------
Common stock............................ $308,850 $230,429 $(67,031) $472,248
======== ======== ======== ========
</Table>
During the year ended December 31, 2000, the Company had proceeds, realized
gains and losses on trading securities as follows:
<Table>
<Caption>
AMOUNT
----------
Proceeds................................................ $1,874,245
Gains................................................... 1,062,211
Losses.................................................. (67,031)
</Table>
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.......................................... 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>
F-13
145
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net amounts receivable from affiliates are recorded in the accompanying
consolidated balance sheets as Receivables from Affiliates, net and Accounts
Receivable. 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 principally relates to
cash, travel 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>
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>
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 is 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).
During the year ended December 31, 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).
F-14
146
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 9 -- HEDGING TRANSACTIONS
During 1999, the Company entered into a two year contract with Aquila
Energy Marketing Corporation ("Aquila") that obligated the Company to deliver
specified volumes of natural gas to Aquila at a certain price. The Company
entered into this contract to manage the price risk relating to a portion of its
future natural gas production.
With the authorization of the bankruptcy court, the Company rejected this
hedging contract effective December 20, 2000. Aquila filed a claim against the
Company for damages relating to the cancellation of the contract for
$17,059,272. 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.
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 assets acquired based on estimated fair values at the date of
acquisition. 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.
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................................ $ (14,952)
============
</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>
F-15
147
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
F-16
148
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
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.
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.
NOTE 13 -- SUBSEQUENT EVENTS
(a) During March, 2001, the Company entered into a lease agreement with a
related party 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.
F-17
149
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(b) On June 5, 2001, the Company sold certain oil and natural gas property
for $2.2 million.
(c) On May 25, 2001, the Company agreed to transfer certain oil and natural
gas properties with a net book value at December 31, 2000 of approximately
$1,138,000 to its affiliate, Atasca Resources, Inc. In connection with this
transaction, all balances owing to and from the Company by its affiliates on May
25, 2001 were forgiven. As a consequence of these transactions, the Company will
record a one-time reorganization expense of approximately $2,151,000 in the
second quarter of 2001.
(d) 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.
(e) 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 will pay all pre-petition liabilities in
full. In addition, the Company will pay 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 an executory contract.
(f) On June 13, 2001, the Company issued a Prospectus for 130,000 Units,
consisting 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.
The units will consist of $1,000 principal amount of Notes and one share of
class A common stock.
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
will be 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 will be amortized as additional
interest expense over the term of the Notes.
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 will be considered as bond discount and
amortized as additional interest expense over the term of the Notes.
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 will be considered as unit offering costs. The portion
of the offering costs associated with the issuance of
F-18
150
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Notes will be 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 Tribo, subject to certain limitations.
In addition, the Company incurred other offering costs of $9,625,000. The
portion of the offering costs associated with the issuance of the Notes will be
amortized as additional interest expense over the term of the Notes.
(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. The contract will require
the Company to sell the oil and gas production at swap prices of $25.30 per Bbl
and $4.19 per mcf, respectively.
(h) On July 27, 2001, Tribo merged with one of its wholly-owned
subsidiaries, TDC. As a result of the merger, the surviving corporation was TDC,
which assumed all of the rights and obligations of Tribo.
NOTE 14 -- 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>
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>
F-19
151
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In the presentation above, no deduction has been made for indirect costs
such as corporate overhead or interest expense. No income taxes are reflected
above due to the Company's tax loss carryforwards.
Oil and Natural Gas Reserves (Unaudited)
The following table sets forth the Company's net proved oil and natural gas
reserves at December 31, 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 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........................ (36) (24,800)
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-20
152
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 (81,277)
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.
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
F-21
153
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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-22
154
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 15 -- 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.... 9,057,715 214,350 435,806 (210,269) 9,497,602
Marketable securities....... -- -- 235,000 -- 235,000
Prepaid and other........... 925,213 -- 1,073 -- 926,286
------------ ---------- ------------ ----------- ------------
Total current
assets............. 11,970,442 616,503 1,096,208 (210,269) 13,472,884
------------ ---------- ------------ ----------- ------------
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
Receivable from affiliates,
net....................... 1,412,397 1,137,788 (1,697,210) -- 852,975
Deferred loan costs......... 498,499 -- -- -- 498,499
Investment in subsidiary.... 1,795,372 -- (25,373,174) 23,577,802 --
------------ ---------- ------------ ----------- ------------
Total other assets... 8,086,289 1,178,919 (27,053,514) 23,577,802 5,789,496
------------ ---------- ------------ ----------- ------------
$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
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-23
155
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............... 24,305,581 451,033 618,809 (468,815) 24,906,608
Marketable securities.................. -- -- 472,248 -- 472,248
Prepaid and other...................... 973,632 365,965 438,166 -- 1,777,763
------------ ---------- ------------ ----------- ------------
Total current assets............ 57,705,370 704,308 2,205,695 (468,815) 60,146,558
------------ ---------- ------------ ----------- ------------
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
Receivable from affiliates, net........ (502,740) 1,965,510 (1,098,103) -- 364,667
Deferred loan costs.................... 99,700 -- -- -- 99,700
Investment in subsidiary............... 3,030,900 -- (32,113,482) 29,082,582 --
------------ ---------- ------------ ----------- ------------
Total other assets.............. 7,424,797 1,996,242 (33,189,088) 29,082,582 5,314,533
------------ ---------- ------------ ----------- ------------
$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-24
156
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING BALANCE SHEET
MARCH 31, 2001
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
------------ ---------- ------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents.............. $ 52,349,388 $ 336,307 $ 29,667 $ -- $ 52,715,362
Accounts receivable, net............... 28,009,713 1,210,659 833,960 -- 30,054,332
Marketable securities.................. -- -- 264,270 -- 264,270
Prepaid and other...................... 908,637 136,386 591,487 -- 1,636,510
------------ ---------- ------------ ----------- ------------
Total current assets............ 81,267,738 1,683,352 1,719,384 -- 84,670,474
------------ ---------- ------------ ----------- ------------
Oil and natural gas properties, net...... 83,406,295 277,771 1,137,969 -- 84,822,035
Other assets
Restricted cash and bonds.............. 4,747,405 -- -- -- 4,747,405
Furniture, fixtures and equipment,
net.................................. 222,164 130,472 73,928 -- 426,564
Receivable from affiliates, net........ (561,141) 2,015,511 (1,103,903) -- 350,467
Investment in subsidiary............... 4,008,693 -- (17,056,742) 13,048,049 --
------------ ---------- ------------ ----------- ------------
Total other assets.............. 8,417,121 2,145,983 (18,086,717) 13,048,049 5,524,436
------------ ---------- ------------ ----------- ------------
$173,091,154 $4,107,106 $(15,229,364) $13,048,049 $175,016,945
============ ========== ============ =========== ============
LIABILITIES AND STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued
liabilities........................ $ 33,056,852 $ 98,413 $ 129,288 $ -- $ 33,284,553
Accrued interest..................... 8,361,310 -- -- -- 8,361,310
Notes payable........................ 164,194 -- -- -- 164,194
------------ ---------- ------------ ----------- ------------
41,582,356 98,413 129,288 -- 41,810,057
------------ ---------- ------------ ----------- ------------
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)............ (17,057,742) 4,007,693 (15,361,035) 13,050,049 (15,361,035)
------------ ---------- ------------ ----------- ------------
Total stockholder's equity
(capital deficit)............. (17,056,742) 4,008,693 (15,358,652) 13,048,049 (15,358,652)
------------ ---------- ------------ ----------- ------------
$173,091,154 $4,107,106 $(15,229,364) $13,048,049 $175,016,945
============ ========== ============ =========== ============
</Table>
F-25
157
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-26
158
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-27
159
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.......... -- -- 995,179 -- 995,179
Other.................. 118,969 (33,429) 6,623 (63,758) 28,405
----------- ---------- ----------- ----------- -----------
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-28
160
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2000
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- --------- --------- ------------ ------------
Revenues and other:
Oil and natural gas
revenues................. $11,800,299 $161,553 $ 532,925 $ -- $12,494,777
Gain on marketable
securities............... -- -- 441,632 -- 441,632
Other....................... 76,215 31,197 401 (31,196) 76,617
----------- -------- --------- --------- -----------
Total revenues and
other............. 11,876,514 192,750 974,958 (31,196) 13,013,026
----------- -------- --------- --------- -----------
Expenses:
Lease operating expense..... 4,179,263 61,079 116,315 (468,890) 3,889,767
Workover expense............ 1,108,972 4,799 20,625 -- 1,134,396
Production taxes............ 281,846 -- 26,509 -- 308,355
Depreciation, depletion and
amortization............. 2,763,476 2,598 1,125 2,767,199
General and
administrative........... 670,086 2,842 77,615 435,694 1,186,237
Interest expense............ 3,323,269 -- 3,752 3,327,021
----------- -------- --------- --------- -----------
Total expenses...... 12,326,912 71,318 245,941 (31,196) 12,612,975
----------- -------- --------- --------- -----------
Income (loss) before
reorganization costs........ (450,398) 121,432 729,017 -- 400,051
Reorganization costs.......... 401,908 -- -- -- 401,908
----------- -------- --------- --------- -----------
Income (loss) from operations
before equity in net income
(loss) of subsidiaries...... (852,306) 121,432 729,107 -- (1,857)
Equity in net income (loss) of
subsidiaries................ 121,432 -- (730,874) 609,442 --
----------- -------- --------- --------- -----------
Net income (loss)............. $ (730,874) $121,432 $ (1,857) $ 609,442 $ (1,857)
=========== ======== ========= ========= ===========
</Table>
F-29
161
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2001
(UNAUDITED)
<Table>
<Caption>
TRI-UNION TRI-UNION TRIBO
DEVELOPMENT OPERATING PETROLEUM ELIMINATIONS CONSOLIDATED
----------- ---------- ----------- ------------ ------------
Revenues and other:
Oil and natural gas
revenues........... $30,644,216 $1,338,442 $ 424,564 $ -- $32,407,222
Loss on marketable
securities......... -- -- (326,363) -- (326,363)
Other................. 51,931 32,673 4,347 (31,184) 57,767
----------- ---------- ----------- ------------ -----------
Total revenues
and other... 30,696,147 1,371,115 102,548 (31,184) 32,138,626
----------- ---------- ----------- ------------ -----------
Expenses:
Lease operating
expense............ 5,595,266 48,749 111,846 (301,422) 5,452,439
Workover expense...... 1,592,241 17,581 11,012 -- 1,620,834
Production taxes...... 751,712 -- 17,185 -- 768,897
Depreciation,
depletion and
amortization....... 3,584,265 123,756 30,091 -- 3,738,112
General and
administrative..... 969,867 205,236 196,905 270,238 1,642,246
Interest expense...... 3,100,441 -- 11,534 -- 3,111,975
----------- ---------- ----------- ------------ -----------
Total
expenses.... 15,593,792 393,322 378,573 (31,184) 16,334,503
----------- ---------- ----------- ------------ -----------
Income before
reorganization costs
and income taxes...... 15,102,355 977,793 (276,025) -- 15,804,123
Reorganization costs.... 723,408 -- -- -- 723,408
----------- ---------- ----------- ------------ -----------
Income (loss) before
income taxes.......... 14,378,947 977,793 (276,025) -- 15,080,715
Provision for income
taxes................. 300,000 -- -- -- 300,000
----------- ---------- ----------- ------------ -----------
Income (loss) from
operations before
equity in net income
of subsidiaries....... 14,078,947 977,793 (276,025) -- 14,780,715
Equity in net income of
subsidiaries.......... 977,793 -- 15,056,740 (16,034,533) --
----------- ---------- ----------- ------------ -----------
Net income.............. $15,056,740 $ 977,793 $14,780,715 $(16,034,533) $14,780,715
=========== ========== =========== ============ ===========
</Table>
F-30
162
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 flow 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)
Receivable 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
Pre-petition liabilities
subject to
compromise............. -- -- -- -- --
------------ --------- ------------ ------------ ------------
Net cash provided by
operating
activities........... 6,049,322 203,365 915,537 -- 7,168,224
------------ --------- ------------ ------------ ------------
Cash flow 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-31
163
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 flow 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 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.................... (3,443,338) (29,373) 16,758 30,678 (3,425,275)
Prepaid expenses....................... (298,986) -- 59,682 -- (239,304)
Receivable from affiliates............. 333,891 (204,918) (541,565) -- (412,592)
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 flow 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-32
164
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 flow 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 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.......................... (15,247,866) (236,683) (183,003) 258,546 (15,409,006)
Prepaid expenses............................. (48,419) (365,965) (437,093) -- (851,477)
Receivable from affiliates................... 1,915,137 (827,722) (599,107) -- 488,308
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 flow 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-33
165
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 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 (loss)............................. $ (730,874) $ 121,432 $ (1,857) $ 609,442 $ (1,857)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Equity in undistributed (income) loss of
subsidiaries.............................. (121,432) -- 730,874 (609,442) --
Depletion, depreciation and amortization.... 2,763,476 2,598 1,125 -- 2,767,199
Gain on sale of marketable securities....... -- -- (441,632) -- (441,632)
Accretion of bond interest.................. (34,154) -- -- -- (34,154)
Reorganization items........................ 401,908 -- -- -- 401,908
Changes in assets and liabilities:
Accounts receivable....................... 1,633,478 63,464 (207,775) (210,269) 1,278,898
Prepaid expenses.......................... (718,227) -- -- -- (718,227)
Receivable from affiliates................ 384,877 (225,047) 82,997 -- 242,827
Accounts payable and accrued
liabilities............................ 2,411,146 60,492 83,173 210,269 2,765,082
Pre-petition liabilities subject to
compromise............................. (1,424,676) -- -- -- (1,424,676)
----------- --------- --------- --------- ----------
Net cash provided by operating
activities before reorganization
items................................ 4,565,522 22,939 246,907 -- 4,835,368
----------- --------- --------- --------- ----------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid..... (400,860) -- -- -- (400,860)
Interest earned during bankruptcy............. 12,032 -- -- -- 12,032
----------- --------- --------- --------- ----------
Net cash provided by reorganization
items................................ (388,828) -- -- -- (388,828)
----------- --------- --------- --------- ----------
Net cash provided by operating
activities........................... 4,176,694 22,939 246,907 -- 4,446,540
----------- --------- --------- --------- ----------
Cash flow from investing activities:
Purchase of marketable securities............. -- -- (248,854) -- (248,854)
Proceeds from sales of marketable
securities.................................. -- -- 2,205 -- 2,205
Additions to oil and natural gas properties... (1,166,147) -- (50,786) -- (1,216,933)
Purchase of furniture, fixtures and
equipment................................... (402) -- (6,293) -- (6,695)
Purchase of restricted cash and bonds......... (75,000) -- -- -- (75,000)
----------- --------- --------- --------- ----------
Net cash used in investing
activities........................... (1,241,549) -- (303,728) -- (1,545,277)
----------- --------- --------- --------- ----------
Cash flows from financing activities:
Decrease in notes payable..................... (141,782) -- (76,160) -- (217,942)
----------- --------- --------- --------- ----------
Net cash used in financing
activities........................... (141,782) -- (76,160) -- (217,942)
----------- --------- --------- --------- ----------
Net increase (decrease) in cash and cash
equivalents................................... 2,793,363 22,939 (132,981) -- 2,683,321
Cash and cash equivalents -- beginning of
period........................................ 1,987,514 402,153 424,329 -- 2,813,996
----------- --------- --------- --------- ----------
Cash and cash equivalents -- end of period...... $4,780,877 $ 425,092 $ 291,348 $ -- $5,497,317
=========== ========= ========= ========= ==========
</Table>
F-34
166
TRIBO PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 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....................... $15,056,740 $ 977,793 $14,780,715 $(16,034,533) $14,780,715
Adjustments to reconcile net
income to net cash provided by
(used in) operating activities:
Equity in undistributed income
of subsidiary................ (977,793) -- (15,056,740) 16,034,533 --
Depletion, depreciation and
amortization................. 3,584,265 123,756 30,091 -- 3,738,112
Loss on sale of marketable
securities................... -- -- 326,363 -- 326,363
Accretion of bond interest..... (22,859) -- -- -- (22,859)
Reorganization items........... 723,408 -- -- -- 723,408
Changes in assets and
liabilities:
Accounts receivable.......... (3,704,132) (759,626) (215,151) (468,815) (5,147,724)
Prepaid expenses............. 64,996 229,579 (153,321) -- 141,254
Receivable from affiliates... 58,401 (50,001) 5,800 -- 14,200
Accounts payable and accrued
liabilities............... 6,640,552 42,147 (102,504) 468,815 7,049,010
----------- --------- ----------- ------------ -----------
Net cash provided by (used
in) operating activities
before reorganization
items................... 21,423,578 563,648 (384,747) -- 21,602,479
Operating cash flows from
reorganization items:
Bankruptcy related professional
fees paid...................... (479,716) -- -- -- (479,716)
Interest earned during
bankruptcy..................... 519,400 -- -- -- 519,400
----------- --------- ----------- ------------ -----------
Net cash provided by
reorganization items.... 39,684 -- -- -- 39,684
Net cash provided by (used
in) operating
activities.............. 21,463,262 563,648 (384,747) -- 21,642,163
Cash flow from investing
activities:
Purchase of marketable
securities..................... -- -- (335,755) -- (335,755)
Proceeds from sales of marketable
securities..................... -- -- 217,469 -- 217,469
Additions to oil and natural gas
properties..................... (1,280,367) (11,203) (89,876) -- (1,381,446)
Purchase of furniture, fixtures
and equipment.................. (39,978) (103,448) (53,896) -- (197,322)
Purchase of restricted cash and
bonds.......................... (50,000) -- -- -- (50,000)
----------- --------- ----------- ------------ -----------
Net cash used in investing
activities.............. (1,370,345) (114,651) (262,058) -- (1,747,054)
Cash flows from financing
activities:
Decrease in notes payable........ (169,686) -- -- -- (169,686)
----------- --------- ----------- ------------ -----------
Net cash used in financing
activities.............. (169,686) -- -- -- (169,686)
Net increase (decrease) in cash and
cash equivalents................. 19,923,231 448,997 (646,805) -- 19,725,423
Cash and cash equivalents --
beginning of period.............. 32,426,157 (112,690) 676,472 -- 32,989,939
----------- --------- ----------- ------------ -----------
Cash and cash equivalents -- end of
period........................... $52,349,388 $ 336,307 $ 29,667 $ -- $52,715,362
=========== ========= =========== ============ ===========
</Table>
F-35
167
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......................... 14
Forward-Looking Statements........... 23
The Company.......................... 25
The Exchange Offer................... 26
Use of Proceeds...................... 34
Capitalization....................... 35
Selected Historical Consolidated
Financial Data..................... 36
Unaudited Condensed Pro Forma
Financial Data..................... 38
Operating Data....................... 42
Reserve Data......................... 42
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 43
Business and Properties.............. 52
Management........................... 69
Principal Stockholders............... 71
Certain Relationships and Related
Transactions....................... 71
Description of the Senior
Secured Notes...................... 73
Plan of Distribution................. 118
Registration Rights.................. 119
Certain United States Federal Income
Tax Considerations................. 121
Legal Matters........................ 124
Independent Auditors................. 124
Reserve Engineers.................... 125
Available Information................ 125
Incorporation by Reference........... 125
Glossary of Oil and Natural Gas
Terms.............................. 126
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
--------
JULY , 2001
168
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 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
II-1
169
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 Production
Company 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 , 2001.
*10.1 Form of Equity Option Plan for Directors
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
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 of Transmittal
</Table>
* To be filed by amendment
II-2
170
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 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-3
171
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Tri-Union
Development Corporation has duly caused this Registration Statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, State of Texas, on the 30th day of July, 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
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated. Each person whose signature appears below
constitutes and appoints Richard Bowman and R. Kelly Plato, and each of them
(with full power to each of them to act alone), his true and lawful
attorney-in-fact and agent, with full power of substitution and resubstitution,
for him and in his name, place and stead, in any and all capacities to sign on
his behalf individually and in each capacity stated below any amendment,
including post-effective amendments, to this Registration Statement, and to file
the same, with all exhibits thereto and other documents in connection therewith
with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents and either of them, or their substitutes, may
lawfully do or cause to be done by virtue hereof.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ RICHARD BOWMAN President, Chief Executive July 30, 2001
- ----------------------------------------------------- Officer and Director
Richard Bowman (Principal Executive Officer)
/s/ R. KELLY PLATO Vice President and Chief July 30, 2001
- ----------------------------------------------------- Financial Officer (Principal
R. Kelly Plato Financial Officer)
/s/ SUZANNE R. AMBROSE Vice President, Treasurer and July 30, 2001
- ----------------------------------------------------- Chief Accounting Officer
Suzanne R. Ambrose (Principal Accounting Officer)
</Table>
II-4
172
Pursuant to the requirements of the Securities Act of 1933, Tri-Union
Operating Company has duly caused this Registration Statement to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, State of Texas, on the 30th day of July, 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
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated. Each person whose signature appears below
constitutes and appoints Richard Bowman and R. Kelly Plato, and each of them
(with full power to each of them to act alone), his true and lawful
attorney-in-fact and agent, with full power of substitution and resubstitution,
for him and in his name, place and stead, in any and all capacities to sign on
his behalf individually and in each capacity stated below any amendment,
including post-effective amendments, to this Registration Statement, and to file
the same, with all exhibits thereto and other documents in connection therewith
with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and authority to do
and perform each and every act and thing requisite and necessary to be done in
and about the premises, as fully to all intents and purposes as he might or
could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents and either of them, or their substitutes, may
lawfully do or cause to be done by virtue hereof.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ RICHARD BOWMAN President, Chief Executive July 30, 2001
- ----------------------------------------------------- Officer and Director
Richard Bowman (Principal Executive Officer)
/s/ R. KELLY PLATO Vice President and Chief July 30, 2001
- ----------------------------------------------------- Financial Officer (Principal
R. Kelly Plato Financial Officer)
/s/ SUZANNE R. AMBROSE Vice President, Treasurer and July 30, 2001
- ----------------------------------------------------- Chief Accounting Officer
Suzanne R. Ambrose (Principal Accounting Officer)
</Table>
II-5
173
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 Production
Company 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 , 2001.
*10.1 Form of Equity Option Plan for Directors
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
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 of Transmittal
</Table>
* To be filed by amendment